U.S. patent application number 09/841298 was filed with the patent office on 2002-03-28 for in situ thermal processing of a coal formation to produce a mixture of olefins, oxygenated hydrocarbons, and aromatic hydrocarbons.
Invention is credited to de Rouffignac, Eric Pierre, Vinegar, Harold J., Wellington, Scott Lee, Zhang, Etuan.
Application Number | 20020038069 09/841298 |
Document ID | / |
Family ID | 27393994 |
Filed Date | 2002-03-28 |
United States Patent
Application |
20020038069 |
Kind Code |
A1 |
Wellington, Scott Lee ; et
al. |
March 28, 2002 |
In situ thermal processing of a coal formation to produce a mixture
of olefins, oxygenated hydrocarbons, and aromatic hydrocarbons
Abstract
A coal formation may be treated using an in situ thermal
process. A mixture of hydrocarbons, H.sub.2, and/or other formation
fluids may be produced from the formation. A portion of the mixture
may be a condensable component that includes a relatively small
amount of olefins and a relatively small amount of tri- and higher
order aromatics.
Inventors: |
Wellington, Scott Lee;
(Belliare, TX) ; Vinegar, Harold J.; (Houston,
TX) ; de Rouffignac, Eric Pierre; (Houston, TX)
; Zhang, Etuan; (Houston, TX) |
Correspondence
Address: |
DEL CHRISTENSEN
SHELL OIL COMPANY
P.O. BOX 2463
HOUSTON
TX
77252-2463
US
|
Family ID: |
27393994 |
Appl. No.: |
09/841298 |
Filed: |
April 24, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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60199213 |
Apr 24, 2000 |
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60199214 |
Apr 24, 2000 |
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60199215 |
Apr 24, 2000 |
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Current U.S.
Class: |
585/6 |
Current CPC
Class: |
Y02C 20/40 20200801;
E21B 43/2401 20130101; E21B 36/04 20130101; E21B 36/001 20130101;
C09K 8/592 20130101; Y02P 20/582 20151101; E21B 43/247 20130101;
E21B 43/24 20130101; E21B 43/243 20130101; Y10S 48/06 20130101;
E21B 41/0057 20130101; E21B 43/30 20130101; Y02C 10/14
20130101 |
Class at
Publication: |
585/943 |
International
Class: |
C10G 049/00 |
Claims
1. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least one
portion of the formation; allowing the heat to transfer from the
one or more heat sources to a selected section of the formation;
controlling the heat from the one or more heat sources such that an
average temperature within at least a majority of the selected
section of the formation is less than about 375.degree. C.; and
producing a mixture from the formation.
2. The method of claim 1, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
coal within the selected section of the formation.
3. The method of claim 1, wherein controlling formation conditions
comprises maintaining a temperature within the selected section
within a pyrolysis temperature range.
4. The method of claim 1, wherein the one or more heat sources
comprise electrical heaters.
5. The method of claim 1, wherein the one or more heat sources
comprise surface burners.
6. The method of claim 1, wherein the one or more heat sources
comprise flameless distributed combustors.
7. The method of claim 1, wherein the one or more heat sources
comprise natural distributed combustors.
8. The method of claim 1, further comprising controlling a pressure
and a temperature within at least a majority of the selected
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
9. The method of claim 1, further comprising controlling a pressure
within at least a majority of the selected section of the formation
with a valve coupled to at least one of the one or more heat
sources.
10. The method of claim 1, further comprising controlling a
pressure within at least a majority of the selected section of the
formation with a valve coupled to a production well located in the
formation.
11. The method of claim 1, further comprising controlling the heat
such that an average heating rate of the selected section is less
than about 1.degree. C. per day during pyrolysis.
12. The method of claim 1, wherein providing heat from the one or
more heat sources to at least the portion of formation comprises:
heating a selected volume (V) of the coal formation from the one or
more heat sources, wherein the formation has an average heat
capacity (C.sub.v), and wherein the heating pyrolyzes at least some
coal within the selected volume of the formation; and wherein
heating energy/day provided to the volume is equal to or less than
Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
13. The method of claim 1, wherein allowing the heat to transfer
from the one or more heat sources to the selected section comprises
transferring heat substantially by conduction.
14. The method of claim 1, wherein providing heat from the one or
more heat sources comprises heating the selected section such that
a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
15. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
16. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
17. The method of claim 1, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
18. The method of claim 1, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein about 0.1% by weight to
about 15% by weight of the non-condensable hydrocarbons are
olefins.
19. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
20 . The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
21. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
22. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
23. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
24. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
25. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
26. The method of claim 1, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
27. The method of claim 1, wherein the produced mixture comprises a
non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
28. The method of claim 1, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
29. The method of claim 1, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
30. The method of claim 1, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
31. The method of claim 1, further comprising controlling formation
conditions such that the produced mixture comprises a partial
pressure of H.sub.2 within the mixture greater than about 0.5
bar.
32. The method of claim 31, wherein the partial pressure of H.sub.2
is measured when the mixture is at a production well.
33. The method of claim 1, wherein controlling formation conditions
comprises recirculating a portion of hydrogen from the mixture into
the formation.
34. The method of claim 1, further comprising altering a pressure
within the formation to inhibit production of hydrocarbons from the
formation having carbon numbers greater than about 25.
35. The method of claim 1, further comprising: providing hydrogen
(H.sub.2) to the heated section to hydrogenate hydrocarbons within
the section; and heating a portion of the section with heat from
hydrogenation.
36. The method of claim 1, wherein the produced mixture comprises
hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
37. The method of claim 1, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
38. The method of claim 1, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
39. The method of claim 1, further comprising controlling the heat
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
40. The method of claim 1, wherein producing the mixture comprises
producing the mixture in a production well, and wherein at least
about 7 heat sources are disposed in the formation for each
production well.
41. The method of claim 1, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, and wherein the unit of heat
sources comprises a triangular pattern.
42. The method of claim 1, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
43. The method of claim 1, further comprising separating the
produced mixture into a gas stream and a liquid stream.
44. The method of claim 1, further comprising separating the
produced mixture into a gas stream and a liquid stream and
separating the liquid stream into an aqueous stream and a
non-aqueous stream.
45. The method of claim 1, wherein the produced mixture comprises
H.sub.2S, the method further comprising separating a portion of the
H.sub.2S from non-condensable hydrocarbons.
46. The method of claim 1, wherein the produced mixture comprises
CO.sub.2, the method further comprising separating a portion of the
CO.sub.2 from non-condensable hydrocarbons.
47. The method of claim 1, wherein the mixture is produced from a
production well, wherein the heating is controlled such that the
mixture can be produced from the formation as a vapor.
48. The method of claim 1, wherein the mixture is produced from a
production well, the method further comprising heating a wellbore
of the production well to inhibit condensation of the mixture
within the wellbore.
49. The method of claim 1, wherein the mixture is produced from a
production well, wherein a wellbore of the production well
comprises a heater element configured to heat the formation
adjacent to the wellbore, and further comprising heating the
formation with the heater element to produce the mixture, wherein
the mixture comprises a large non-condensable hydrocarbon gas
component and H.sub.2.
50. The method of claim 1, wherein the minimum pyrolysis
temperature is about 270.degree. C.
51. The method of claim 1, further comprising maintaining the
pressure within the formation above about 2.0 bar absolute to
inhibit production of fluids having carbon numbers above 25.
52. The method of claim 1, further comprising controlling pressure
within the formation in a range from about atmospheric pressure to
about 100 bar, as measured at a wellhead of a production well, to
control an amount of condensable hydrocarbons within the produced
mixture, wherein the pressure is reduced to increase production of
condensable hydrocarbons, and wherein the pressure is increased to
increase production of non-condensable hydrocarbons.
53. The method of claim 1, further comprising controlling pressure
within the formation in a range from about atmospheric pressure to
about 100 bar, as measured at a wellhead of a production well, to
control an API gravity of condensable hydrocarbons within the
produced mixture, wherein the pressure is reduced to decrease the
API gravity, and wherein the pressure is increased to reduce the
API gravity.
54. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from at least the
portion to a selected section of the formation substantially by
conduction of heat; pyrolyzing at least some hydrocarbons within
the selected section of the formation; and producing a mixture from
the formation.
55. The method of claim 54, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
56. The method of claim 54, wherein the one or more heat sources
comprise electrical heaters.
57. The method of claim 54, wherein the one or more heat sources
comprise surface burners.
58. The method of claim 54, wherein the one or more heat sources
comprise flameless distributed combustors.
59. The method of claim 54, wherein the one or more heat sources
comprise natural distributed combustors.
60. The method of claim 54, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
61. The method of claim 54, further comprising controlling the heat
such that an average heating rate of the selected section is less
than about 1.0.degree. C. per day during pyrolysis.
62. The method of claim 54, wherein providing heat from the one or
more heat sources to at least the portion of formation comprises:
heating a selected volume (V) of the coal formation from the one or
more heat sources, wherein the formation has an average heat
capacity (C.sub.v), and wherein the heating pyrolyzes at least some
hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
63. The method of claim 54, wherein providing heat from the one or
more heat sources comprises heating the selected section such that
a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
64. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
250.
65. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
66. The method of claim 54, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
67. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
68. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
69. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
70. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
71. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
72. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
73. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
74. The method of claim 54, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
75. The method of claim 54, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
76. The method of claim 54, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
77. The method of claim 54, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
78. The method of claim 54, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
79. The method of claim 54, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2 wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
80. The method of claim 79, wherein the partial pressure of H.sub.2
is measured when the mixture is at a production well.
81. The method of claim 54, further comprising altering a pressure
within the formation to inhibit production of hydrocarbons from the
formation having carbon numbers greater than about 25.
82. The method of claim 54, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
83. The method of claim 54, further comprising: providing hydrogen
(H.sub.2) to the heated section to hydrogenate hydrocarbons within
the section; and heating a portion of the section with heat from
hydrogenation.
84. The method of claim 54, wherein the produced mixture comprises
hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
85. The method of claim 54, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
86. The method of claim 54, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
87. The method of claim 54, further comprising controlling the heat
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
88. The method of claim 54, wherein producing the mixture comprises
producing the mixture in a production well, and wherein at least
about 7 heat sources are disposed in the formation for each
production well.
89. The method of claim 54, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, and wherein the unit of heat
sources comprises a triangular pattern.
90. The method of claim 54, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
91. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
heating the selected section such that a thermal conductivity of at
least a portion of the selected section is greater than about 0.5
W/(m.degree. C.).
92. The method of claim 91, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
93. The method of claim 91, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
94. The method of claim 91, wherein the one or more heat sources
comprise electrical heaters.
95. The method of claim 91, wherein the one or more heat sources
comprise surface burners.
96. The method of claim 91, wherein the one or more heat sources
comprise flameless distributed combustors.
97. The method of claim 91, wherein the one or more heat sources
comprise natural distributed combustors.
98. The method of claim 91, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
99. The method of claim 91, further comprising controlling the heat
such that an average heating rate of the selected section is less
than about 1.degree. C. per day during pyrolysis.
100. The method of claim 91, wherein providing heat from the one or
more heat sources to at least the portion of formation comprises:
heating a selected volume (V) of the coal formation from the one or
more heat sources, wherein the formation has an average heat
capacity (C.sub.v), and wherein the heating pyrolyzes at least some
hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
101. The method of claim 91, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
102. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
103. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
104. The method of claim 91, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
105. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
106. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
107. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
108. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
109. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
110. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
111. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
112. The method of claim 91, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
113. The method of claim 91, wherein the produced mixture comprises
a-non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
114. The method of claim 91, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
115. The method of claim 91, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
116. The method of claim 91, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
117. The method of claim 91, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
118. The method of claim 117, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
119. The method of claim 91, further comprising altering a pressure
within the formation to inhibit production of hydrocarbons from the
formation having carbon numbers greater than about 25.
120. The method of claim 91, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
121. The method of claim 91, further comprising: providing hydrogen
(H.sub.2) to the heated section to hydrogenate hydrocarbons within
the section; and heating a portion of the section with heat from
hydrogenation.
122. The method of claim 91, wherein the produced mixture comprises
hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
123. The method of claim 91, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
124. The method of claim 91, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
125. The method of claim 91, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
126. The method of claim 91, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
127. The method of claim 91, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, and wherein the unit of heat
sources comprises a triangular pattern.
128. The method of claim 91, further comprising providing heat from
three or more heat sources to at least a portion of the formation,
wherein three or more of the heat sources are located in the
formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
129. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
controlling the heat from the one or more heat sources such that an
average temperature within at least a majority of the selected
section of the formation is less than about 370.degree. C. such
that production of a substantial amount of hydrocarbons having
carbon numbers greater than 25 is inhibited; controlling a pressure
within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least 2.0 bar; and
producing a mixture from the formation, wherein about 0.1% by
weight of the produced mixture to about 15% by weight of the
produced mixture are olefins, and wherein an average carbon number
of the produced mixture ranges from 1-25.
130. The method of claim 129, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
131. The method of claim 129, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
132. The method of claim 129, wherein the one or more heat sources
comprise electrical heaters.
133. The method of claim 129, wherein the one or more heat sources
comprise surface burners.
134. The method of claim 129, wherein the one or more heat sources
comprise flameless distributed combustors.
135. The method of claim 129, wherein the one or more heat sources
comprise natural distributed combustors.
136. The method of claim 129, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
137. The method of claim 129, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
138. The method of claim 129, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
139. The method of claim 129, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
140. The method of claim 129, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
141. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
142. The method of claim 129, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
143. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
144. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
145. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
146. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
147. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
148. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
149. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
150. The method of claim 129, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
151. The method of claim 129, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
152. The method of claim 129, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
153. The method of claim 129, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
154. The method of claim 129, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
155. The method of claim 154, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
156. The method of claim 129, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
157. The method of claim 129, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
158. The method of claim 129, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
159. The method of claim 129, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
160. The method of claim 129, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
161. The method of claim 129, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
162. The method of claim 129, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
163. The method of claim 129, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
164. The method of claim 129, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
165. The method of claim 129, further comprising separating the
produced mixture into a gas stream and a liquid stream.
166. The method of claim 129, further comprising separating the
produced mixture into a gas stream and a liquid stream and
separating the liquid stream into an aqueous stream and a
non-aqueous stream.
167. The method of claim 129, wherein the produced mixture
comprises H.sub.2S, the method further comprising separating a
portion of the H.sub.2S from non-condensable hydrocarbons.
168. The method of claim 129, wherein the produced mixture
comprises CO.sub.2, the method further comprising separating a
portion of the CO.sub.2 from non-condensable hydrocarbons.
169. The method of claim 129, wherein the mixture is produced from
a production well, wherein the heating is controlled such that the
mixture can be produced from the formation as a vapor.
170. The method of claim 129, wherein the mixture is produced from
a production well, the method further comprising heating a wellbore
of the production well to inhibit condensation of the mixture
within the wellbore.
171. The method of claim 129, wherein the mixture is produced from
a production well, wherein a wellbore of the production well
comprises a heater element configured to heat the formation
adjacent to the wellbore, and further comprising heating the
formation with the heater element to produce the mixture, wherein
the produced mixture comprise a large non-condensable hydrocarbon
gas component and H.sub.2.
172. The method of claim 129, wherein the minimum pyrolysis
temperature is about 270.degree. C.
173. The method of claim 129, further comprising maintaining the
pressure within the formation above about 2.0 bar absolute to
inhibit production of fluids having carbon numbers above 25.
174. The method of claim 129, further comprising controlling
pressure within the formation in a range from about atmospheric
pressure to about 100 bar absolute, as measured at a wellhead of a
production well, to control an amount of condensable fluids within
the produced mixture, wherein the pressure is reduced to increase
production of condensable fluids, and wherein the pressure is
increased to increase production of non-condensable fluids.
175. The method of claim 129, further comprising controlling
pressure within the formation in a range from about atmospheric
pressure to about 100 bar absolute, as measured at a wellhead of a
production well, to control an API gravity of condensable fluids
within the produced mixture, wherein the pressure is reduced to
decrease the API gravity, and wherein the pressure is increased to
reduce the API gravity.
176. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
controlling a pressure within at least a majority of the selected
section of the formation, wherein the controlled pressure is at
least about 2.0 bar absolute; and producing a mixture from the
formation.
177. The method of claim 176, wherein controlling the pressure
comprises controlling the pressure with a valve coupled to at least
one of the one or more heat sources.
178. The method of claim 176, wherein controlling the pressure
comprises controlling the pressure with a valve coupled to a
production well located in the formation.
179. The method of claim 176, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
180. The method of claim 176, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
181. The method of claim 176, wherein the one or more heat sources
comprise electrical heaters.
182. The method of claim 176, wherein the one or more heat sources
comprise surface burners.
183. The method of claim 176, wherein the one or more heat sources
comprise flameless distributed combustors.
184. The method of claim 176, wherein the one or more heat sources
comprise natural distributed combustors.
185. The method of claim 176, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
186. The method of claim 176, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
187. The method of claim 176, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
188. The method of claim 176, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
189. The method of claim 176, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
190. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
191. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
192. The method of claim 176, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
193. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
194. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
195. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
196. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
197. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
198. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
199. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
200. The method of claim 176, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
201. The method of claim 176, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
202. The method of claim 176, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
203. The method of claim 176, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
204. The method of claim 176, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2 wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
205. The method of claim 204, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
206. The method of claim 176, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
207. The method of claim 176, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
208. The method of claim 176, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
209. The method of claim 176, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
210. The method of claim 176, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
211. The method of claim 176, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
212. The method of claim 176, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
213. The method of claim 176, wherein producing the mixture from
the formation comprises producing the mixture in a production well,
and wherein at least about 7 heat sources are disposed in the
formation for each production well.
214. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
controlling a pressure within at least a majority of the selected
section of the formation, wherein the controlled pressure is at
least about 2.0 bar absolute; controlling the heat from the one or
more heat sources such that an average temperature within at least
a majority of the selected section of the formation is less than
about 375.degree. C.; and producing a mixture from the
formation.
215. The method of claim 214, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
216. The method of claim 214, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
217. The method of claim 214, wherein the one or more heat sources
comprise electrical heaters.
218. The method of claim 214, wherein the one or more heat sources
comprise surface burners.
219. The method of claim 214, wherein the one or more heat sources
comprise flameless distributed combustors.
220. The method of claim 214, wherein the one or more heat sources
comprise natural distributed combustors.
221. The method of claim 214, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
222. The method of claim 214, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
223. The method of claim 214, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
224. The method of claim 214, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
225. The method of claim 214, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
226. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
227. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
228. The method of claim 214, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
229. The method of claim 214, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
230. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
231. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
232. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
233. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
234. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
235. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
236. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
237. The method of claim 214, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
238. The method of claim 214, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
239. The method of claim 214, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
240. The method of claim 214, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
241. The method of claim 214, wherein controlling the heat further
comprises controlling the heat such that coke production is
inhibited.
242. The method of claim 214, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
243. The method of claim 242, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
244. The method of claim 214, further comprising altering the
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
245. The method of claim 214, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
246. The method of claim 214, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
247. The method of claim 214, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
248. The method of claim 214, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
249. The method of claim 214, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
250. The method of claim 214, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
251. The method of claim 214, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
252. The method of claim 214, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
253. The method of claim 214, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
254. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; producing
a mixture from the formation, wherein at least a portion of the
mixture is produced during the pyrolysis and the mixture moves
through the formation in a vapor phase; and maintaining a pressure
within at least a majority of the selected section above about 2.0
bar absolute.
255. The method of claim 254, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
256. The method of claim 254, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
257. The method of claim 254, wherein the one or more heat sources
comprise electrical heaters.
258. The method of claim 254, wherein the one or more heat sources
comprise surface burners.
259. The method of claim 254, wherein the one or more heat sources
comprise flameless distributed combustors.
260. The method of claim 254, wherein the one or more heat sources
comprise natural distributed combustors.
261. The method of claim 254, further comprising controlling the
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
262. The method of claim 254, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
263. The method of claim 254, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
264. The method of claim 254, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
265. The method of claim 254, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
266. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
267. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
268. The method of claim 254, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
269. The method of claim 254, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
270. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
271. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
272. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
273. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
274. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
275. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
276. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
277. The method of claim 254, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
278. The method of claim 254, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
279. The method of claim 254, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
280. The method of claim 254, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
281. The method of claim 254, wherein the pressure is measured at a
wellhead of a production well.
282. The method of claim 254, wherein the pressure is measured at a
location within a wellbore of the production well.
283. The method of claim 254, wherein the pressure is maintained
below about 100 bar absolute.
284. The method of claim 254, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
285. The method of claim 284, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
286. The method of claim 254, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
287. The method of claim 254, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
288. The method of claim 254, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
289. The method of claim 254, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
290. The method of claim 254, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
291. The method of claim 254, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
292. The method of claim 254, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
293. The method of claim 254, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
294. The method of claim 254, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
295. The method of claim 254, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
296. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
maintaining a pressure within at least a majority of the selected
section of the formation above 2.0 bar absolute; and producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity higher than an API
gravity of condensable hydrocarbons in a mixture producible from
the formation at the same temperature and at atmospheric
pressure.
297. The method of claim 296, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
298. The method of claim 296, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
299. The method of claim 296, wherein the one or more heat sources
comprise electrical heaters.
300. The method of claim 296, wherein the one or more heat sources
comprise surface burners.
301. The method of claim 296, wherein the one or more heat sources
comprise flameless distributed combustors.
302. The method of claim 296, wherein the one or more heat sources
comprise natural distributed combustors.
303. The method of claim 296, further comprising controlling the
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
304. The method of claim 296, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
305. The method of claim 296, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
306. The method of claim 296, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
307. The method of claim 296, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
308. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
309. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
310. The method of claim 296, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0. 1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
311. The method of claim 296, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
312. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
313. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
314. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
315. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
316. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
317. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
318. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
319. The method of claim 296, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
320. The method of claim 296, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
321. The method of claim 296, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
322. The method of claim 296, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
323. The method of claim 296, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
324. The method of claim 296, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
325. The method of claim 296, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
326. The method of claim 296, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
327. The method of claim 296, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
328. The method of claim 296, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
329. The method of claim 296, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
330. The method of claim 296, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
331. The method of claim 296, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
332. The method of claim 296, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
333. The method of claim 296, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
334. The method of claim 296, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
335. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
maintaining a pressure within at least a majority of the selected
section of the formation to above 2.0 bar absolute; and producing a
fluid from the formation, wherein condensable hydrocarbons within
the fluid comprise an atomic hydrogen to atomic carbon ratio of
greater than about 1.75.
336. The method of claim 335, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
337. The method of claim 335, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
338. The method of claim 335, wherein the one or more heat sources
comprise electrical heaters.
339. The method of claim 335, wherein the one or more heat sources
comprise surface burners.
340. The method of claim 335, wherein the one or more heat sources
comprise flameless distributed combustors.
341. The method of claim 335, wherein the one or more heat sources
comprise natural distributed combustors.
342. The method of claim 335, further comprising controlling the
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
343. The method of claim 335, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
344. The method of claim 335, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (y) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
345. The method of claim 335, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
346. The method of claim 335, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
347. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
348. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
349. The method of claim 335, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
350. The method of claim 335, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
351. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
352. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
353. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
354. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
355. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
356. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
357. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
358. The method of claim 335, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
359. The method of claim 335, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater-than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
360. The method of claim 335, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
361. The method of claim 335, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
362. The method of claim 335, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
363. The method of claim 335, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
364. The method of claim 335, further comprising altering the
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
365. The method of claim 335, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
366. The method of claim 335, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
367. The method of claim 335, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
368. The method of claim 335, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
369. The method of claim 335, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
370. The method of claim 335, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
371. The method of claim 335, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
372. The method of claim 335, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
373. The method of claim 335, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
374. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
maintaining a pressure within at least a majority of the selected
section of the formation to above 2.0 bar absolute; and producing a
mixture from the formation, wherein the produced mixture comprises
a higher amount of non-condensable components as compared to
non-condensable components producible from the formation under the
same temperature conditions and at atmospheric pressure.
375. The method of claim 374, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
376. The method of claim 374, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
377. The method of claim 374, wherein the one or more heat sources
comprise electrical heaters.
378. The method of claim 374, wherein the one or more heat sources
comprise surface burners.
379. The method of claim 374, wherein the one or more heat sources
comprise flameless distributed combustors.
380. The method of claim 374, wherein the one or more heat sources
comprise natural distributed combustors.
381. The method of claim 374, further comprising controlling the
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
382. The method of claim 374, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
383. The method of claim 374, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
384. The method of claim 374, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
385. The method of claim 374, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
386. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 250.
387. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
388. The method of claim 374, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
389. The method of claim 374, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
390. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
391. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
392. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
393. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
394. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
395. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
396. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
397. The method of claim 374, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
398. The method of claim 374, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
399. The method of claim 374, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
400. The method of claim 374, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
401. The method of claim 374, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
402. The method of claim 374, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
403. The method of claim 374, further comprising altering the
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
404. The method of claim 374, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
405. The method of claim 374, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
406. The method of claim 374, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
407. The method of claim 374, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
408. The method of claim 374, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
409. The method of claim 374, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
410. The method of claim 374, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
411. The method of claim 374, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
412. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
superimposed heat from the one or more heat sources pyrolyzes at
least about 20% by weight of hydrocarbons within the selected
section of the formation; and producing a mixture from the
formation.
413. The method of claim 412, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
414. The method of claim 412, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
415. The method of claim 412, wherein the one or more heat sources
comprise electrical heaters.
416. The method of claim 412, wherein the one or more heat sources
comprise surface burners.
417. The method of claim 412, wherein the one or more heat sources
comprise flameless distributed combustors.
418. The method of claim 412, wherein the one or more heat sources
comprise natural distributed combustors.
419. The method of claim 412, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
420. The method of claim 412, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
421. The method of claim 412, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
422. The method of claim 412, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
423. The method of claim 412, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
424. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
425. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
426. The method of claim 412, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
427. The method of claim 412, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
428. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
429. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
430. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
431. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
432. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
433. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
434. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
435. The method of claim 412, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
436. The method of claim 412, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
437. The method of claim 412, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
438. The method of claim 412, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
439. The method of claim 412, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
440. The method of claim 412, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
441. The method of claim 412, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
442. The method of claim 412, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
443. The method of claim 412, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
444. The method of claim 412, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
445. The method of claim 412, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
446. The method of claim 412, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
447. The method of claim 412, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
448. The method of claim 412, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
449. The method of claim 412, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
450. The method of claim 412, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
451. The method of claim 412, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
452. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
superimposed heat from the one or more heat sources pyrolyzes at
least about 20% of hydrocarbons within the selected section of the
formation; and producing a mixture from the formation, wherein the
mixture comprises a condensable component having an API gravity of
at least about 25.degree..
453. The method of claim 452, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
454. The method of claim 452, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
455. The method of claim 452, wherein the one or more heat sources
comprise electrical heaters.
456. The method of claim 452, wherein the one or more heat sources
comprise surface burners.
457. The method of claim 452, wherein the one or more heat sources
comprise flameless distributed combustors.
458. The method of claim 452, wherein the one or more heat sources
comprise natural distributed combustors.
459. The method of claim 452, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
460. The method of claim 452, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
461. The method of claim 452, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
462. The method of claim 452, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
463. The method of claim 452, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
464. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
465. The method of claim 452, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
466. The method of claim 452, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
467. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
468. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
469. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
470. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
471. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
472. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
473. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
474. The method of claim 452, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
475. The method of claim 452, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
476. The method of claim 452, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
477. The method of claim 452, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
478. The method of claim 452, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
479. The method of claim 452, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
480. The method of claim 452, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
481. The method of claim 452, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
482. The method of claim 452, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
483. The method of claim 452, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
484. The method of claim 452, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
485. The method of claim 452, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
486. The method of claim 452, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
487. The method of claim 452, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
488. The method of claim 452, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
489. The method of claim 452, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
490. The method of claim 452, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
491. A method of treating a layer of a coal formation in situ,
comprising: providing heat from one or more heat sources to at
least a portion of the layer, wherein the one or more heat sources
are positioned proximate an edge of the layer; allowing the heat to
transfer from the one or more heat sources to a selected section of
the layer such that superimposed heat from the one or more heat
sources pyrolyzes at least some hydrocarbons within the selected
section of the formation; and producing a mixture from the
formation.
492. The method of claim 491, wherein the one or more heat sources
are laterally spaced from a center of the layer.
493. The method of claim 491, wherein the one or more heat sources
are positioned in a staggered line.
494. The method of claim 491, wherein the one or more heat sources
positioned proximate the edge of the layer can increase an amount
of hydrocarbons produced per unit of energy input to the one or
more heat sources.
495. The method of claim 491, wherein the one or more heat sources
positioned proximate the edge of the layer can increase the volume
of formation undergoing pyrolysis per unit of energy input to the
one or more heat sources.
496. The method of claim 491, wherein the one or more heat sources
comprise electrical heaters.
497. The method of claim 491, wherein the one or more heat sources
comprise surface burners.
498. The method of claim 491, wherein the one or more heat sources
comprise flameless distributed combustors.
499. The method of claim 491, wherein the one or more heat sources
comprise natural distributed combustors.
500. The method of claim 491, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
501. The method of claim 491, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.0.degree. C. per day during pyrolysis.
502. The method of claim 491, wherein providing heat from the one
or more heat sources to at least the portion of the layer
comprises: heating a selected volume (Y) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
503. The method of claim 491, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
504. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
505. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
506. The method of claim 491, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
507. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
508. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
509. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
510. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
511. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
512. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
513. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
514. The method of claim 491, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
515. The method of claim 491, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
516. The method of claim 491, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
517. The method of claim 491, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
518. The method of claim 491, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
519. The method of claim 491, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
520. The method of claim 519, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
521. The method of claim 491, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
522. The method of claim 491, further comprising controlling
formation conditions, wherein controlling formation conditions
comprises recirculating a portion of hydrogen from the mixture into
the formation.
523. The method of claim 491, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
524. The method of claim 491, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
525. The method of claim 491, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
526. The method of claim 491, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
527. The method of claim 491, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
528. The method of claim 491, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
529. The method of claim 491, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
530. The method of claim 491, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
531. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
controlling a pressure and a temperature within at least a majority
of the selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure; and producing a mixture from
the formation.
532. The method of claim 531, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
533. The method of claim 531, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
534. The method of claim 531, wherein the one or more heat sources
comprise electrical heaters.
535. The method of claim 531, wherein the one or more heat sources
comprise surface burners.
536. The method of claim 531, wherein the one or more heat sources
comprise Blameless distributed combustors.
537. The method of claim 531, wherein the one or more heat sources
comprise natural distributed combustors.
538. The method of claim 531, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
539. The method of claim 531, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
540. The method of claim 531, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
541. The method of claim 531, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
542. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
543. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
544. The method of claim 531, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.11% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
545. The method of claim 531, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons range s
from about 0.001 to about 0.15.
546. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
547. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
548. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic, basis, of the condensable
hydrocarbons is sulfur.
549. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
550. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
551. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
552. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
553. The method of claim 531, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
554. The method of claim 531, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
555. The method of claim 531, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
556. The method of claim 531, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
557. The method of claim 531, wherein the controlled pressure is at
least about 2.0 bar absolute.
558. The method of claim 531, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
559. The method of claim 531, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
560. The method of claim 531, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
561. The method of claim 531, where in controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
562. The method of claim 531, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
563. The method of claim 531, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
564. The method of claim 531, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
565. The method of claim 531, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
566. The method of claim 531, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
567. The method of claim 531, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
568. The method of claim 531, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
569. The method of claim 531, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
570. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation to raise
an average temperature within the selected section to, or above, a
temperature that will pyrolyze hydrocarbons within the selected
section; producing a mixture from the formation; and controlling
API gravity of the produced mixture to be greater than about 25
degrees API by controlling average pressure and average temperature
in the selected section such that the average pressure in the
selected section is greater than the pressure (p) set forth in the
following equation for an assessed average temperature (1) in the
selected section: p=e.sup.[-44000/T+67]where p is measured in psia
and T is measured in .degree. Kelvin.
571. The method of claim 570, wherein the API gravity of the
produced mixture is controlled to be greater than about 30 degrees
API, and wherein the equation is: p=e.sup.[-31000/T+51].
572. The method of claim 570, wherein the API gravity of the
produced mixture is controlled to be greater than about 35 degrees
API, and wherein the equation is: p=e.sup.[-22000/T+38].
573. The method of claim 570, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
574. The method of claim 570, wherein controlling the average
temperature comprises maintaining a temperature in the selected
section within a pyrolysis temperature range.
575. The method of claim 570, wherein the one or more heat sources
comprise electrical heaters.
576. The method of claim 570, wherein the one or more heat sources
comprise surface burners.
577. The method of claim 570, wherein the one or more heat sources
comprise flameless distributed combustors.
578. The method of claim 570, wherein the one or more heat sources
comprise natural distributed combustors.
579. The method of claim 570, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
580. The method of claim 570, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
581. The method of claim 570, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr., wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
582. The method of claim 570, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
583. The method of claim 570, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
584. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
585. The method of claim 570, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
586. The method of claim 570, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
587. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
588. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
589. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
590. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
591. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
592. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
593. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
594. The method of claim 570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
595. The method of claim 570, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
596. The method of claim 570, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
597. The method of claim 570, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
598. The method of claim 570, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
599. The method of claim 570, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
600. The method of claim 570, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
601. The method of claim 570, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
602. The method of claim 570, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
603. The method of claim 570, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
604. The method of claim 570, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
605. The method of claim 570, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
606. The method of claim 570, wherein the heat is controlled to
yield greater than about 60% by weight of condensable hydrocarbons,
as measured by Fischer Assay.
607. The method of claim 570, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
608. The method of claim 570, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
609. The method of claim 570, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
610. A method of treating a coal formation in situ, comprising:
providing heat to at least a portion of a coal formation such that
a temperature (T) in a substantial part of the heated portion
exceeds 270.degree. C. and hydrocarbons are pyrolyzed within the
heated portion of the formation; controlling a pressure (p) within
at least a substantial part of the heated portion of the formation;
wherein p.sub.bar>e.sup.[(-A/T- )+B-2.6744]; wherein p is the
pressure in bar absolute and T is the temperature in degrees K, and
A and B are parameters that are larger than 10 and are selected in
relation to the characteristics and composition of the coal
formation and on the required olefin content and carbon number of
the pyrolyzed hydrocarbon fluids; and producing pyrolyzed
hydrocarbon fluids from the heated portion of the formation.
611. The method of claim 610, wherein A is greater than 14000 and B
is greater than about 25 and a majority of the produced pyrolyzed
hydrocarbon fluids have an average carbon number lower than 25 and
comprise less than about 10% by weight of olefins.
612. The method of claim 610, wherein T is less than about
390.degree. C., p is greater than about 1.4 bar, A is greater than
about 44000, and b is greater than about 67, and a majority of the
produced pyrolyzed hydrocarbon fluids have an average carbon number
less than 25 and comprise less than 10% by weight of olefins.
613. The method of claim 610, wherein T is less than about
390.degree. C., p is greater than about 2 bar, A is less than about
57000, and b is less than about 83, and a majority of the produced
pyrolyzed hydrocarbon fluids have an average carbon number lower
than about 21.
614. The method of claim 610, further comprising controlling the
heat such that an average heating rate of the heated portion is
less than about 3.degree. C. per day during pyrolysis.
615. The method of claim 610, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
616. The method of claim 610, wherein heat is transferred
substantially by conduction from one or more heat sources located
in one or more heat sources to the heated portion of the
formation.
617. The method of claim 616, wherein the heat sources comprise
heaters in which hydrocarbons are either injected into a heaters or
released by the coal formation adjacent to a heater by an oxidant
injected into the heater in or adjacent to which the combustion
occurs and wherein at least part of the produced combustion gases
are vented to surface via the heater in which the combustion
occurs.
618. The method of claim 617, wherein heat is transferred
substantially by conduction from one or more heat sources to the
heated portion of the formation such that the thermal conductivity
of at least part of the heated portion is substantially uniformly
modified to a value greater than about 0.6 W/m.degree. C. and the
permeability of said part increases substantially uniformly to a
value greater than 1 Darcy.
619. The method of claim 610, further comprising controlling
formation conditions to produce a mixture of hydrocarbon fluids and
H.sub.2, wherein a partial pressure of H.sub.2 within the mixture
flowing through the formation is greater than 0.5 Bar.
620. The method of claim 619, further comprising, hydrogenating a
portion of the produced pyrolyzed hydrocarbon fluids with at least
a portion of the produced hydrogen and heating the fluids with heat
from hydrogenation.
621. The method of claim 610, wherein the coal formation is a coal
seam and at least about 70% of the hydrocarbon content of the coal,
when such hydrocarbon content is measured by a Fischer assay, is
produced from the heated portion of the formation.
622. The method of claim 610, wherein the substantially gaseous
pyrolyzed hydrocarbon fluids are produced from a production well,
the method further comprising heating a wellbore of the production
well to inhibit condensation of the hydrocarbon fluids within the
wellbore.
623. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation to raise
an average temperature within the selected section to, or above, a
temperature that will pyrolyze hydrocarbons within the selected
section; producing a mixture from the formation; and controlling a
weight percentage of olefins of the produced mixture to be less
than about 20% by weight by controlling average pressure and
average temperature in the selected section such that the average
pressure in the selected section is greater than the pressure (p)
set forth in the following equation for an assessed average
temperature (T) in the selected section: p=e.sup.[-57000/T+83]whe-
re p is measured in psia and T is measured in .degree. Kelvin.
624. The method of claim 623, wherein the weight percentage of
olefins of the produced mixture is controlled to be less than about
10% by weight, and wherein the equation is:
p=e.sup.[-16000/T+28].
625. The method of claim 623, wherein the weight percentage of
olefins of the produced mixture is controlled to be less than about
5% by weight, and wherein the equation is:
p=e.sup.[-12000/T+22].
626. The method of claim 623, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
627. The method of claim 623, wherein the one or more heat sources
comprise electrical heaters.
628. The method of claim 623, wherein the one or more heat sources
comprise surface burners.
629. The method of claim 623, wherein the one or more heat sources
comprise flameless distributed combustors.
630. The method of claim 623, wherein the one or more heat sources
comprise natural distributed combustors.
631. The method of claim 623, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
632. The method of claim 631, wherein controlling an average
temperature comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
633. The method of claim 623, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 3.0.degree. C. per day during pyrolysis.
634. The method of claim 623, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
635. The method of claim 623, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
636. The method of claim 623, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
637. The method of claim 623, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
638. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
639. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
640. The method of claim 623, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
641. The method of claim 623, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
642. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
643. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
644. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
645. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
646. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
647. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
648. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
649. The method of claim 623, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
650. The method of claim 623, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
651. The method of claim 623, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
652. The method of claim 623, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
653. The method of claim 623, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
654. The method of claim 623, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
655. The method of claim 623, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
656. The method of claim 623, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
657. The method of claim 623, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
658. The method of claim 623, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
659. The method of claim 623, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
660. The method of claim 623, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
661. The method of claim 623, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
662. The method of claim 623, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
663. The method of claim 623, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
664. The method of claim 623, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
665. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation to raise
an average temperature within the selected section to, or above, a
temperature that will pyrolyze hydrocarbons within the selected
section; producing a mixture from the formation; and controlling
hydrocarbons having carbon numbers greater than 25 of the produced
mixture to be less than about 25% by weight by controlling average
pressure and average temperature in the selected section such that
the average pressure in the selected section is greater than the
pressure (p) set forth in the following equation for an assessed
average temperature (T) in the selected section:
p=e.sup.[-14000/T+25]where p is measured in psia and T is measured
in .degree. Kelvin.
666. The method of claim 665, wherein the hydrocarbons having
carbon numbers greater than 25 of the produced mixture is
controlled to be less than about 20% by weight, and wherein the
equation is: p=e.sup.[-16000/T+28].
667. The method of claim 665, wherein the hydrocarbons having
carbon numbers greater than 25 of the produced mixture is
controlled to be less than about 15% by weight, and wherein the
equation is: p=e.sup.[-18000/T+32].
668. The method of claim 665, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
669. The method of claim 665, wherein the one or more heat sources
comprise electrical heaters.
670. The method of claim 665, wherein the one or more heat sources
comprise surface burners.
671. The method of claim 665, wherein the one or more heat sources
comprise flameless distributed combustors.
672. The method of claim 665, wherein the one or more heat sources
comprise natural distributed combustors.
673. The method of claim 665, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
674. The method of claim 673, wherein controlling the temperature
comprises maintaining a temperature within the selected section
within a pyrolysis temperature range.
675. The method of claim 665, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
676. The method of claim 665, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
677. The method of claim 665, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
678. The method of claim 665, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
679. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
680. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
681. The method of claim 665, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
682. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
683. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
684. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
685. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
686. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
687. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
688. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
689. The method of claim 665, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
690. The method of claim 665, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
691. The method of claim 665, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
692. The method of claim 665, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
693. The method of claim 665, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
694. The method of claim 665, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
695. The method of claim 665, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
696. The method of claim 665, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
697. The method of claim 665, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
698. The method of claim 665, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
699. The method of claim 665, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
700. The method of claim 665, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
701. The method of claim 665, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
702. The method of claim 665, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
703. The method of claim 665, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
704. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation to raise
an average temperature within the selected section to, or above, a
temperature that will pyrolyze hydrocarbons within the selected
section; producing a mixture from the formation; and controlling an
atomic hydrogen to carbon ratio of the produced mixture to be
greater than about 1.7 by controlling average pressure and average
temperature in the selected section such that the average pressure
in the selected section is greater than the pressure (p) set forth
in the following equation for an assessed average temperature (T)
in the selected section: p=e.sup.[-38000/T+61]where p is measured
in psia and T is measured in .degree. Kelvin.
705. The method of claim 704, wherein the atomic hydrogen to carbon
ratio of the produced mixture is controlled to be greater than
about 1.8, and wherein the equation is: p=e.sup.[-13000/T+24].
706. The method of claim 704, wherein the atomic hydrogen to carbon
ratio of the produced mixture is controlled to be greater than
about 1.9, and wherein the equation is: p=e.sup.[-8000/T+18].
707. The method of claim 704, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
708. The method of claim 704, wherein the one or more heat sources
comprise electrical heaters.
709. The method of claim 704, wherein the one or more heat sources
comprise surface burners.
710. The method of claim 704, wherein the one or more heat sources
comprise flameless distributed combustors.
711. The method of claim 704, wherein the one or more heat sources
comprise natural distributed combustors.
712. The method of claim 704, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
713. The method of claim 712, wherein controlling the temperature
comprises maintaining a temperature within the selected section
within a pyrolysis temperature range.
714. The method of claim 704, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
715. The method of claim 704, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
716. The method of claim 704, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
717. The method of claim 704, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
718. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
719. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
720. The method of claim 704, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
721. The method of claim 704, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
722. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
723. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
724. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
725. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
726. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
727. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
728. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
729. The method of claim 704, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
730. The method of claim 704, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
731. The method of claim 704, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
732. The method of claim 704, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
733. The method of claim 704, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2 wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
734. The method of claim 704, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
735. The method of claim 704, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
736. The method of claim 704, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
737. The method of claim 704, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
738. The method of claim 704, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
739. The method of claim 704, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
740. The method of claim 704, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
741. The method of claim 704, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
742. The method of claim 704, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
743. The method of claim 704, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
744. The method of claim 704, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
745. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least one
portion of the formation; allowing the heat to transfer from the
one or more heat sources to a selected section of the formation;
controlling a pressure-temperature relationship within at least the
selected section of the formation by selected energy input into the
one or more heat sources and by pressure release from the selected
section through wellbores of the one or more heat sources; and
producing a mixture from the formation.
746. The method of claim 745, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
747. The method of claim 745, wherein the one or more heat sources
comprise at least two heat sources.
748. The method of claim 745, wherein the one or more heat sources
comprise surface burners.
749. The method of claim 745, wherein the one or more heat sources
comprise flameless distributed combustors.
750. The method of claim 745, wherein the one or more heat sources
comprise natural distributed combustors.
751. The method of claim 745, further comprising controlling the
pressure-temperature relationship by controlling a rate of removal
of fluid from the formation.
752. The method of claim 745, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
753. The method of claim 745, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
754. The method of claim 745, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
755. The method of claim 745, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
756. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
757. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
758. The method of claim 745, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
759. The method of claim 745, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
760. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
761. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
762. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
763. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
764. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
765. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
766. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
767. The method of claim 745, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
768. The method of claim 745, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
769. The method of claim 745, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
770. The method of claim 745, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
771. The method of claim 745, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
772. The method of claim 745, further comprising controlling
formation conditions to produce a mixture of hydrocarbon fluids and
H.sub.2, wherein the partial pressure of H.sub.2 within the mixture
is greater than about 0.5 bar.
773. The method of claim 745, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
774. The method of claim 745, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
775. The method of claim 745, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
776. The method of claim 745, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
777. The method of claim 745, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
778. The method of claim 745, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
779. The method of claim 745, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
780. The method of claim 745, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
781. The method of claim 745, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
782. The method of claim 745, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
783. The method of claim 745, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
784. The method of claim 745, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
785. A method of treating a coal formation in situ, comprising:
heating a selected volume (V) of the coal formation, wherein
formation has an average heat capacity (C.sub.v), and wherein the
heating pyrolyzes at least some hydrocarbons within the selected
volume of the formation; and wherein heating energy/day provided to
the volume is equal to or less than Pwr, wherein Pwr is calculated
by the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
786. The method of claim 785, wherein heating a selected volume
comprises heating with an electrical heater.
787. The method of claim 785, wherein heating a selected volume
comprises heating with a surface burner.
788. The method of claim 785, wherein heating a selected volume
comprises heating with a flameless distributed combustor.
789. The method of claim 785, wherein heating a selected volume
comprises heating with a natural distributed combustors.
790. The method of claim 785, further comprising controlling a
pressure and a temperature within at least a majority of the
selected volume of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
791. The method of claim 785, further comprising controlling the
heating such that an average heating rate of the selected volume is
less than about 1.degree. C. per day during pyrolysis.
792. The method of claim 785, wherein a value for C.sub.v is
determined as an average heat capacity of two or more samples taken
from the coal formation.
793. The method of claim 785, wherein heating the selected volume
comprises transferring heat substantially by conduction.
794. The method of claim 785, wherein heating the selected volume
comprises heating the selected section such that a thermal
conductivity of at least a portion of the selected section is
greater than about 0.5 W/(m.degree. C.).
795. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
796. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
797. The method of claim 785, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
798. The method of claim 785, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
799. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
800. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
801. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
802. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
803. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
804. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
805. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
806. The method of claim 785, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
807. The method of claim 785, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
808. The method of claim 785, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
809. The method of claim 785, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer
810. The method of claim 785, further comprising controlling a
pressure within at least a majority of the selected volume of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
811. The method of claim 785, further comprising controlling
formation conditions to produce a mixture from the formation
comprising condensable hydrocarbons and H.sub.2, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
812. The method of claim 785, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
813. The method of claim 785, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
814. The method of claim 785, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
815. The method of claim 785, further comprising: providing
hydrogen (H.sub.2) to the heated volume to hydrogenate hydrocarbons
within the volume; and heating a portion of the volume with heat
from hydrogenation.
816. The method of claim 785, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
817. The method of claim 785, further comprising increasing a
permeability of a majority of the selected volume to greater than
about 100 millidarcy.
818. The method of claim 785, further comprising substantially
uniformly increasing a permeability of a majority of the selected
volume.
819. The method of claim 785, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
820. The method of claim 785, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
821. The method of claim 785, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
822. The method of claim 785, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
823. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation to raise
an average temperature within the selected section to, or above, a
temperature that will pyrolyze hydrocarbons within the selected
section; controlling heat output from the one or more heat sources
such that an average heating rate of the selected section rises by
less than about 3.degree. C. per day when the average temperature
of the selected section is at, or above, the temperature that will
pyrolyze hydrocarbons within the selected section; and producing a
mixture from the formation.
824. The method of claim 823, controlling heat output comprises:
raising the average temperature within the selected section to a
first temperature that is at or above a minimum pyrolysis
temperature of hydrocarbons within the formation; limiting energy
input into the one or more heat sources to inhibit increase in
temperature of the selected section; and increasing energy input
into the formation to raise an average temperature of the selected
section above the first temperature when production of formation
fluid declines below a desired production rate.
825. The method of claim 823, controlling heat output comprises:
raising the average temperature within the selected section to a
first temperature that is at or above a minimum pyrolysis
temperature of hydrocarbons within the formation; limiting energy
input into the one or more heat sources to inhibit increase in
temperature of the selected section; and increasing energy input
into the formation to raise an average temperature of the selected
section above the first temperature when quality of formation fluid
produced from the formation falls below a desired quality.
826. The method of claim 823, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section.
827. The method of claim 823, wherein the one or more heat sources
comprise electrical heaters.
828. The method of claim 823, wherein the one or more heat sources
comprise surface burners.
829. The method of claim 823, wherein the one or more heat sources
comprise flameless distributed combustors.
830. The method of claim 823, wherein the one or more heat sources
comprise natural distributed combustors.
831. The method of claim 823, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
832. The method of claim 823, wherein the heat is controlled that
an average heating rate of the selected section is less than about
1.5.degree. C. per day during pyrolysis.
833. The method of claim 823, wherein the heat is controlled that
an average heating rate of the selected section is less than about
1.degree. C. per day during pyrolysis.
834. The method of claim 823, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density.
835. The method of claim 823, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
836. The method of claim 823, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
837. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
838. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
839. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, wherein the condensable
hydrocarbons have an olefin content is less than about 2.5% by
weight of the condensable hydrocarbons, and wherein the olefin
content is greater than about 0.1% by weight of the condensable
hydrocarbons.
840. The method of claim 823, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
841. The method of claim 823, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons is less
than about 0.10 and wherein the ratio of ethene to ethane is
greater than about 0.001.
842. The method of claim 823, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons is less
than about 0.05 and wherein the ratio of ethene to ethane is
greater than about 0.001.
843. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
844. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
845. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
846. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
847. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
848. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
849. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
850. The method of claim 823, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
851. The method of claim 823, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
852. The method of claim 823, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
853. The method of claim 823, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
854. The method of claim 823, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
855. The method of claim 823, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
856. The method of claim 823, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
857. The method of claim 823, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
858. The method of claim 823, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
859. The method of claim 823, further comprising: providing H.sub.2
to the heated section to hydrogenate hydrocarbons within the
section; and heating a portion of the section with heat from
hydrogenation.
860. The method of claim 823, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
861. The method of claim 823, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
862. The method of claim 823, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
863. The method of claim 823, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
864. The method of claim 823, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
865. The method of claim 823, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
866. The method of claim 823, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
867. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; to heat a selected section of the formation to an
average temperature above about 270.degree. C; allowing the heat to
transfer from the one or more heat sources to the selected section
of the formation; controlling the heat from the one or more heat
sources such that an average heating rate of the selected section
is less than about 3.degree. C. per day during pyrolysis; and
producing a mixture from the formation.
868. The method of claim 867, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
869. The method of claim 867, wherein the one or more heat sources
comprise electrical heaters.
870. The method of claim 867, further comprising supplying
electricity to the electrical heaters substantially during non-peak
hours.
871. The method of claim 867, wherein the one or more heat sources
comprise surface burners.
872. The method of claim 867, wherein the one or more heat sources
comprise flameless distributed combustors.
873. The method of claim 867, wherein the one or more heat sources
comprise natural distributed combustors.
874. The method of claim 867, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
875. The method of claim 867, wherein the heat is further
controlled such that an average heating rate of the selected
section is less than about 3.degree. C./day until production of
condensable hydrocarbons substantially ceases.
876. The method of claim 867, wherein the heat is further
controlled that an average heating rate of the selected section is
less than about 1.5.degree. C. per day during pyrolysis.
877. The method of claim 867, wherein the heat is further
controlled such that an average heating rate of the selected
section is less than about 1.degree. C. per day during
pyrolysis.
878. The method of claim 867, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density.
879. The method of claim 867, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
880. The method of claim 867, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
881. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
882. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
883. The method of claim 867, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
884. The method of claim 867, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
885. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
886. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
887. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
888. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
889. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
890. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
891. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
892. The method of claim 867, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
893. The method of claim 867, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
894. The method of claim 867, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
895. The method of claim 867, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
896. The method of claim 867, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
897. The method of claim 867, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2 wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
898. The method of claim 897, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
899. The method of claim 867, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
900. The method of claim 867, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
901. The method of claim 867, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
902. The method of claim 867, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
903. The method of claim 867, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
904. The method of claim 867, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
905. The method of claim 867, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
906. The method of claim 867, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
907. The method of claim 867, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
908. The method of claim 867, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
909. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; producing
a mixture from the formation through at least one production well;
monitoring a temperature at or in the production well; and
controlling heat input to raise the monitored temperature at a rate
of less than about 3.degree. C. per day.
910. The method of claim 909, wherein the one or more heat sources
comprise at least two heat sources, and wherein superposition of
heat from at least the two heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
911. The method of claim 909, wherein the one or more heat sources
comprise electrical heaters.
912. The method of claim 909, wherein the one or more heat sources
comprise surface burners.
913. The method of claim 909, wherein the one or more heat sources
comprise flameless distributed combustors.
914. The method of claim 909, wherein the one or more heat sources
comprise natural distributed combustors.
915. The method of claim 909, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
916. The method of claim 909, wherein the heat is controlled that
an average heating rate of the selected section is less than about
1.degree. C. per day during pyrolysis.
917. The method of claim 909, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density.
918. The method of claim 909, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
919. The method of claim 909, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
920. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
921. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
922. The method of claim 909, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
923. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
924. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
925. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
926. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
927. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
928. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
929. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
930. The method of claim 909, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
931. The method of claim 909, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
932. The method of claim 909, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
933. The method of claim 909, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
934. The method of claim 909, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
935. The method of claim 909, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
936. The method of claim 935, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
937. The method of claim 909, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
938. The method of claim 909, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
939. The method of claim 909, further comprising: providing H.sub.2
to the heated section to hydrogenate hydrocarbons within the
section; and heating a portion of the section with heat from
hydrogenation.
940. The method of claim 909, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
941. The method of claim 909, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the selected
section to greater than about 100 millidarcy.
942. The method of claim 909, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the selected section.
943. The method of claim 909, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
944. The method of claim 909, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
945. The method of claim 909, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
946. The method of claim 909, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
947. A method of treating a coal formation in situ, comprising:
heating a portion of the formation to a temperature sufficient to
support oxidation of hydrocarbons within the portion, wherein the
portion is located substantially adjacent to a wellbore; flowing an
oxidant through a conduit positioned within the wellbore to a heat
source zone within the portion, wherein the heat source zone
supports an oxidation reaction between hydrocarbons and the
oxidant; reacting a portion of the oxidant with hydrocarbons to
generate heat; and transferring generated heat substantially by
conduction to a pyrolysis zone of the formation to pyrolyze at
least a portion of the hydrocarbons within the pyrolysis zone.
948. The method of claim 947, wherein heating the portion of the
formation comprises raising a temperature of the portion above
about 400.degree. C.
949. The method of claim 947, wherein the conduit comprises
critical flow orifices, the method further comprising flowing the
oxidant through the critical flow orifices to the heat source
zone.
950. The method of claim 947, further comprising removing reaction
products from the heat source zone through the wellbore.
951. The method of claim 947, further comprising removing excess
oxidant from the heat source zone to inhibit transport of the
oxidant to the pyrolysis zone.
952. The method of claim 947, further comprising transporting the
oxidant from the conduit to the heat source zone substantially by
diffusion.
953. The method of claim 947, further comprising heating the
conduit with reaction products being removed through the
wellbore.
954. The method of claim 947, wherein the oxidant comprises
hydrogen peroxide.
955. The method of claim 947, wherein the oxidant comprises
air.
956. The method of claim 947, wherein the oxidant comprises a fluid
substantially free of nitrogen.
957. The method of claim 947, further comprising limiting an amount
of oxidant to maintain a temperature of the heat source zone less
than about 1200.degree. C.
958. The method of claim 947, wherein heating the portion of the
formation comprises electrically heating the formation.
959. The method of claim 947, wherein heating the portion of the
formation comprises heating the portion using exhaust gases from a
surface burner.
960 . The method of claim 947, wherein heating the portion of the
formation comprises heating the portion with a flameless
distributed combustor.
961. The method of claim 947, further comprising controlling a
pressure and a temperature within at least a majority of the
pyrolysis zone, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
962. The method of claim 947, further comprising controlling the
heat such that an average heating rate of the pyrolysis zone is
less than about 1.degree. C. per day during pyrolysis.
963. The method of claim 947, wherein heating the portion comprises
heating the pyrolysis zone such that a thermal conductivity of at
least a portion of the pyrolysis zone is greater than about 0.5
W/(m.degree. C.).
964. The method of claim 947, further comprising controlling a
pressure within at least a majority of the pyrolysis zone of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
965. The method of claim 947, further comprising: providing
hydrogen (H.sub.2) to the pyrolysis zone to hydrogenate
hydrocarbons within the pyrolysis zone; and heating a portion of
the pyrolysis zone with heat from hydrogenation.
966. The method of claim 947, wherein transferring generated heat
comprises increasing a permeability of a majority of the pyrolysis
zone to greater than about 100 millidarcy.
967. The method of claim 947, wherein transferring generated heat
comprises substantially uniformly increasing a permeability of a
majority of the pyrolysis zone.
968. The method of claim 947, wherein the heating is controlled to
yield greater than about 60% by weight of condensable hydrocarbons,
as measured by Fischer Assay.
969. The method of claim 947, wherein the wellbore is located along
strike to reduce pressure differentials along a heated length of
the wellbore.
970. The method of claim 947, wherein the wellbore is located along
strike to increase uniformity of heating along a heated length of
the wellbore.
971. The method of claim 947, wherein the wellbore is located along
strike to increase control of heating along a heated length of the
wellbore.
972. A method of treating a coal formation in situ, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidant; flowing the oxidant into a conduit, and
wherein the conduit is connected such that the oxidant can flow
from the conduit to the hydrocarbons; allowing the oxidant and the
hydrocarbons to react to produce heat in a heat source zone;
allowing heat to transfer from the heat source zone to a pyrolysis
zone in the formation to pyrolyze at least a portion of the
hydrocarbons within the pyrolysis zone; and removing reaction
products such that the reaction products are inhibited from flowing
from the heat source zone to the pyrolysis zone.
973. The method of claim 972, wherein heating the portion of the
formation comprises raising the temperature of the portion above
about 400.degree. C.
974. The method of claim 972, wherein heating the portion of the
formation comprises electrically heating the formation.
975. The method of claim 972, wherein heating the portion of the
formation comprises heating the portion using exhaust gases from a
surface burner.
976. The method of claim 972, wherein the conduit comprises
critical flow orifices, the method further comprising flowing the
oxidant through the critical flow orifices to the heat source
zone.
977. The method of claim 972, wherein the conduit is located within
a wellbore, wherein removing reaction products comprises removing
reaction products from the heat source zone through the
wellbore.
978. The method of claim 972, further comprising removing excess
oxidant from the heat source zone to inhibit transport of the
oxidant to the pyrolysis zone.
979. The method of claim 972, further comprising transporting the
oxidant from the conduit to the heat source zone substantially by
diffusion.
980. The method of claim 972, wherein the conduit is located within
a wellbore, the method further comprising heating the conduit with
reaction products being removed through the wellbore to raise a
temperature of the oxidant passing through the conduit.
981. The method of claim 972, wherein the oxidant comprises
hydrogen peroxide.
982. The method of claim 972, wherein the oxidant comprises
air.
983. The method of claim 972, wherein the oxidant comprises a fluid
substantially free of nitrogen.
984. The method of claim 972, further comprising limiting an amount
of oxidant to maintain a temperature of the heat source zone less
than about 1200.degree. C.
985. The method of claim 972, further comprising limiting an amount
of oxidant to maintain a temperature of the heat source zone at a
temperature that inhibits production of oxides of nitrogen.
986. The method of claim 972, wherein heating a portion of the
formation to a temperature sufficient to support oxidation of
hydrocarbons within the portion further comprises heating with a
flameless distributed combustor.
987. The method of claim 972, further comprising controlling a
pressure and a temperature within at least a majority of the
pyrolysis zone of the formation, wherein the pressure is controlled
as a function of temperature, or the temperature is controlled as a
function of pressure.
988. The method of claim 972, further comprising controlling the
heat such that an average heating rate of the pyrolysis zone is
less than about 1.degree. C. per day during pyrolysis.
989. The method of claim 972, wherein allowing the heat to transfer
comprises transferring heat substantially by conduction.
990. The method of claim 972, wherein allowing heat to transfer
comprises heating the pyrolysis zone such that a thermal
conductivity of at least a portion of the pyrolysis zone is greater
than about 0.5 W/(m.degree. C.).
991. The method of claim 972, further comprising controlling a
pressure within at least a majority of the pyrolysis zone, wherein
the controlled pressure is at least about 2.0 bar absolute.
992. The method of claim 972, further comprising: providing
hydrogen (H.sub.2) to the pyrolysis zone to hydrogenate
hydrocarbons within the pyrolysis zone; and heating a portion of
the pyrolysis zone with heat from hydrogenation.
993. The method of claim 972, wherein allowing the heat to transfer
comprises increasing a permeability of a majority of the pyrolysis
zone to greater than about 100 millidarcy.
994. The method of claim 972, wherein allowing the heat to transfer
comprises substantially uniformly increasing a permeability of a
majority of the pyrolysis zone.
995. The method of claim 972, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
996. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein the portion is located
substantially adjacent to an opening in the formation; providing
the oxidizing fluid to a heat source zone in the formation;
allowing the oxidizing gas to react with at least a portion of the
hydrocarbons at the heat source zone to generate heat in the heat
source zone; and transferring the generated heat substantially by
conduction from the heat source zone to a pyrolysis zone in the
formation.
997. The method of claim 996, further comprising transporting the
oxidizing fluid through the heat source zone by diffusion.
998. The method of claim 996, further comprising directing at least
a portion of the oxidizing fluid into the opening through orifices
of a conduit disposed in the opening.
999. The method of claim 996, further comprising controlling a flow
of the oxidizing fluid with critical flow orifices of a conduit
disposed in the opening such that a rate of oxidation is
controlled.
1000. The method of claim 996, wherein a conduit is disposed within
the opening, the method further comprising removing an oxidation
product from the formation through the conduit.
1001. The method of claim 996, wherein a conduit is disposed within
the opening, the method further comprising removing an oxidation
product from the formation through the conduit and transferring
substantial heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
1002. The method of claim 996, wherein a conduit is disposed within
the opening, the method further comprising removing an oxidation
product from the formation through the conduit, wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
1003. The method of claim 996, wherein a conduit is disposed within
the opening, the method further comprising removing an oxidation
product from the formation through the conduit and controlling a
pressure between the oxidizing fluid and the oxidation product in
the conduit to reduce contamination of the oxidation product by the
oxidizing fluid.
1004. The method of claim 996, wherein a center conduit is disposed
within an outer conduit, and wherein the outer conduit is disposed
within the opening, the method further comprising providing the
oxidizing fluid into the opening through the center conduit and
removing an oxidation product through the outer conduit.
1005. The method of claim 996, wherein the heat source zone extends
radially from the opening a width of less than approximately 0.15
m.
1006. The method of claim 996, wherein heating the portion
comprises applying electrical current to an electric heater
disposed within the opening.
1007. The method of claim 996, wherein the pyrolysis zone is
substantially adjacent to the heat source zone.
1008. The method of claim 996, further comprising controlling a
pressure and a temperature within at least a majority of the
pyrolysis zone of the formation, wherein the pressure is controlled
as a function of temperature, or the temperature is controlled as a
function of pressure.
1009. The method of claim 996, further comprising controlling the
heat such that an average heating rate of the pyrolysis zone is
less than about 1.degree. C. per day during pyrolysis.
1010. The method of claim 996, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1011. The method of claim 996, wherein allowing heat to transfer
comprises heating the portion such that a thermal conductivity of
at least a portion of the pyrolysis zone is greater than about 0.5
W/(m.degree. C.).
1012. The method of claim 996, further comprising controlling a
pressure within at least a majority of the pyrolysis zone, wherein
the controlled pressure is at least about 2.0 bar absolute.
1013. The method of claim 996, further comprising: providing
hydrogen (H.sub.2) to the pyrolysis zone to hydrogenate
hydrocarbons within the pyrolysis zone; and heating a portion of
the pyrolysis zone with heat from hydrogenation.
1014. The method of claim 996, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
pyrolysis zone to greater than about 100 millidarcy.
1015. The method of claim 996, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the pyrolysis zone.
1016. The method of claim 996, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1017. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; producing
a mixture from the formation; and maintaining an average
temperature within the selected section above a minimum pyrolysis
temperature and below a vaporization temperature of hydrocarbons
having carbon numbers greater than 25 to inhibit production of a
substantial amount of hydrocarbons having carbon numbers greater
than 25 in the mixture.
1018. The method of claim 1017, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1019. The method of claim 1017, wherein maintaining the average
temperature within the selected section comprises maintaining the
temperature within a pyrolysis temperature range.
1020. The method of claim 1017, wherein the one or more heat
sources comprise electrical heaters.
1021. The method of claim 1017, wherein the one or more heat
sources comprise surface burners.
1022. The method of claim 1017, wherein the one or more heat
sources comprise flameless distributed combustors.
1023. The method of claim 1017, wherein the one or more heat
sources comprise natural distributed combustors.
1024. The method of claim 1017, wherein the minimum pyrolysis
temperature is greater than about 270.degree. C.
1025. The method of claim 1017, wherein the vaporization
temperature is less than approximately 450.degree. C. at
atmospheric pressure.
1026. The method of claim 1017, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1027. The method of claim 1017, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1028. The method of claim 1017, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1029. The method of claim 1017, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1030. The method of claim 1017, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1031. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1032. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1033. The method of claim 1017, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1034. The method of claim 1017, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1035. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1036. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1037. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1038. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1039. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1040. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1041. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1042. The method of claim 1017, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1043. The method of claim 1017, wherein the produced mixture
comprises a-non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1044. The method of claim 1017, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1045. The method of claim 1017, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1046. The method of claim 1017, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1047. The method of claim 1017, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1048. The method of claim 1047, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1049. The method of claim 1017, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1050. The method of claim 1017, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1051. The method of claim 1017, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1052. The method of claim 1017, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1053. The method of claim 1017, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1054. The method of claim 1017, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1055. The method of claim 1017, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1056. The method of claim 1017, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1057. The method of claim 1017, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1058. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
controlling a pressure within the formation to inhibit production
of hydrocarbons from the formation having carbon numbers greater
than 25; and producing a mixture from the formation.
1059. The method of claim 1058, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1060. The method of claim 1058, wherein the one or more heat
sources comprise electrical heaters.
1061. The method of claim 1058, wherein the one or more heat
sources comprise surface burners.
1062. The method of claim 1058, wherein the one or more heat
sources comprise flameless distributed combustors.
1063. The method of claim 1058, wherein the one or more heat
sources comprise natural distributed combustors.
1064. The method of claim 1058, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
1065. The method of claim 1064, wherein controlling the temperature
comprises maintaining a temperature within the selected section
within a pyrolysis temperature range.
1066. The method of claim 1058, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1067. The method of claim 1058, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1068. The method of claim 1058, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1069. The method of claim 1058, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1070. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1071. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1072. The method of claim 1058, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1073. The method of claim 1058, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1074. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1075. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1076. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1077. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1078. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1079. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1080. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1081. The method of claim 1058, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1082. The method of claim 1058, wherein the produced mixture
comprises a-non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1083. The method of claim 1058, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1084. The method of claim 1058, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1085. The method of claim 1058, further comprising controlling the
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1086. The method of claim 1058, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1087. The method of claim 1086, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1088. The method of claim 1058, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1089. The method of claim 1058, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1090. The method of claim 1058, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1091. The method of claim 1058, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1092. The method of claim 1058, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1093. The method of claim 1058, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1094. The method of claim 1058, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1095. The method of claim 1058, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1096. The method of claim 1058, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1097. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation, wherein the produced
mixture comprises condensable hydrocarbons, and wherein about 0.1%
by weight to about 15% by weight of the condensable hydrocarbons
are olefins.
1098. The method of claim 1097, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1099. The method of claim 1097, wherein the one or more heat
sources comprise electrical heaters.
1100. The method of claim 1097, wherein the one or more heat
sources comprise surface burners.
1101. The method of claim 1097, wherein the one or more heat
sources comprise flameless distributed combustors.
1102. The method of claim 1097, wherein the one or more heat
sources comprise natural distributed combustors.
1103. The method of claim 1097, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1104. The method of claim 1097, wherein controlling the temperature
comprises maintaining the temperature within the selected section
within a pyrolysis temperature range.
1105. The method of claim 1097, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1106. The method of claim 1097, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1107. The method of claim 1097, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1108. The method of claim 1097, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1109. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1110. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1111. The method of claim 1097, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1112. The method of claim 1097, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1113. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1114. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1115. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1116. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1117. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1118. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1119. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1120. The method of claim 1097, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1121. The method of claim 1097, wherein the produced mixture
comprises a-non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1122. The method of claim 1097, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1123. The method of claim 1097, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1124. The method of claim 1097, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1125. The method of claim 1097, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1126. The method of claim 1125, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1127. The method of claim 1097, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1128. The method of claim 1097, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1129. The method of claim 1097, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1130. The method of claim 1097, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1131. The method of claim 1097, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1132. The method of claim 1097, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1133. The method of claim 1097, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1134. The method of claim 1097, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1135. The method of claim 1097, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1136. The method of claim 1097, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1137. A method of treating a coal formation in situ, comprising:
heating a section of the formation to a pyrolysis temperature from
at least a first heat source, a second heat source and a third heat
source, and wherein the first heat source, the second heat source
and the third heat source are located along a perimeter of the
section; controlling heat input to the first heat source, the
second heat source and the third heat source to limit a heating
rate of the section to a rate configured to produce a mixture, from
the formation with an olefin content of less than about 15% by
weight of condensable fluids (on a dry basis) within the produced
mixture; and producing the mixture from the formation through a
production well.
1138. The method of claim 1137, wherein superposition of heat form
the first heat source, second heat source, and third heat source
pyrolyzes a portion of the hydrocarbons within the formation to
fluids
1139. The method of claim 1137, wherein the pyrolysis temperature
is between about 270.degree. C. and about 400.degree. C.
1140. The method of claim 1137, wherein the first heat source is
operated for less than about twenty four hours a day.
1141. The method of claim 1137, wherein the first heat source
comprises an electrical heater.
1142. The method of claim 1137, wherein the first heat source
comprises a surface burner.
1143. The method of claim 1137, wherein the first heat source
comprises a flameless distributed combustor.
1144. The method of claim 1137, wherein the first heat source,
second heat source and third heat source are positioned
substantially at apexes of an equilateral triangle.
1145. The method of claim 1137, wherein the production well is
located substantially at a geometrical center of the first heat
source, second heat source, and third heat source.
1146. The method of claim 1137, further comprising a fourth heat
source, fifth heat source, and sixth heat source located along the
perimeter of the section.
1147, The method of claim 1146, wherein the heat sources are
located substantially at apexes of a regular hexagon.
1148. The method of claim 1147, wherein the production well is
located substantially at a center of the hexagon.
1149. The method of claim 1137, further comprising controlling a
pressure and a temperature within at least a majority of the
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
1150. The method of claim 1137, wherein controlling the temperature
comprises maintaining the temperature within the selected section
within a pyrolysis temperature range.
1151. The method of claim 1137, further comprising controlling the
heat such that an average heating rate of the section is less than
about 3.degree. C. per day during pyrolysis.
1152. The method of claim 1137, further comprising controlling the
heat such that an average heating rate of the section is less than
about 1.degree. C. per day during pyrolysis.
1153. The method of claim 1137, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1154. The method of claim 1137, wherein heating the section of the
formation comprises transferring heat substantially by
conduction.
1155. The method of claim 1137, wherein providing heat from the one
or more heat sources comprises heating the section such that a
thermal conductivity of at least a portion of the section is
greater than about 0.5 W/(m.degree. C.).
1156. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1157. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1158. The method of claim 1137, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1159. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1160. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1161. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1162. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1163. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1164. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1165. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1166. The method of claim 1137, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1167. The method of claim 1137, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1168. The method of claim 1137, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1169. The method of claim 1137, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1170. The method of claim 1137, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1171. The method of claim 1137, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1172. The method of claim 1171, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1173. The method of claim 1137, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1174. The method of claim 1137, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1175. The method of claim 1137, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1176. The method of claim 1137, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1177. The method of claim 1137, heating the section comprises
increasing a permeability of a majority of the section to greater
than about 100 millidarcy.
1178. The method of claim 1137, wherein heating the section
comprises substantially uniformly increasing a permeability of a
majority of the section.
1179. The method of claim 1137, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1180. The method of claim 1137, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1181. The method of claim 1137, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1182. The method of claim 1137, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1183. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation, wherein the produced
mixture comprises condensable hydrocarbons, and wherein less than
about 1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
1184. The method of claim 1183, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1185. The method of claim 1183, wherein the one or more heat
sources comprise electrical heaters.
1186. The method of claim 1183, wherein the one or more heat
sources comprise surface burners.
1187. The method of claim 1183, wherein the one or more heat
sources comprise flameless distributed combustors.
1188. The method of claim 1183, wherein the one or more heat
sources comprise natural distributed combustors.
1189. The method of claim 1183, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1190. The method of claim 1189, wherein controlling the temperature
comprises maintaining the temperature within the selected section
within a pyrolysis temperature range.
1191. The method of claim 1183, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1192. The method of claim 1183, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1193. The method of claim 1183, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1194. The method of claim 1183, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1195. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1196. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1197. The method of claim 1183, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1198. The method of claim 1183, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1199. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1200. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1201. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1202. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1203. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1204. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1205. The method of claim 1183, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1206. The method of claim 1183, wherein the produced mixture
comprises a-non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1207. The method of claim 1183, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1208. The method of claim 1183, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1209. The method of claim 1183, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1210. The method of claim 1183, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1211. The method of claim 1211, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1212. The method of claim 1183, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1213. The method of claim 1183, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1214. The method of claim 1183, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1215. The method of claim 1183, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1216. The method of claim 1183, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1217. The method of claim 1183, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1218. The method of claim 1183, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1219. The method of claim 1183, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1220. The method of claim 1183, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1221. The method of claim 1183, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1222. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation, wherein the produced
mixture comprises condensable hydrocarbons, and wherein less than
about 1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
1223. The method of claim 1222, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1224. The method of claim 1222, wherein the one or more heat
sources comprise electrical heaters.
1225. The method of claim 1222, wherein the one or more heat
sources comprise surface burners.
1226. The method of claim 1222, wherein the one or more heat
sources comprise Blameless distributed combustors.
1227. The method of claim 1222, wherein the one or more heat
sources comprise natural distributed combustors.
1228. The method of claim 1222, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1229. The method of claim 1228, wherein controlling the temperature
comprises maintaining the temperature within the selected section
within a pyrolysis temperature range.
1230. The method of claim 1222, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1231. The method of claim 1222, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1232. The method of claim 1222, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1233. The method of claim 1222, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1234. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1235. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.11% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1236. The method of claim 1222, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1237. The method of claim 1222, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1238. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1239. The method of claim 1222 wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1240. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1241. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1242. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1243. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1244. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1245. The method of claim 1222, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1246. The method of claim 1222, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1247. The method of claim 1222, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1248. The method of claim 1222, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1249. The method of claim 1222, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1250. The method of claim 1222, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1251. The method of claim 1250, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1252. The method of claim 1222, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1253. The method of claim 1222, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1254. The method of claim 1222, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1255. The method of claim 1222, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1256. The method of claim 1222, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1257. The method of claim 1222, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1258. The method of claim 1222, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1259. The method of claim 1222, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1260. The method of claim 1222, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1261. The method of claim 1222, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1262. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation, wherein the produced
mixture comprises condensable hydrocarbons, and wherein less than
about 1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
1263. The method of claim 1262, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1264. The method of claim 1262, wherein the one or more heat
sources comprise electrical heaters.
1265. The method of claim 1262, wherein the one or more heat
sources comprise surface burners.
1266. The method of claim 1262, wherein the one or more heat
sources comprise flameless distributed combustors.
1267. The method of claim 1262, wherein the one or more heat
sources comprise natural distributed combustors.
1268. The method of claim 1262, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1269. The method of claim 1268, wherein controlling the temperature
comprises maintaining the temperature within the selected section
within a pyrolysis temperature range.
1270. The method of claim 1262, further comprising controlling the
heat into such that an average heating rate of the selected section
is less than about 1.degree. C. per day during pyrolysis.
1271. The method of claim 1262, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (T of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1272. The method of claim 1262, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1273. The method of claim 1262, wherein providing heat from the one
or more heat sources comprises heating the selected formation such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1274. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1275. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1276. The method of claim 1262, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
1277. The method of claim 1262, wherein the produced mixture
comprises non-condensable hydrocarbons, wherein a molar ratio of
ethene to ethane in the non-condensable hydrocarbons is less than
about 0.15, and wherein the ratio of ethene to ethane is greater
than about 0.001.
1278. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1279. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1280. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1281. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1282. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1283. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1284. The method of claim 1262, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1285. The method of claim 1262, wherein the produced mixture
comprises a-non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1286. The method of claim 1262, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1287. The method of claim 1262, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1288. The method of claim 1262, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1289. The method of claim 1262, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2 wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1290. The method of claim 1289, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
1291. The method of claim 1262, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1292. The method of claim 1262, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1293. The method of claim 1262, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1294. The method of claim 1262, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
1295. The method of claim 1262, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1296. The method of claim 1262, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1297. The method of claim 1262, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1298. The method of claim 1262, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1299. The method of claim 1262, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1300. The method of claim 1262, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1301. A method of treating a coal formation in situ, comprising:
raising a temperature of a first section of the formation with one
or more heat sources to a first pyrolysis temperature; heating the
first section to an upper pyrolysis temperature, wherein heat is
supplied to the first section at a rate configured to inhibit
olefin production; producing a first mixture from the formation,
wherein the first mixture comprises condensable hydrocarbons and
H.sub.2; creating a second mixture from the first mixture, wherein
the second mixture comprises a higher concentration of H.sub.2 than
the first mixture; raising a temperature of a second section of the
formation with one or more heat sources to a second pyrolysis
temperature; providing a portion of the second mixture to the
second section; heating the second section to an upper pyrolysis
temperature, wherein heat is supplied to the second section at a
rate configured to inhibit olefin production; and producing a third
mixture from the second section.
1302. The method of claim 1301, wherein creating the second mixture
comprises removing condensable hydrocarbons from the first
mixture.
1303. The method of claim 1301, wherein creating the second mixture
comprises removing water from the first mixture.
1304. The method of claim 1301, wherein creating the second mixture
comprises removing carbon dioxide from the first mixture.
1305. The method of claim 1301, wherein the first pyrolysis
temperature is greater than about 270.degree. C.
1306. The method of claim 1301, wherein the second pyrolysis
temperature is greater than about 270.degree. C.
1307. The method of claim 1301, wherein the upper pyrolysis
temperature is about 500.degree. C.
1308. The method of claim 1301, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the first or second selected
section of the formation.
1309. The method of claim 1301, wherein the one or more heat
sources comprise electrical heaters.
1310. The method of claim 1301, wherein the one or more heat
sources comprise surface burners.
1311. The method of claim 1301, wherein the one or more heat
sources comprise flameless distributed combustors.
1312. The method of claim 1301, wherein the one or more heat
sources comprise natural distributed combustors.
1313. The method of claim 1301, further comprising controlling a
pressure and a temperature within at least a majority of the first
section and the second section of the formation, wherein the
pressure is controlled as a function of temperature, or the
temperature is controlled as a function of pressure.
1314. The method of claim 1301, further comprising controlling the
heat to the first and second sections such that an average heating
rate of the first and second sections is less than about 1.degree.
C. per day during pyrolysis.
1315. The method of claim 1301, wherein heating the first and the
second sections comprises: heating a selected volume (V) of the
coal formation from the one or more heat sources, wherein the
formation has an average heat capacity (C.sub.v), and wherein the
heating pyrolyzes at least some hydrocarbons within the selected
volume of the formation; and wherein heating energy/day provided to
the volume is equal to or less than Pwr, wherein Pwr is calculated
by the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
1316. The method of claim 1301, wherein heating the first and
second sections comprises transferring heat substantially by
conduction.
1317. The method of claim 1301, wherein heating the first and
second sections comprises heating the first and second sections
such that a thermal conductivity of at least a portion of the first
and second sections is greater than about 0.5 W/(m.degree. C.).
1318. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1319. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1320. The method of claim 1301, wherein the first or third mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1321. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1322. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1323. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1324. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1325. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1326. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1327. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1328. The method of claim 1301, wherein the first or third mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1329. The method of claim 1301, wherein the first or third mixture
comprises a non-condensable component, and wherein the
non-condensable component comprises hydrogen, and wherein the
hydrogen is greater than about 10% by volume of the non-condensable
component and wherein the hydrogen is less than about 80% by volume
of the non-condensable component.
1330. The method of claim 1301, wherein the first or third mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1331. The method of claim 1301, wherein the first or third mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1332. The method of claim 1301, further comprising controlling a
pressure within at least a majority of the first or second sections
of the formation, wherein the controlled pressure is at least about
2.0 bar absolute.
1333. The method of claim 1301, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1334. The method of claim 1333, wherein the partial pressure of
H.sub.2 within a mixture is measured when the mixture is at a
production well.
1335. The method of claim 1301, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1336. The method of claim 1301, further comprising: providing
hydrogen (H.sub.2) to the first or second section to hydrogenate
hydrocarbons within the first or second section; and heating a
portion of the first or second section with heat from
hydrogenation.
1337. The method of claim 1301, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1338. The method of claim 1301, further comprising increasing a
permeability of a majority of the first or second section to
greater than about 100 millidarcy.
1339. The method of claim 1301, further comprising substantially
uniformly increasing a permeability of a majority of the first or
second section.
1340. The method of claim 1301, wherein the heating is controlled
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1341. The method of claim 1301, wherein producing the first or
third mixture comprises producing the first or third mixture in a
production well, and wherein at least about 7 heat sources are
disposed in the formation for each production well.
1342. The method of claim 1301, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1343. The method of claim 1301, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1344. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; producing
a mixture from the formation; and hydrogenating a portion of the
produced mixture with H.sub.2 produced from the formation.
1345. The method of claim 1344, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1346. The method of claim 1344, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1347. The method of claim 1344, wherein the one or more heat
sources comprise electrical heaters.
1348. The method of claim 1344, wherein the one or more heat
sources comprise surface burners.
1349. The method of claim 1344, wherein the one or more heat
sources comprise flameless distributed combustors.
1350. The method of claim 1344, wherein the one or more heat
sources comprise natural distributed combustors.
1351. The method of claim 1344, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1352. The method of claim 1344, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree.C. per day du ring pyrolysis.
1353. The method of claim 1344, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1354. The method of claim 1344, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1355. The method of claim 1344, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1356. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1357. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1358. The method of claim 1344, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1359. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1360. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1361. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1362. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1363. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1364. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1365. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1366. The method of claim 1344, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1367. The method of claim 1344, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1368. The method of claim 1344, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1369. The method of claim 1344, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1370. The method of claim 1344, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1371. The method of claim 1344, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1372. The method of claim 1344, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1373. The method of claim 1344, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1374. The method of claim 1344, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1375. The method of claim 1344, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1376. The method of claim 1344, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1377. The method of claim 1344, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1378. The method of claim 1344, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1379. The method of claim 1344, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1380. The method of claim 1344, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1381. A method of treating a coal formation in situ, comprising:
heating a first section of the formation; producing H.sub.2 from
the first section of formation; heating a second section of the
formation; and recirculating a portion of the H.sub.2 from the
first section into the second section of the formation to provide a
reducing environment within the second section of the
formation.
1382. The method of claim 1381, wherein heating the first section
or heating the second section comprises heating with an electrical
heater.
1383. The method of claim 1381, wherein heating the first section
or heating the second section comprises heating with a surface
burner.
1384. The method of claim 1381, wherein heating the first section
or heating the second section comprises heating with a flameless
distributed combustor.
1385. The method of claim 1381, wherein heating the first section
or heating the second section comprises heating with a natural
distributed combustor.
1386. The method of claim 1381, further comprising controlling a
pressure and a temperature within at least a majority of the first
or second section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1387. The method of claim 1381, further comprising controlling the
heat such that an average heating rate of the first or second
section is less than about 1.degree. C. per day during
pyrolysis.
1388. The method of claim 1381, wherein heating the first section
or heating the second section further comprises: heating a selected
volume (V) of the coal formation from the one or more heat sources,
wherein the formation has an average heat capacity (C.sub.v), and
wherein the heating pyrolyzes at least some hydrocarbons within the
selected volume of the formation; and wherein heating energy/day
provided to the volume is equal to or less than Pwr, wherein Pwr is
calculated by the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr
is the heating energy/day, h is an average heating rate of the
formation, .rho..sub.B is formation bulk density, and wherein the
heating rate is less than about 10.degree. C./day.
1389. The method of claim 1381, wherein heating the first section
or heating the second section comprises transferring heat
substantially by conduction.
1390. The method of claim 1381, wherein heating the first section
or heating the second section comprises heating the formation such
that a thermal conductivity of at least a portion of the first or
second section is greater than about 0.5 W/(m.degree. C.).
1391. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1392. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1393. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1394. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1395. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1396. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1397. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons comprise
oxygen containing compounds, and wherein the oxygen containing
compounds comprise phenols.
1398. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1399. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1400. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1401. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1402. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1403. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1404. The method of claim 1381, further comprising producing a
mixture from the second section, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1405. The method of claim 1381, further comprising controlling a
pressure within at least a majority of the first or second section
of the formation, wherein the controlled pressure is at least about
2.0 bar absolute.
1406. The method of claim 1381, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
1407. The method of claim 1406, wherein the partial pressure of
H.sub.2 within a mixture is measured when the mixture is at a
production well.
1408. The method of claim 1381, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1409. The method of claim 1381, further comprising: providing
hydrogen (H.sub.2) to the second section to hydrogenate
hydrocarbons within the section; and heating a portion of the
second section with heat from hydrogenation.
1410. The method of claim 1381, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1411. The method of claim 1381, wherein heating the first section
or heating the second section comprises increasing a permeability
of a majority of the first or second section, respectively, to
greater than about 100 millidarcy.
1412. The method of claim 1381, wherein heating the first section
or heating the second section comprises substantially uniformly
increasing a permeability of a majority of the first or second
section, respectively.
1413. The method of claim 1381, further comprises controlling the
heating of the first section or controlling the heat of the second
section to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1414. The method of claim 1381, further comprising producing a
mixture from the formation in a production well, and wherein at
least about 7 heat sources are disposed in the formation for each
production well.
1415. The method of claim 1381, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1416. The method of claim 1381, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1417. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; producing
a mixture from the formation; and controlling formation conditions
such that the mixture produced from the formation comprises
condensable hydrocarbons including H.sub.2, wherein the partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1418. The method of claim 1417, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1419. The method of claim 1417, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range.
1420. The method of claim 1417, wherein the one or more heat
sources comprise electrical heaters.
1421. The method of claim 1417, wherein the one or more heat
sources comprise surface burners.
1422. The method of claim 1417, wherein the one or more heat
sources comprise flameless distributed combustors.
1423. The method of claim 1417, wherein the one or more heat
sources comprise natural distributed combustors.
1424. The method of claim 1417, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1425. The method of claim 1417, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1426. The method of claim 1417, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1427. The method of claim 1417, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1428. The method of claim 1417, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1429. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 250.
1430. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1431. The method of claim 1417, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1432. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1433. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1434. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1435. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1436. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1437. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1438. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1439. The method of claim 1417, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1440. The method of claim 1417, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1441. The method of claim 1417, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1442. The method of claim 1417, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1443. The method of claim 1417, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1444. The method of claim 1417, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1445. The method of claim 1417, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
1446. The method of claim 1417, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1447. The method of claim 1417, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1448. The method of claim 1417, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1449. The method of claim 1417, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1450. The method of claim 1417, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1451. The method of claim 1417, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1452. The method of claim 1417, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1453. The method of claim 1417, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1454. The method of claim 1417, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1455. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation;
maintaining a pressure of the selected section above atmospheric
pressure to increase a partial pressure of H.sub.2, as compared to
the partial pressure of H.sub.2 at atmospheric pressure, in at
least a majority of the selected section; and producing a mixture
from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
1456. The method of claim 1455, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1457. The method of claim 1455, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1458. The method of claim 1455, wherein the one or more heat
sources comprise electrical heaters.
1459. The method of claim 1455, wherein the one or more heat
sources comprise surface burners.
1460. The method of claim 1455, wherein the one or more heat
sources comprise Blameless distributed combustors.
1461. The method of claim 1455, wherein the one or more heat
sources comprise natural distributed combustors.
1462. The method of claim 1455, further comprising controlling the
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1463. The method of claim 1455, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1464. The method of claim 1455, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1465. The method of claim 1455, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1466. The method of claim 1455, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1467. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1468. The method of claim 1455, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1469. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1470. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1471. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1472. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1473. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1474. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1475. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1476. The method of claim 1455, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1477. The method of claim 1455, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1478. The method of claim 1455, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1479. The method of claim 1455, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1480. The method of claim 1455, further comprising controlling the
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1481. The method of claim 1455, further comprising increasing the
pressure of the selected section, to an upper limit of about 21 bar
absolute, to increase an amount of non-condensable hydrocarbons
produced from the formation.
1482. The method of claim 1455, further comprising decreasing
pressure of the selected section, to a lower limit of about
atmospheric pressure, to increase an amount of condensable
hydrocarbons produced from the formation.
1483. The method of claim 1455, wherein the partial pressure
comprises a partial pressure based on properties measured at a
production well.
1484. The method of claim 1455, further comprising altering the
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1485. The method of claim 1455, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1486. The method of claim 1455, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1487. The method of claim 1455, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1488. The method of claim 1455, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1489. The method of claim 1455, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1490. The method of claim 1455, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1491. The method of claim 1455, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1492. The method of claim 1455, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1493. The method of claim 1455, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1494. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; providing
H.sub.2 to the formation to produce a reducing environment in at
least some of the formation; producing a mixture from the
formation.
1495. The method of claim 1494, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1496. The method of claim 1494, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1497. The method of claim 1494, further comprising separating a
portion of hydrogen within the mixture and recirculating the
portion into the formation.
1498. The method of claim 1494, wherein the one or more heat
sources comprise electrical heaters.
1499. The method of claim 1494, wherein the one or more heat
sources comprise surface burners.
1500. The method of claim 1494, wherein the one or more heat
sources comprise flameless distributed combustors.
1501. The method of claim 1494, wherein the one or more heat
sources comprise natural distributed combustors.
1502. The method of claim 1494, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1503. The method of claim 1494, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1504. The method of claim 1494, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1505. The method of claim 1494, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1506. The method of claim 1494, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1507. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1508. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1509. The method of claim 1494, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1510. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1511. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1512. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1513. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1514. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1515. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1516. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1517. The method of claim 1494, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1518. The method of claim 1494, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1519. The method of claim 1494, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1520. The method of claim 1494, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1521. The method of claim 1494, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1522. The method of claim 1494, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1523. The method of claim 1494, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1524. The method of claim 1494, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1525. The method of claim 1494, wherein providing hydrogen
(H.sub.2) to the formation further comprises: hydrogenating
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1526. The method of claim 1494, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1527. The method of claim 1494, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1528. The method of claim 1494, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1529. The method of claim 1494, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1530. The method of claim 1494, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1531. The method of claim 1494, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1532. The method of claim 1494, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1533. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; providing
H.sub.2 to the selected section to hydrogenate hydrocarbons within
the selected section and to heat a portion of the section with heat
from the hydrogenation; and controlling heating of the selected
section by controlling amounts of H.sub.2 provided to the selected
section.
1534. The method of claim 1533, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1535. The method of claim 1533, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1536. The method of claim 1533, wherein the one or more heat
sources comprise electrical heaters.
1537. The method of claim 1533, wherein the one or more heat
sources comprise surface burners.
1538. The method of claim 1533, wherein the one or more heat
sources comprise flameless distributed combustors.
1539. The method of claim 1533, wherein the one or more heat
sources comprise natural distributed combustors.
1540. The method of claim 1533, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1541. The method of claim 1533, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1542. The method of claim 1533, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1543. The method of claim 1533, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1544. The method of claim 1533, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1545. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
1546. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
1547. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
1548. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
1549. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
1550. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
1551. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1552. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
1553. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
1554. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
1555. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
1556. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
1557. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
1558. The method of claim 1533, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
1559. The method of claim 1533, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1560. The method of claim 1533, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
1561. The method of claim 1560, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1562. The method of claim 1533, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1563. The method of claim 1533, further comprising controlling
formation conditions by recirculating a portion of hydrogen from a
produced mixture into the formation.
1564. The method of claim 1533, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1565. The method of claim 1533, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1566. The method of claim 1533, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1567. The method of claim 1533, wherein the heating is controlled
of claim 1533, further comprising producing a mixture in a
production well, and wherein at least about 7 heat sources are
disposed in the formation for each production well.
1568. The method of claim 1533, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1569. The method of claim 1533, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1570. An in situ method for producing H.sub.2 from a coal
formation, comprising: providing heat from one or more heat sources
to at least a portion of the formation; allowing the heat to
transfer from the one or more heat sources to a selected section of
the formation; and producing a mixture from the formation, wherein
a H.sub.2 partial pressure within the mixture is greater than about
0.5 bar.
1571. The method of claim 1570, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1572. The method of claim 1570, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1573. The method of claim 1570, wherein the one or more heat
sources comprise electrical heaters.
1574. The method of claim 1570, wherein the one or more heat
sources comprise surface burners.
1575. The method of claim 1570, wherein the one or more heat
sources comprise flameless distributed combustors.
1576. The method of claim 1570, wherein the one or more heat
sources comprise natural distributed combustors.
1577. The method of claim 1570, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1578. The method of claim 1570, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1579. The method of claim 1570, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (k) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1580. The method of claim 1570, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1581. The method of claim 1570, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1582. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1583. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1584. The method of claim 1570, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1585. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1586. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1587. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1588. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1589. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1590. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1591. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1592. The method of claim 1570, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1593. The method of claim 1570, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1594. The method of claim 1570, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1595. The method of claim 1570, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1596. The method of claim 1570, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1597. The method of claim 1570, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1598. The method of claim 1570, further comprising recirculating a
portion of the hydrogen within the mixture into the formation.
1599. The method of claim 1570, further comprising condensing a
hydrocarbon component from the produced mixture and hydrogenating
the condensed hydrocarbons with a portion of the hydrogen.
1600. The method of claim 1570, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1601. The method of claim 1570, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1602. The method of claim 1570, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1603. The method of claim 1570, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1604. The method of claim 1570, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1605. The method of claim 1570, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1606. The method of claim 1570, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1607. The method of claim 1570, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1608. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using an atomic
hydrogen weight percentage of at least a portion of hydrocarbons in
the selected section, and wherein at least the portion of the
hydrocarbons in the selected section comprises an atomic hydrogen
weight percentage, when measured on a dry, ash-free basis, of
greater than about 4.0%; and producing a mixture from the
formation.
1609. The method of claim 1608, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1610. The method of claim 1608, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1611. The method of claim 1608, wherein the one or more heat
sources comprise electrical heaters.
1612. The method of claim 1608, wherein the one or more heat
sources comprise surface burners.
1613. The method of claim 1608, wherein the one or more heat
sources comprise flameless distributed combustors.
1614. The method of claim 1608, wherein the one or more heat
sources comprise natural distributed combustors.
1615. The method of claim 1608, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1616. The method of claim 1608, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1617. The method of claim 1608, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1618. The method of claim 1608, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1619. The method of claim 1608, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1620. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1621. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1622. The method of claim 1608, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1623. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1624. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1625. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1626. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1627. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1628. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1629. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1630. The method of claim 1608, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1631. The method of claim 1608, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1632. The method of claim 1608, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1633. The method of claim 1608, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1634. The method of claim 1608, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1635. The method of claim 1608, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1636. The method of claim 1635, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1637. The method of claim 1608, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1638. The method of claim 1608, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1639. The method of claim 1608, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1640. The method of claim 1608, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1641. The method of claim 1608, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1642. The method of claim 1608, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1643. The method of claim 1608, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1644. The method of claim 1608, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1645. The method of claim 1608, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1646. The method of claim 1608, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1647. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
at least some hydrocarbons within the selected section have an
initial atomic hydrogen weight percentage of greater than about
4.0%; and producing a mixture from the formation.
1648. The method of claim 1647, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1649. The method of claim 1647, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1650. The method of claim 1647, wherein the one or more heat
sources comprise electrical heaters.
1651. The method of claim 1647, wherein the one or more heat
sources comprise surface burners.
1652. The method of claim 1647, wherein the one or more heat
sources comprise Blameless distributed combustors.
1653. The method of claim 1647, wherein the one or more heat
sources comprise natural distributed combustors.
1654. The method of claim 1647, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1655. The method of claim 1647, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1656. The method of claim 1647, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1657. The method of claim 1647, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1658. The method of claim 1647, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1659. The method of claim 1647, wherein the produced mixture
comprises condensable, hydrocarbons having an API gravity of at
least about 25.degree..
1660. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1661. The method of claim 1647, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1662. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1663. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1664. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1665. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1666. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1667. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1668. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1669. The method of claim 1647, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1670. The method of claim 1647, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1671. The method of claim 1647, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1672. The method of claim 1647, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1673. The method of claim 1647, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1674. The method of claim 1647, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1675. The method of claim 1674, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1676. The method of claim 1647, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1677. The method of claim 1647, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1678. The method of claim 1647, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1679. The method of claim 1647, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1680. The method of claim 1647, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1681. The method of claim 1647, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1682. The method of claim 1647, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1683. The method of claim 1647, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1684. The method of claim 1647, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1685. The method of claim 1647, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1686. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using vitrinite
reflectance of at least some hydrocarbons in the selected section,
and wherein at least a portion of the hydrocarbons in the selected
section comprises a vitrinite reflectance of greater than about
0.3%; wherein at least a portion of the hydrocarbons in the
selected section comprises a vitrinite reflectance of less than
about 4.5%; and producing a mixture from the formation.
1687. The method of claim 1686, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1688. The method of claim 1686, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature.
1689. The method of claim 1686, wherein the vitrinite reflectance
of at least the portion of hydrocarbons within the selected section
is between about 0.47% and about 1.5% such that a majority of the
produced mixture comprises condensable hydrocarbons.
1690. The method of claim 1686, wherein the vitrinite reflectance
of at least the portion of hydrocarbons within the selected section
is between about 1.4% and about 4.2% such that a majority of the
produced mixture comprises non-condensable hydrocarbons.
1691. The method of claim 1686, wherein the one or more heat
sources comprise electrical heaters.
1692. The method of claim 1686, wherein the one or more heat
sources comprise surface burners.
1693. The method of claim 1686, wherein the one or more heat
sources comprise flameless distributed combustors.
1694. The method of claim 1686, wherein the one or more heat
sources comprise natural distributed combustors.
1695. The method of claim 1686, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1696. The method of claim 1686, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1697. The method of claim 1686, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1698. The method of claim 1686, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1699. The method of claim 1686, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1700. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 250.
1701. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1702. The method of claim 1686, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1703. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1704. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1705. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1706. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1707. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1708. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1709. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1710. The method of claim 1686, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1711. The method of claim 1686, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1712. The method of claim 1686, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1713. The method of claim 1686, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1714. The method of claim 1686, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1715. The method of claim 1686, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1716. The method of claim 1715, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1717. The method of claim 1686, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1718. The method of claim 1686, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1719. The method of claim 1686, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1720. The method of claim 1686, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1721. The method of claim 1686, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1722. The method of claim 1686, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1723. The method of claim 1686, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1724. The method of claim 1686, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1725. The method of claim 1686, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1726. The method of claim 1686, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1727. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using a total
organic matter weight percentage of at least a portion of the
selected section, and wherein at least the portion of the selected
section comprises a total organic matter weight percentage, of at
least about 5.0%; and producing a mixture from the formation.
1728. The method of claim 1727, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1729. The method of claim 1727, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1730. The method of claim 1727, wherein the one or more heat
sources comprise electrical heaters.
1731. The method of claim 1727, wherein the one or more heat
sources comprise surface burners.
1732. The method of claim 1727, wherein the one or more heat
sources comprise flameless distributed combustors.
1733. The method of claim 1727, wherein the one or more heat
sources comprise natural distributed combustors.
1734. The method of claim 1727, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1735. The method of claim 1727, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about I .degree. C. per day during pyrolysis.
1736. The method of claim 1727, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation, and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1737. The method of claim 1727, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1738. The method of claim 1727, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1739. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1740. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1741. The method of claim 1727, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1742. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1743. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1744. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1745. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable, hydrocarbons comprise
oxygen containing compounds, and wherein the oxygen containing
compounds comprise phenols.
1746. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1747. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1748. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1749. The method of claim 1727, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1750. The method of claim 1727, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1751. The method of claim 1727, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1752. The method of claim 1727, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1753. The method of claim 1727, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1754. The method of claim 1727, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1755. The method of claim 1754, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1756. The method of claim 1727, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1757. The method of claim 1727, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1758. The method of claim 1727, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1759. The method of claim 1727, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1760. The method of claim 1727, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1761. The method of claim 1727, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1762. The method of claim 1727, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1763. The method of claim 1727, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1764. The method of claim 1727, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1765. The method of claim 1727, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1766. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
at least some hydrocarbons within the selected section have an
initial total organic matter weight percentage of at least about
5.0%; and producing a mixture from the formation.
1767. The method of claim 1766, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1768. The method of claim 1766, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1769. The method of claim 1766, wherein the one or more heat
sources comprise electrical heaters.
1770. The method of claim 1766, wherein the one or more heat
sources comprise surface burners.
1771. The method of claim 1766, wherein the one or more heat
sources comprise flameless distributed combustors.
1772. The method of claim 1766, wherein the one or more heat
sources comprise natural distributed combustors.
1773. The method of claim 1766, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1774. The method of claim 1766, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1775. The method of claim 1766, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1776. The method of claim 1766, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1777. The method of claim 1766, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1778. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1779. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1780. The method of claim 1766, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1781. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1782. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1783. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1784. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1785. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1786. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1787. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1788. The method of claim 1766, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1789. The method of claim 1766, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1790. The method of claim 1766, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1791. The method of claim 1766, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1792. The method of claim 1766, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1793. The method of claim 1766, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1794. The method of claim 1793, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1795. The method of claim 1766, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1796. The method of claim 1766, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1797. The method of claim 1766, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1798. The method of claim 1766, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1799. The method of claim 1766, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1800. The method of claim 1766, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1801. The method of claim 1766, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1802. The method of claim 1766, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1803. The method of claim 1766, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1804. The method of claim 1766, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1805. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using an atomic
oxygen weight percentage of at least a portion of hydrocarbons in
the selected section, and wherein at least a portion of the
hydrocarbons in the selected section comprises an atomic oxygen
weight percentage of less than about 15% when measured on a dry,
ash free basis; and producing a mixture from the formation.
1806. The method of claim 1805, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1807. The method of claim 1805, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1808. The method of claim 1805, wherein the one or more heat
sources comprise electrical heaters.
1809. The method of claim 1805, wherein the one or more heat
sources comprise surface burners.
1810. The method of claim 1805, wherein the one or more heat
sources comprise flameless distributed combustors.
1811. The method of claim 1805, wherein the one or more heat
sources comprise natural distributed combustors.
1812. The method of claim 1805, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1813. The method of claim 1805, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1814. The method of claim 1805, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1815. The method of claim 1805, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1816. The method of claim 1805, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1817. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1818. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1819. The method of claim 1805, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1820. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1821. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1822. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1823. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1824. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1825. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1826. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1827. The method of claim 1805, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1828. The method of claim 1805, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1829. The method of claim 1805, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1830. The method of claim 1805, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1831. The method of claim 1805, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1832. The method of claim 1805, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1833. The method of claim 1832, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1834. The method of claim 1805, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1835. The method of claim 1805, further comprising controlling
formation conditions by recirculating a portion of hydrogen from,
the mixture into the formation.
1836. The method of claim 1805, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1837. The method of claim 1805, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1838. The method of claim 1805, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1839. The method of claim 1805, wherein allowing the heat to
transfer further comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1840. The method of claim 1805, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1841. The method of claim 1805, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1842. The method of claim 1805, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1843. The method of claim 1805, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1844. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to a selected section
of the formation; allowing the heat to transfer from the one or
more heat sources to the selected section of the formation to
pyrolyze hydrocarbon within the selected section; wherein at least
some hydrocarbons within the selected section have an initial
atomic oxygen weight percentage of less than about 15%; and
producing a mixture from the formation.
1845. The method of claim 1844, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1846. The method of claim 1844, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range
1847. The method of claim 1844, wherein the one or more heat
sources comprise electrical heaters.
1848. The method of claim 1844, wherein the one or more heat
sources comprise surface burners.
1849. The method of claim 1844, wherein the one or more heat
sources comprise flameless distributed combustors.
1850. The method of claim 1844, wherein the one or more heat
sources comprise natural distributed combustors.
1851. The method of claim 1844, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1852. The method of claim 1844, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1853. The method of claim 1844, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1854. The method of claim 1844, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1855. The method of claim 1844, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1856. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1857. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1858. The method of claim 1844, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1859. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1860. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1861. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1862. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1863. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1864. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1865. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1866. The method of claim 1844, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1867. The method of claim 1844, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1868. The method of claim 1844, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1869. The method of claim 1844, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1870. The method of claim 1844, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1871. The method of claim 1844, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1872. The method of claim 1871, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1873. The method of claim 1844, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1874. The method of claim 1844, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1875. The method of claim 1844, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1876. The method of claim 1844, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1877. The method of claim 1844, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1878. The method of claim 1844, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1879. The method of claim 1844, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1880. The method of claim 1844, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1881. The method of claim 1844, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1882. The method of claim 1844, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1883. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using an atomic
hydrogen to carbon ratio of at least a portion of hydrocarbons in
the selected section, wherein at least a portion of the
hydrocarbons in the selected section comprises an atomic hydrogen
to carbon ratio greater than about 0.70, and wherein the atomic
hydrogen to carbon ratio is less than about 1.65; and producing a
mixture from the formation.
1884. The method of claim 1883, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1885. The method of claim 1883, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1886. The method of claim 1883, wherein the one or more heat
sources comprise electrical heaters.
1887. The method of claim 1883, wherein the one or more heat
sources comprise surface burners.
1888. The method of claim 1883, wherein the one or more heat
sources comprise flameless distributed combustors.
1889. The method of claim 1883, wherein the one or more heat
sources comprise natural distributed combustors.
1890. The method of claim 1883, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1891. The method of claim 1883, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1892. The method of claim 1883, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1893. The method of claim 1883, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1894. The method of claim 1883, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1895. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1896. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1897. The method of claim 1883, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1898. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1899. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1900. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1901. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1902. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1903. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1904. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1905. The method of claim 1883, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1906. The method of claim 1883, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1907. The method of claim 1883, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1908. The method of claim 1883, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1909. The method of claim 1883, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1910. The method of claim 1883, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1911. The method of claim 1910, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1912. The method of claim 1883, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1913. The method of claim 1883, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1914. The method of claim 1883, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1915. The method of claim 1883, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1916. The method of claim 1883, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1917. The method of claim 1883, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1918. The method of claim 1883, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1919. The method of claim 1883, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1920. The method of claim 1883, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1921. The method of claim 1883, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1922. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to a selected section
of the formation; allowing the heat to transfer from the one or
more heat sources to the selected section of the formation to
pyrolyze hydrocarbons within the selected section; wherein at least
some hydrocarbons within the selected section have an initial
atomic hydrogen to carbon ratio greater than about 0.70; wherein
the initial atomic hydrogen to carbon ration is less than about
1.65; and producing a mixture from the formation.
1923. The method of claim 1922, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1924. The method of claim 1922, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1925. The method of claim 1922, wherein the one or more heat
sources comprise electrical heaters.
1926. The method of claim 1922, wherein the one or more heat
sources comprise surface burners.
1927. The method of claim 1922, wherein the one or more heat
sources comprise flameless distributed combustors.
1928. The method of claim 1922, wherein the one or more heat
sources comprise natural distributed combustors.
1929. The method of claim 1922, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1930. The method of claim 1922, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1931. The method of claim 1922, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1932. The method of claim 1922, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1933. The method of claim 1922, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1934. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1935. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1936. The method of claim 1922, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1937. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1938. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1939. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1940. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1941. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1942. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1943. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1944. The method of claim 1922, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1945. The method of claim 1922, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1946. The method of claim 1922, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1947. The method of claim 1922, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1948. The method of claim 1922, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1949. The method of claim 1922, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1950. The method of claim 1949, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1951. The method of claim 1922, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1952. The method of claim 1922, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1953. The method of claim 1922, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1954. The method of claim 1922, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1955. The method of claim 1922, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1956. The method of claim 1922, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1957. The method of claim 1922, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1958. The method of claim 1922, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1959. The method of claim 1922, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1960. The method of claim 1922, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
1961. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using an atomic
oxygen to carbon ratio of at least a portion of hydrocarbons in the
selected section, wherein at least a portion of the hydrocarbons in
the selected section comprises an atomic oxygen to carbon ratio
greater than about 0.025, and wherein the atomic oxygen to carbon
ratio of at least a portion of the hydrocarbons in the selected
section is less than about 0.15 and producing a mixture from the
formation.
1962. The method of claim 1961, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
1963. The method of claim 1961, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
1964. The method of claim 1961, wherein the one or more heat
sources comprise electrical heaters.
1965. The method of claim 1961, wherein the one or more heat
sources comprise surface burners.
1966. The method of claim 1961, wherein the one or more heat
sources comprise flameless distributed combustors.
1967. The method of claim 1961, wherein the one or more heat
sources comprise natural distributed combustors.
1968. The method of claim 1961, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
1969. The method of claim 1961, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
1970. The method of claim 1961, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
1971. The method of claim 1961, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
1972. The method of claim 1961, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
1973. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
1974. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
1975. The method of claim 1961, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
1976. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
1977. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
1978. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
1979. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
1980. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
1981. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
1982. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
1983. The method of claim 1961, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
1984. The method of claim 1961, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
1985. The method of claim 1961, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
1986. The method of claim 1961, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
1987. The method of claim 1961, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
1988. The method of claim 1961, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
1989. The method of claim 1988, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
1990. The method of claim 1961, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
1991. The method of claim 1961, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
1992. The method of claim 1961, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
1993. The method of claim 1961, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
1994. The method of claim 1961, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
1995. The method of claim 1961, wherein allowing the heat to
transfer further comprises substantially uniformly increasing a
permeability of a majority of the selected section.
1996. The method of claim 1961, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
1997. The method of claim 1961, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
1998. The method of claim 1961, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
1999. The method of claim 1961, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2000. A method of treating a coal formation in situ, comprising
providing heat from one or more heat sources to a selected section
of the formation; allowing the heat to transfer from the one or
more heat sources to the selected section of the formation to
pyrolyze hydrocarbons within the selected section; wherein at least
some hydrocarbons within the selected section have an initial
atomic oxygen to carbon ratio greater than about 0.025; wherein the
initial atomic oxygen to carbon ratio is less than about 0.15; and
producing a mixture from the formation.
2001. The method of claim 2000, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2002. The method of claim 2000, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2003. The method of claim 2000, wherein the one or more heat
sources comprise electrical heaters.
2004. The method of claim 2000, wherein the one or more heat
sources comprise surface burners.
2005. The method of claim 2000, wherein the one or more heat
sources comprise flameless distributed combustors.
2006. The method of claim 2000, wherein the one or more heat
sources comprise natural distributed combustors.
2007. The method of claim 2000, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2008. The method of claim 2000, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2009. The method of claim 2000, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2010. The method of claim 2000, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2011. The method of claim 2000, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2012. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 250.
2013. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2014. The method of claim 2000, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2015. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2016. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2017. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2018. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2019. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2020. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2021. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2022. The method of claim 2000, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2023. The method of claim 2000, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2024. The method of claim 2000, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2025. The method of claim 2000, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2026. The method of claim 2000, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2027. The method of claim 2000, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2028. The method of claim 2027, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2029. The method of claim 2000, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2030. The method of claim 2000, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2031. The method of claim 2000, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2032. The method of claim 2000, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2033. The method of claim 2000, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2034. The method of claim 2000, wherein allowing the heat to
transfer further comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2035. The method of claim 2000, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2036. The method of claim 2000, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2037. The method of claim 2000, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2038. The method of claim 2000, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2039. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section has been selected for heating using a moisture
content in the selected section, and wherein at least a portion of
the selected section comprises a moisture content of less than
about 15%; and producing a mixture from the formation.
2040. The method of claim 2039, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2041. The method of claim 2039, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2042. The method of claim 2039, wherein the one or more heat
sources comprise electrical heaters.
2043. The method of claim 2039, wherein the one or more heat
sources comprise surface burners.
2044. The method of claim 2039, wherein the one or more heat
sources comprise flameless distributed combustors.
2045. The method of claim 2039, wherein the one or more heat
sources comprise natural distributed combustors.
2046. The method of claim 2039, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2047. The method of claim 2039, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2048. The method of claim 2039, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2049. The method of claim 2039, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2050. The method of claim 2039, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2051. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2052. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2053. The method of claim 2039, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2054. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2055. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2056. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2057. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2058. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2059. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2060. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2061. The method of claim 2039, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2062. The method of claim 2039, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2063. The method of claim 2039, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2064. The method of claim 2039, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2065. The method of claim 2039, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2066. The method of claim 2039, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2067. The method of claim 2066, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2068. The method of claim 2039, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2069. The method of claim 2039, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2070. The method of claim 2039, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2071. The method of claim 2039, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2072. The method of claim 2039, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2073. The method of claim 2039, wherein allowing the heat to
transfer further comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2074. The method of claim 2039, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2075. The method of claim 2039, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2076. The method of claim 2039, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2077. The method of claim 2039, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2078. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to a selected section
of the formation; allowing the heat to transfer from the one or
more heat sources to the selected section of the formation; wherein
at least a portion of the selected section has an initial moisture
content of less than about 15%; and producing a mixture from the
formation.
2079. The method of claim 2078, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2080. The method of claim 2078, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2081. The method of claim 2078, wherein the one or more heat
sources comprise electrical heaters.
2082. The method of claim 2078, wherein the one or more heat
sources comprise surface burners.
2083. The method of claim 2078, wherein the one or more heat
sources comprise flameless distributed combustors.
2084. The method of claim 2078, wherein the one or more heat
sources comprise natural distributed combustors.
2085. The method of claim 2078, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2086. The method of claim 2078, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2087. The method of claim 2078, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2088. The method of claim 2078, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2089. The method of claim 2078, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2090. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2091. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2092. The method of claim 2078, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2093. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2094. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2095. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2096. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2097. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2098. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2099. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2100. The method of claim 2078, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2101. The method of claim 2078, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2102. The method of claim 2078, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2103. The method of claim 2078, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2104. The method of claim 2078, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2105. The method of claim 2078, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2106. The method of claim 2105, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2107. The method of claim 2078, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2108. The method of claim 2078, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2109. The method of claim 2078, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2110. The method of claim 2078, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2111. The method of claim 2078, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2112. The method of claim 2078, wherein allowing the heat to
transfer further comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2113. The method of claim 2078, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2114. The method of claim 2078, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2115. The method of claim 2078, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2116. The method of claim 2078, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2117. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; wherein
the selected section is heated in a reducing environment during at
least a portion of the time that the selected section is being
heated; and producing a mixture from the formation.
2118. The method of claim 2117, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2119. The method of claim 2117, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2120. The method of claim 2117, wherein the one or more heat
sources comprise electrical heaters.
2121. The method of claim 2117, wherein the one or more heat
sources comprise surface burners.
2122. The method of claim 2117, wherein the one or more heat
sources comprise flameless distributed combustors.
2123. The method of claim 2117, wherein the one or more heat
sources comprise natural distributed combustors.
2124. The method of claim 2117, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2125. The method of claim 2117, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2126. The method of claim 2117, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2127. The method of claim 2117, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2128. The method of claim 2117, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2129. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2130. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2131. The method of claim 2117, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2132. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2133. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2134. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2135. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2136. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2137. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2138. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2139. The method of claim 2117, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2140. The method of claim 2117, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2141. The method of claim 2117, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2142. The method of claim 2117, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2143. The method of claim 2117, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2144. The method of claim 2117, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2145. The method of claim 2144, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2146. The method of claim 2117, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2147. The method of claim 2117, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2148. The method of claim 2117, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2149. The method of claim 2117, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2150. The method of claim 2117, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2151. The method of claim 2117, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2152. The method of claim 2117, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2153. The method of claim 2117, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2154. The method of claim 2117, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2155. The method of claim 2117, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2156. A method of treating a coal formation in situ, comprising:
heating a first section of the formation to produce a mixture from
the formation; heating a second section of the formation; and
recirculating a portion of the produced mixture from the first
section into the second section of the formation to provide a
reducing environment within the second section of the
formation.
2157. The method of claim 2156, further comprising maintaining a
temperature within the first section or the second section within a
pyrolysis temperature range.
2158. The method of claim 2156, wherein heating the first or the
second section comprises heating with an electrical heater.
2159. The method of claim 2156, wherein heating the first or the
second section comprises heating with a surface burner.
2160. The method of claim 2156, wherein heating the first or the
second section comprises heating with a flameless distributed
combustor.
2161. The method of claim 2156, wherein heating the first or the
second section comprises heating with a natural distributed
combustor.
2162. The method of claim 2156, further comprising controlling a
pressure and a temperature within at least a majority of the first
or second section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2163. The method of claim 2156, further comprising controlling the
heat such that an average heating rate of the first or the second
section is less than about 1.degree. C. per day during
pyrolysis.
2164. The method of claim 2156, wherein heating the first or the
second section comprises: heating a selected volume (V) of the coal
formation from one or more heat sources, wherein the formation has
an average heat capacity (C.sub.v), and wherein the heating
pyrolyzes at least some hydrocarbons within the selected volume of
the formation; and wherein heating energy/day provided to the
volume is equal to or less than Pwr, wherein Pwr is calculated by
the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
2165. The method of claim 2156, wherein heating the first or the
second section comprises transferring heat substantially by
conduction.
2166. The method of claim 2156, wherein heating the first or the
second section comprises heating the first or the second section
such that a thermal conductivity of at least a portion of the first
or the second section is greater than about 0.5 W/(m.degree.
C.).
2167. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2168. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2169. The method of claim 2156, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2170. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2171. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2172. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2173. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2174. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2175. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2176. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2177. The method of claim 2156, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2178. The method of claim 2156, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2179. The method of claim 2156, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2180. The method of claim 2156, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2181. The method of claim 2156, further comprising controlling a
pressure within at least a majority of the first or second section
of the formation, wherein the controlled pressure is at least about
2.0 bar absolute.
2182. The method of claim 2156, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2183. The method of claim 2182, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2184. The method of claim 2156, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2185. The method of claim 2156, further comprising: providing
hydrogen (H.sub.2) to the first or second section to hydrogenate
hydrocarbons within the first or second section; and heating a
portion of the first or second section with heat from
hydrogenation.
2186. The method of claim 2156, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2187. The method of claim 2156, wherein heating the first or the
second section comprises increasing a permeability of a majority of
the first or the second section to greater than about 100
millidarcy.
2188. The method of claim 2156, wherein heating the first or the
second section comprises substantially uniformly increasing a
permeability of a majority of the first or the second section.
2189. The method of claim 2156, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2190. The method of claim 2156, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2191. The method of claim 2156, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2192. The method of claim 2156, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2193. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; and allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
a permeability of at least a portion of the selected section
increases to greater than about 100 millidarcy.
2194. The method of claim 2193, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2195. The method of claim 2193, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2196. The method of claim 2193, wherein the one or more heat
sources comprise electrical heaters.
2197. The method of claim 2193, wherein the one or more heat
sources comprise surface burners.
2198. The method of claim 2193, wherein the one or more heat
sources comprise flameless distributed combustors.
2199. The method of claim 2193, wherein the one or more heat
sources comprise natural distributed combustors.
2200. The method of claim 2193, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2201. The method of claim 2193, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2202. The method of claim 2193, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2203. The method of claim 2193, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2204. The method of claim 2193, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2205. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2206. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2207. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2208. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2209. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2210. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2211. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2212. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2213. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2214. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2215. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2216. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2217. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2218. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2219. The method of claim 2193, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2220. The method of claim 2193, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2221. The method of claim 2220, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2222. The method of claim 2193, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2223. The method of claim 2193, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2224. The method of claim 2193, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2225. The method of claim 2193, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2226. The method of claim 2193, further comprising increasing a
permeability of a majority of the selected section to greater than
about 5 Darcy.
2227. The method of claim 2193, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2228. The method of claim 2193, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2229. The method of claim 2193, further comprising producing a
mixture in a production well, wherein at least about 7 heat sources
are disposed in the formation for each production well.
2230. The method of claim 2193, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2231. The method of claim 2193, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2232. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; and allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
a permeability of a majority of at least a portion of the selected
section increases substantially uniformly.
2233. The method of claim 2232, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2234. The method of claim 2232, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2235. The method of claim 2232, wherein the one or more heat
sources comprise electrical heaters.
2236. The method of claim 2232, wherein the one or more heat
sources comprise surface burners.
2237. The method of claim 2232, wherein the one or more heat
sources comprise flameless distributed combustors.
2238. The method of claim 2232, wherein the one or more heat
sources comprise natural distributed combustors.
2239. The method of claim 2232, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2240. The method of claim 2232, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2241. The method of claim 2232, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2242. The method of claim 2232, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2243. The method of claim 2232, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2244. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2245. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2246. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2247. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2248. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2249. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2250. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2251. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2252. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2253. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2254. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2255. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2256. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2257. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2258. The method of claim 2232, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2259. The method of claim 2232, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2260. The method of claim 2232, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2261. The method of claim 2232, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2262. The method of claim 2232, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2263. The method of claim 2232, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2264. The method of claim 2232, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2265. The method of claim 2232, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2266. The method of claim 2232, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2267. The method of claim 2232, further comprising producing a
mixture in a production well, wherein at least about 7 heat sources
are disposed in the formation for each production well.
2268. The method of claim 2232, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2269. The method of claim 2232, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2270. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; and allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
a porosity of a majority of at least a portion of the selected
section increases substantially uniformly.
2271. The method of claim 2270, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2272. The method of claim 2270, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2273. The method of claim 2270, wherein the one or more heat
sources comprise electrical heaters.
2274. The method of claim 2270, wherein the one or more heat
sources comprise surface burners.
2275. The method of claim 2270, wherein the one or more heat
sources comprise flameless distributed combustors.
2276. The method of claim 2270, wherein the one or more heat
sources comprise natural distributed combustors.
2277. The method of claim 2270, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2278. The method of claim 2270, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2279. The method of claim 2270, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2280. The method of claim 2270, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2281. The method of claim 2270, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2282. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2283. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2284. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2285. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2286. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2287. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2288. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2289. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2290. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2291. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2292. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2293. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2294. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2295. The method of claim 2270, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2296. The method of claim 2270, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2297. The method of claim 2270, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2298. The method of claim 2193, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2299. The method of claim 2193, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2300. The method of claim 2193, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2301. The method of claim 2270, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2302. The method of claim 2270, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2303. The method of claim 2270, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2304. The method of claim 2270, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2305. The method of claim 2270, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2306. The method of claim 2270, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2307. The method of claim 2270, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2308. The method of claim 2270, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2309. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
controlling the heat to yield at least about 15% by weight of a
total organic carbon content of at least some of the coal formation
into condensable hydrocarbons.
2310. The method of claim 2309, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2311. The method of claim 2309, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2312. The method of claim 2309, wherein the one or more heat
sources comprise electrical heaters.
2313. The method of claim 2309, wherein the one or more heat
sources comprise surface burners.
2314. The method of claim 2309, wherein the one or more heat
sources comprise flameless distributed combustors.
2315. The method of claim 2309, wherein the one or more heat
sources comprise natural distributed combustors.
2316. The method of claim 2309, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2317. The method of claim 2309, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2318. The method of claim 2309, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2319. The method of claim 2309, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2320. The method of claim 2309, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2321. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2322. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2323. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2324. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2325. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2326. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2327. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2328. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2329. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2330. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2331. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2332. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2333. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2334. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2335. The method of claim 2309, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2336. The method of claim 2309, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2337. The method of claim 2309, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2338. The method of claim 2309, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2339. The method of claim 2309, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2340. The method of claim 2309, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2341. The method of claim 2309, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2342. The method of claim 2309, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2343. The method of claim 2309, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2344. The method of claim 2309, wherein the heating is controlled
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2345. The method of claim 2309, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2346. The method of claim 2309, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2347. The method of claim 2309, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2348. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
controlling the heat to yield greater than about 60% by weight of
condensable hydrocarbons, as measured by Fischer Assay.
2349. The method of claim 2348, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2350. The method of claim 2348, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2351. The method of claim 2348, wherein the one or more heat
sources comprise electrical heaters.
2352. The method of claim 2348, wherein the one or more heat
sources comprise surface burners.
2353. The method of claim 2348, wherein the one or more heat
sources comprise flameless distributed combustors.
2354. The method of claim 2348, wherein the one or more heat
sources comprise natural distributed combustors.
2355. The method of claim 2348, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2356. The method of claim 2348, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2357. The method of claim 2348, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2358. The method of claim 2348, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2359. The method of claim 2348, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2360. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2361. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2362. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2363. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2364. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2365. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2366. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2367. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2368. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2369. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2370. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2371. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2372. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2373. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2374. The method of claim 2348, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2375. The method of claim 2348, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2376. The method of claim 2348, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2377. The method of claim 2348, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2378. The method of claim 2348, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2379. The method of claim 2348, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2380. The method of claim 2348, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2381. The method of claim 2348, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2382. The method of claim 2348, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2383. The method of claim 2348, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2384. The method of claim 2348, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2385. The method of claim 2348, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2386. A method of treating a coal formation in situ, comprising:
heating a first section of the formation to pyrolyze at least some
hydrocarbons in the first section and produce a first mixture from
the formation; heating a second section of the formation to
pyrolyze at least some hydrocarbons in the second section and
produce a second mixture from the formation; and leaving an
unpyrolyzed section between the first section and the second
section to inhibit subsidence of the formation.
2387. The method of claim 2386, further comprising maintaining a
temperature within the first section or the second section within a
pyrolysis temperature range.
2388. The method of claim 2386, wherein heating the first section
or heating the second section comprises heating with an electrical
heater.
2389. The method of claim 2386, wherein heating the first section
or heating the second section comprises heating with a surface
burner.
2390. The method of claim 2386, wherein heating the first section
or heating the second section comprises heating with a flameless
distributed combustor.
2391. The method of claim 2386, wherein heating the first section
or heating the second section comprises heating with a natural
distributed combustor.
2392. The method of claim 2386, further comprising controlling a
pressure and a temperature within at least a majority of the first
or second section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2393. The method of claim 2386, further comprising controlling the
heat such that an average heating rate of the first or second
section is less than about 1.degree. C. per day during
pyrolysis.
2394. The method of claim 2386, wherein heating the first section
or heating the second section comprises: heating a selected volume
(V) of the coal formation from one or more heat sources, wherein
the formation has an average heat capacity (C.sub.v), and wherein
the heating pyrolyzes at least some hydrocarbons within the
selected volume of the formation; and wherein heating energy/day
provided to the volume is equal to or less than Pwr, wherein Pwr is
calculated by the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr
is the heating energy/day, h is an average heating rate of the
formation, .rho..sub.B is formation bulk density, and wherein the
heating rate is less than about 10.degree. C./day.
2395. The method of claim 2386, wherein heating the first section
or heating the second section comprises transferring heat
substantially by conduction.
2396. The method of claim 2386, wherein heating the first section
or heating the second section comprises heating the formation such
that a thermal conductivity of at least a portion of the first or
second section, respectively, is greater than about 0.5
W/(m.degree. C.).
2397. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2398. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2399. The method of claim 2386, wherein the first or second mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2400. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2401. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2402. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2403. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2404. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2405. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2406. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2407. The method of claim 2386, wherein the first or second mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2408. The method of claim 2386, wherein the first or second mixture
comprises a non-condensable component, and wherein the
non-condensable component comprises hydrogen, and wherein the
hydrogen is greater than about 10% by volume of the non-condensable
component and wherein the hydrogen is less than about 80% by volume
of the non-condensable component.
2409. The method of claim 2386, wherein the first or second mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the first or second mixture is ammonia.
2410. The method of claim 2386, wherein the first or second mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2411. The method of claim 2386, further comprising controlling a
pressure within at least a majority of the first or second section
of the formation, wherein the controlled pressure is at least about
2.0 bar absolute.
2412. The method of claim 2386, further comprising controlling
formation conditions to produce the first or second mixture,
wherein a partial pressure of H.sub.2 within the first or second
mixture is greater than about 0.5 bar.
2413. The method of claim 2386, wherein a partial pressure of
H.sub.2 within the first or second mixture is measured when the
first or second mixture is at a production well.
2414. The method of claim 2386, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2415. The method of claim 2386, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the first or second mixture into the formation.
2416. The method of claim 2386, further comprising: providing
hydrogen (H.sub.2) to the first or second section to hydrogenate
hydrocarbons within the first or second section, respectively; and
heating a portion of the first or second section, respectively,
with heat from hydrogenation.
2417. The method of claim 2386, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2418. The method of claim 2386, wherein heating the first section
or heating the second section comprises increasing a permeability
of a majority of the first or second section, respectively, to
greater than about 100 millidarcy.
2419. The method of claim 2386, wherein heating the first section
or heating the second section comprises substantially uniformly
increasing a permeability of a majority of the first or second
section, respectively.
2420. The method of claim 2386, further comprising controlling
heating of the first or second section to yield greater than about
60% by weight of condensable hydrocarbons, as measured by Fischer
Assay, from the first or second section, respectively.
2421. The method of claim 2386, wherein producing the first or
second mixture comprises producing the first or second mixture in a
production well, and wherein at least about 7 heat sources are
disposed in the formation for each production well.
2422. The method of claim 2386, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2423. The method of claim 2386, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2424. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation through one or more
production wells, wherein the heating is controlled such that the
mixture can be produced from the formation as a vapor, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2425. The method of claim 2424, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2426. The method of claim 2424, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2427. The method of claim 2424, wherein the one or more heat
sources comprise electrical heaters.
2428. The method of claim 2424, wherein the one or more heat
sources comprise surface burners.
2429. The method of claim 2424, wherein the one or more heat
sources comprise flameless distributed combustors.
2430. The method of claim 2424, wherein the one or more heat
sources comprise natural distributed combustors.
2431. The method of claim 2424, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2432. The method of claim 2424, her comprising controlling the heat
such that an average heating rate of the selected section is less
than about 1.degree. C. per day during pyrolysis.
2433. The method of claim 2424, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2434. The method of claim 2424, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2435. The method of claim 2424, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2436. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2437. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2438. The method of claim 2424, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2439. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2440. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2441. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2442. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2443. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2444. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2445. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2446. The method of claim 2424, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2447. The method of claim 2424, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2448. The method of claim 2424, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2449. The method of claim 2424, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2450. The method of claim 2424, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2451. The method of claim 2424, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2452. The method of claim 2452, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2453. The method of claim 2424, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2454. The method of claim 2424, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2455. The method of claim 2424, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2456. The method of claim 2424, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2457. The method of claim 2424, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2458. The method of claim 2424, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2459. The method of claim 2424, wherein the heating is controlled
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2460. The method of claim 2424, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2461. The method of claim 2424, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2462. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation, wherein the one or more heat sources are disposed
within one or more first wells; allowing the heat to transfer from
the one or more heat sources to a selected section of the
formation; and producing a mixture from the formation through one
or more second wells, wherein one or more of the first or second
wells are initially used for a first purpose and are then used for
one or more other purposes.
2463. The method of claim 2462, wherein the first purpose comprises
removing water from the formation, and wherein the second purpose
comprises providing heat to the formation.
2464. The method of claim 2462, wherein the first purpose comprises
removing water from the formation, and wherein the second purpose
comprises producing the mixture.
2465. The method of claim 2462, wherein the first purpose comprises
heating, and wherein the second purpose comprises removing water
from the formation.
2466. The method of claim 2462, wherein the first purpose comprises
producing the mixture, and wherein the second purpose comprises
removing water from the formation.
2467. The method of claim 2462, wherein the one or more heat
sources comprise electrical heaters.
2468. The method of claim 2462, wherein the one or more heat
sources comprise surface burners.
2469. The method of claim 2462, wherein the one or more heat
sources comprise flameless distributed combustors.
2470. The method of claim 2462, wherein the one or more heat
sources comprise natural distributed combustors.
2471. The method of claim 2462, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2472. The method of claim 2462, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.0.degree. C. per day during pyrolysis.
2473. The method of claim 2462, wherein providing heat from the one
or more heat sources to at least the portion of the formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2474. The method of claim 2462, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2475. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2476. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2477. The method of claim 2462, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2478. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2479. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen
2480. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2481. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2482. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2483. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2484. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2485. The method of claim 2462, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2486. The method of claim 2462, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2487. The method of claim 2462, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2488. The method of claim 2462, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2489. The method of claim 2462, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2490. The method of claim 2462, further comprising controlling
formation conditions to produce a mixture of condensable
hydrocarbons and H.sub.2, wherein a partial pressure of H.sub.2
within the mixture is greater than about 0.5 bar.
2491. The method of claim 2490, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
2492. The method of claim 2462, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2493. The method of claim 2462, further comprising controlling
formation conditions, wherein controlling formation conditions
comprises recirculating a portion of hydrogen from the mixture into
the formation.
2494. The method of claim 2462, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2495. The method of claim 2462, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
2496. The method of claim 2462, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2497. The method of claim 2462, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2498. The method of claim 2462, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2499. The method of claim 2462, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2500. The method of claim 2462, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2501. The method of claim 2462, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2502. A method for forming heater wells in a coal formation,
comprising: forming a first wellbore in the formation; forming a
second wellbore in the formation using magnetic tracking such that
the second wellbore is arranged substantially parallel to the first
wellbore; and providing at least one heating mechanism within the
first wellbore and at least one heating mechanism within the second
wellbore such that the heating mechanisms can provide heat to at
least a portion of the formation.
2503. The method of claim 2502, wherein superposition of heat from
the at least one heating mechanism within the first wellbore and
the at least one heating mechanism within the second wellbore
pyrolyzes at least some hydrocarbons within a selected section of
the formation.
2504. The method of claim 2502, further comprising maintaining a
temperature within a selected section within a pyrolysis
temperature range.
2505. The method of claim 2502, wherein the heating mechanisms
comprise electrical heaters.
2506. The method of claim 2502, wherein the heating mechanisms
comprise surface burners.
2507. The method of claim 2502, wherein the heating mechanisms
comprise flameless distributed combustors.
2508. The method of claim 2502, wherein the heating mechanisms
comprise natural distributed combustors.
2509. The method of claim 2502, further comprising controlling a
pressure and a temperature within at least a majority of a selected
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
2510. The method of claim 2502, further comprising controlling the
heat from the heating mechanisms such that heat transferred from
the heating mechanisms to at least the portion of the hydrocarbons
is less than about 1.degree. C. per day during pyrolysis.
2511. The method of claim 2502, further comprising: heating a
selected volume (V) of the coal formation from the heating
mechanisms, wherein the formation has an average heat capacity
(C.sub.v), and wherein the heating pyrolyzes at least some
hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2512. The method of claim 2502, further comprising allowing the
heat to transfer from the heating mechanisms to at least the
portion of the formation substantially by conduction.
2513. The method of claim 2502, further comprising providing heat
from the heating mechanisms to at least the portion of the
formation such that a thermal conductivity of at least the portion
of the formation is greater than about 0.5 W/(m.degree. C.).
2514. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2515. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2516. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2517. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2518. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2519. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2520. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2521. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2522. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2523. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2524. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2525. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2526. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2527. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2528. The method of claim 2502, further comprising controlling a
pressure within at least a majority of a selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2529. The method of claim 2528, wherein the partial pressure of
H.sub.2 within the mixture is greater than about 0.5 bar.
2530. The method of claim 2502, further comprising producing a
mixture from the formation, wherein the partial pressure of H.sub.2
within the mixture is measured when the mixture is at a production
well.
2531. The method of claim 2502, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2532. The method of claim 2502, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2533. The method of claim 2502, further comprising: providing
hydrogen (H.sub.2) to the portion to hydrogenate hydrocarbons
within the formation; and heating a portion of the formation with
heat from hydrogenation.
2534. The method of claim 2502, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2535. The method of claim 2502, further comprising allowing heat to
transfer from the heating mechanisms to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of a
selected section of the formation increases to greater than about
100 millidarcy.
2536. The method of claim 2502, further comprising allowing heat to
transfer from the heating mechanisms to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of the
selected section increases substantially uniformly.
2537. The method of claim 2502, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2538. The method of claim 2502, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2539. The method of claim 2502, further comprising forming a
production well in the formation using magnetic tracking such that
the production well is substantially parallel to the first wellbore
and coupling a wellhead to the third wellbore.
2540. The method of claim 2502, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2541. The method of claim 2502, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2542. A method for installing a heater well into a coal formation,
comprising: forming a bore in the ground using a steerable motor
and an accelerometer; and providing a heating mechanism within the
bore such that the heating mechanism can transfer heat to at least
a portion of the formation.
2543. The method of claim 2542, further comprising installing at
least two heater wells, and wherein superposition of heat from at
least the two heater wells pyrolyzes at least some hydrocarbons
within a selected section of the formation.
2544. The method of claim 2542, further comprising maintaining a
temperature within a selected section within a pyrolysis
temperature range.
2545. The method of claim 2542, wherein the heating mechanism
comprises an electrical heater.
2546. The method of claim 2542, wherein the heating mechanism
comprises a surface burner.
2547. The method of claim 2542, wherein the heating mechanism
comprises a flameless distributed combustor.
2548. The method of claim 2542, wherein the heating mechanism
comprises a natural distributed combustor.
2549. The method of claim 2542, further comprising controlling a
pressure and a temperature within at least a majority of a selected
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
2550. The method of claim 2542, further comprising controlling the
heat from the heating mechanism such that heat transferred from the
heating mechanism to at least the portion of the formation is less
than about 1.degree. C. per day during pyrolysis.
2551. The method of claim 2542, further comprising: heating a
selected volume (V) of the coal formation from the heating
mechanism, wherein the formation has an average heat capacity
(C.sub.v), and wherein the heating pyrolyzes at least some
hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2552. The method of claim 2542, further comprising allowing the
heat to transfer from the heating mechanism to at least the portion
of the formation substantially by conduction.
2553. The method of claim 2542, further comprising providing heat
from the heating mechanism to at least the portion of the formation
such that a thermal conductivity of at least the portion of the
formation is greater than about 0.5 W/(m.degree. C.).
2554. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2555. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2556. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2557. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2558. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2559. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2560. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2561. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2562. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2563. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2564. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2565. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2566. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2567. The method of claim 2542, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2568. The method of claim 2542, further comprising controlling a
pressure within at least a majority of a selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2569. The method of claim 2542, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2570. The method of claim 2569, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2571. The method of claim 2542, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2572. The method of claim 2542, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2573. The method of claim 2542, further comprising: providing
hydrogen (H.sub.2) to the at least the heated portion to
hydrogenate hydrocarbons within the formation; and heating a
portion of the formation with heat from hydrogenation.
2574. The method of claim 2542, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2575. The method of claim 2542, further comprising allowing heat to
transfer from the heating mechanism to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of a
selected section of the formation increases to greater than about
100 millidarcy.
2576. The method of claim 2542, further comprising allowing heat to
transfer from the heating mechanism to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of the
selected section increases substantially uniformly.
2577. The method of claim 2542, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2578. The method of claim 2542, further comprising producing a
mixture in a production well, and wherein at least about 7 heating
mechanisms are disposed in the formation for each production
well.
2579. The method of claim 2542, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2580. The method of claim 2542, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2581. A method for installing of wells in a coal formation,
comprising: forming a wellbore in the formation by geosteered
drilling; and providing a heating mechanism within the wellbore
such that the heating mechanism can transfer heat to at least a
portion of the formation.
2582. The method of claim 2581, further comprising maintaining a
temperature within a selected section within a pyrolysis
temperature range.
2583. The method of claim 2581, wherein the heating mechanism
comprises an electrical heater.
2584. The method of claim 2581, wherein the heating mechanism
comprises a surface burner.
2585. The method of claim 2581, wherein the heating mechanism
comprises a flameless distributed combustor.
2586. The method of claim 2581, wherein the heating mechanism
comprises a natural distributed combustor.
2587. The method of claim 2581, further comprising controlling a
pressure and a temperature within at least a majority of a selected
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
2588. The method of claim 2581, further comprising controlling the
heat from the heating mechanism such that heat transferred from the
heating mechanism to at least the portion of the formation is less
than about 1.degree. C. per day during pyrolysis.
2589. The method of claim 2581, further comprising: heating a
selected volume (V) of the coal formation from the heating
mechanism, wherein the formation has an average heat capacity
(C.sub.v), and wherein the heating pyrolyzes at least some
hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2590. The method of claim 2581, further comprising allowing the
heat to transfer from the heating mechanism to at least the portion
of the formation substantially by conduction.
2591. The method of claim 2581, further comprising providing heat
from the heating mechanism to at least the portion of the formation
such that a thermal conductivity of at least the portion of the
formation is greater than about 0.5 W/(m.degree. C.).
2592. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2593. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2594. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2595. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2596. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2597. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2598. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2599. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2600. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2601. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2602. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2603. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2604. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2605. The method of claim 2581, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2606. The method of claim 2581, further comprising controlling a
pressure within at least a majority of a selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2607. The method of claim 2581, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2608. The method of claim 2607, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2609. The method of claim 2581, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2610. The method of claim 2581, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2611. The method of claim 2581, further comprising: providing
hydrogen (H.sub.2) to at least the heated portion to hydrogenate
hydrocarbons within the formation; and heating a portion of the
formation with heat from hydrogenation.
2612. The method of claim 2581, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2613. The method of claim 2581, further comprising allowing heat to
transfer from the heating mechanism to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of a
selected section of the formation increases to greater than about
100 millidarcy.
2614. The method of claim 2581, further comprising allowing heat to
transfer from the heating mechanism to a selected section of the
formation to pyrolyze at least some hydrocarbons within the
selected section such that a permeability of a majority of the
selected section increases substantially uniformly.
2615. The method of claim 2581, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2616. The method of claim 2581, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2617. The method of claim 2581, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2618. The method of claim 2581, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2619. A method of treating a coal formation in situ, comprising:
heating a selected section of the formation with a heating element
placed within a wellbore, wherein at least one end of the heating
element is free to move axially within the wellbore to allow for
thermal expansion of the heating element.
2620. The method of claim 2619, further comprising at least two
heating elements within at least two wellbores, and wherein
superposition of heat from at least the two heating elements
pyrolyzes at least some hydrocarbons within a selected section of
the formation.
2621. The method of claim 2619, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2622. The method of claim 2619, wherein the heating element
comprises a pipe-in-pipe heater.
2623. The method of claim 2619, wherein the heating element
comprises a flameless distributed combustor.
2624. The method of claim 2619, wherein the heating element
comprises a mineral insulated cable coupled to a support, and
wherein the support is free to move within the wellbore.
2625. The method of claim 2619, wherein the heating element
comprises a mineral insulated cable suspended from a wellhead.
2626. The method of claim 2619, further comprising controlling a
pressure and a temperature within at least a majority of a heated
section of the formation, wherein the pressure is controlled as a
function of temperature, or the temperature is controlled as a
function of pressure.
2627. The method of claim 2619, further comprising controlling the
heat such that an average heating rate of the heated section is
less than about 1.degree. C. per day during pyrolysis.
2628. The method of claim 2619, wherein heating the section of the
formation further comprises: heating a selected volume (V) of the
coal formation from the heating element, wherein the formation has
an average heat capacity (C.sub.v), and wherein the heating
pyrolyzes at least some hydrocarbons within the selected volume of
the formation; and wherein heating energy/day provided to the
volume is equal to or less than Pwr, wherein Pwr is calculated by
the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
2629. The method of claim 2619, wherein heating the section of the
formation comprises transferring heat substantially by
conduction.
2630. The method of claim 2619, further comprising heating the
selected section of the formation such that a thermal conductivity
of the selected section is greater than about 0.5 W/(m.degree.
C.).
2631. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons having an API gravity of at least about
25.degree..
2632. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 0.1% by weight to about
15% by weight of the condensable hydrocarbons are olefins.
2633. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
non-condensable hydrocarbons, and wherein a molar ratio of ethene
to ethane in the non-condensable hydrocarbons ranges from about
0.001 to about 0.15.
2634. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is nitrogen.
2635. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
2636. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
2637. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, wherein about 5% by weight to about 30%
by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2638. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
2639. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 5% by weight
of the condensable hydrocarbons comprises multi-ring aromatics with
more than two rings.
2640. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
2641. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
condensable hydrocarbons, and wherein about 5% by weight to about
30% by weight of the condensable hydrocarbons are cycloalkanes.
2642. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
a non-condensable component, wherein the non-condensable component
comprises hydrogen, wherein the hydrogen is greater than about 10%
by volume of the non-condensable component, and wherein the
hydrogen is less than about 80% by volume of the non-condensable
component.
2643. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein greater than about 0.05% by weight of the
produced mixture is ammonia.
2644. The method of claim 2619, further comprising producing a
mixture from the formation, wherein the produced mixture comprises
ammonia, and wherein the ammonia is used to produce fertilizer.
2645. The method of claim 2619, further comprising controlling a
pressure within the selected section of the formation, wherein the
controlled pressure is at least about 2.0 bar absolute.
2646. The method of claim 2619, further comprising controlling
formation conditions to produce a mixture from the formation,
wherein a partial pressure of H.sub.2 within the mixture is greater
than about 0.5 bar.
2647. The method of claim 2647, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2648. The method of claim 2619, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2649. The method of claim 2619, further comprising producing a
mixture from the formation and controlling formation conditions by
recirculating a portion of hydrogen from the mixture into the
formation.
2650. The method of claim 2619, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the heated section; and heating a portion of
the section with heat from hydrogenation.
2651. The method of claim 2619, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2652. The method of claim 2619, wherein heating comprises
increasing a permeability of a majority of the heated section to
greater than about 100 millidarcy.
2653. The method of claim 2619, wherein heating comprises
substantially uniformly increasing a permeability of a majority of
the heated section.
2654. The method of claim 2619, wherein the heating is controlled
to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2655. The method of claim 2619, further comprising producing a
mixture in a production well, and wherein at least about 7 heat
sources are disposed in the formation for each production well.
2656. The method of claim 2619, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2657. The method of claim 2619, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2658. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation; and
producing a mixture from the formation through a production well,
wherein the production well is located such that a majority of the
mixture produced from the formation comprises non-condensable
hydrocarbons and a non-condensable component comprising
hydrogen.
2659. The method of claim 2658, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
2660. The method of claim 2658, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2661. The method of claim 2658, wherein the production well is less
than approximately 6 m from a heat source of the one or more heat
sources.
2662. The method of claim 2658, wherein the production well is less
than approximately 3 m from a heat source of the one or more heat
sources.
2663. The method of claim 2658, wherein the production well is less
than approximately 1.5 m from a heat source of the one or more heat
sources.
2664. The method of claim 2658, wherein an additional heat source
is positioned within a wellbore of the production well.
2665. The method of claim 2658, wherein the one or more heat
sources comprise electrical heaters.
2666. The method of claim 2658, wherein the one or more heat
sources comprise surface burners.
2667. The method of claim 2658, wherein the one or more heat
sources comprise flameless distributed combustors.
2668. The method of claim 2658, wherein the one or more heat
sources comprise natural distributed combustors.
2669. The method of claim 2658, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2670. The method of claim 2658, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2671. The method of claim 2658, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity (C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
2672. The method of claim 2658, wherein allowing the heat to
transfer from the one or more heat sources to the selected section
comprises transferring heat substantially by conduction.
2673. The method of claim 2658, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
2674. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2675. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2676. The method of claim 2658, wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons ranges from about 0.001
to about 0.15.
2677. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2678. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2679. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2680. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2681. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2682. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2683. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2684. The method of claim 2658, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2685. The method of claim 2658, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2686. The method of claim 2658, wherein, the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2687. The method of claim 2658, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2688. The method of claim 2658, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2689. The method of claim 2658, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2690. The method of claim 2689, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2691. The method of claim 2658, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2692. The method of claim 2658, further comprising controlling
formation conditions by recirculating a portion of the hydrogen
from the mixture into the formation.
2693. The method of claim 2658, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
2694. The method of claim 2658, further comprising: producing
condensable hydrocarbons from the formation; and hydrogenating a
portion of the produced condensable hydrocarbons with at least a
portion of the produced hydrogen.
2695. The method of claim 2658, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2696. The method of claim 2658, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2697. The method of claim 2658, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2698. The method of claim 2658, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
2699. The method of claim 2658, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2700. The method of claim 2658, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2701. A method of treating a coal formation in situ, comprising:
providing heat to at least a portion of the formation from one or
more first heat sources placed within a pattern in the formation;
allowing the heat to transfer from the one or more first heat
sources to a first section of the formation; heating a second
section of the formation with at least one second heat source,
wherein the second section is located within the first section, and
wherein at least the one second heat source is configured to raise
an average temperature of a portion of the second section to a
higher temperature than an average temperature of the first
section; and producing a mixture from the formation through a
production well positioned within the second section, wherein a
majority of the produced mixture comprises non-condensable
hydrocarbons and a non-condensable component comprising H.sub.2
components.
2702. The method of claim 2701, wherein the one or more first heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the first section of the
formation.
2703. The method of claim 2701, further comprising maintaining a
temperature within the first section within a pyrolysis temperature
range.
2704. The method of claim 2701, wherein at least the one heat
source comprises a heater element positioned within the production
well.
2705. The method of claim 2701, wherein at least the one second
heat source comprises an electrical heater.
2706. The method of claim 2701, wherein at least the one second
heat source comprises a surface burner.
2707. The method of claim 2701, wherein at least the one second
heat source comprises a flameless distributed combustor.
2708. The method of claim 2701, wherein at least the one second
heat source comprises a natural distributed combustor.
2709. The method of claim 2701, further comprising controlling a
pressure and a temperature within at least a majority of the first
or the second section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2710. The method of claim 2701, further comprising controlling the
heat such that an average heating rate of the first section is less
than about 1.degree. C. per day during pyrolysis.
2711. The method of claim 2701, wherein providing heat to the
formation further comprises: heating a selected volume (V) of the
from the one or more first heat sources, wherein the formation has
an average heat capacity (C.sub.v), and wherein the heating
pyrolyzes at least some hydrocarbons within the selected volume of
the formation; and wherein heating energy/day provided to the
volume is equal to or less than Pwr, wherein Pwr is calculated by
the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
2712. The method of claim 2701, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2713. The method of claim 2701, wherein providing heat from the one
or more first heat sources comprises heating the first section such
that a thermal conductivity of at least a portion of the first
section is greater than about 0.5 W/(m.degree. C.).
2714. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2715. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2716. The method of claim 2701, wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons ranges from about 0.001
to about 0.15.
2717. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2718. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2719. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2720. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2721. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2722. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
2723. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2724. The method of claim 2701, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2725. The method of claim 2701, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2726. The method of claim 2701, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2727. The method of claim 2701, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2728. The method of claim 2701, further comprising controlling a
pressure within at least a majority of the first or the second
section of the formation, wherein the controlled pressure is at
least about 2.0 bar absolute.
2729. The method of claim 2701, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2730. The method of claim 2729, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2731. The method of claim 2701, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2732. The method of claim 2701, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2733. The method of claim 2701, further comprising: providing
hydrogen (H.sub.2) to the first or second section to hydrogenate
hydrocarbons within the first or second section, respectively; and
heating a portion of the first or second section, respectively,
with heat from hydrogenation.
2734. The method of claim 2701, further comprising: producing
condensable hydrocarbons from the formation; and hydrogenating a
portion of the produced condensable hydrocarbons with at least a
portion of the produced hydrogen.
2735. The method of claim 2701, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
first or second section to greater than about 100 millidarcy.
2736. The method of claim 2701, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the first or second section.
2737. The method of claim 2701, wherein heating the first or the
second section is controlled to yield greater than about 60% by
weight of condensable hydrocarbons, as measured by Fischer
Assay.
2738. The method of claim 2701, wherein at least about 7 heat
sources are disposed in the formation for each production well.
2739. The method of claim 2701, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2740. The method of claim 2701, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2741. A method of treating a coal formation in situ, comprising:
providing heat into the formation from a plurality of heat sources
placed in a pattern within the formation, wherein a spacing between
heat sources is greater than about 6 m; allowing the heat to
transfer from the plurality of heat sources to a selected section
of the formation; producing a mixture from the formation from a
plurality of production wells, wherein the plurality of production
wells are positioned within the pattern, and wherein a spacing
between production wells is greater than about 12 m.
2742. The method of claim 2741, wherein superposition of heat from
the plurality of heat sources pyrolyzes at least some hydrocarbons
within the selected section of the formation.
2743. The method of claim 2741, further comprising maintaining a
temperature within the selected section within a pyrolysis
temperature range.
2744. The method of claim 2741, wherein the plurality of heat
sources comprises electrical heaters.
2745. The method of claim 2741, wherein the plurality of heat
sources comprises surface burners.
2746. The method of claim 2741, wherein the plurality of heat
sources comprises flameless distributed combustors.
2747. The method of claim 2741, wherein the plurality of heat
sources comprises natural distributed combustors.
2748. The method of claim 2741, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
2749. The method of claim 2741, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
2750. The method of claim 2741, wherein providing heat from the
plurality of heat comprises: heating a selected volume (V) of the
coal formation from the plurality of heat sources, wherein the
formation has an average heat capacity (C.sub.v), and wherein the
heating pyrolyzes at least some hydrocarbons within the selected
volume of the formation; and wherein heating energy/day provided to
the volume is equal to or less than Pwr, wherein Pwr is calculated
by the equation: Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the
heating energy/day, h is an average heating rate of the formation,
.rho..sub.B is formation bulk density, and wherein the heating rate
is less than about 10.degree. C./day.
2751. The method of claim 2741, wherein allowing the heat to
transfer comprises transferring heat substantially by
conduction.
2752. The method of claim 2741, wherein providing heat comprises
heating the selected formation such that a thermal conductivity of
at least a portion of the selected section is greater than about
0.5 W/(m.degree. C.).
2753. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
2754. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
2755. The method of claim 2741, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
2756. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
2757. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
2758. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
2759. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
2760. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
2761. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ling
aromatics with more than two rings.
2762. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
2763. The method of claim 2741, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
2764. The method of claim 2741, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
2765. The method of claim 2741, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
2766. The method of claim 2741, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
2767. The method of claim 2741, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
2768. The method of claim 2741, further comprising controlling
formation conditions to produce the mixture, wherein a partial
pressure of H.sub.2 within the mixture is greater than about 0.5
bar.
2769. The method of claim 2768, wherein the partial pressure of
H.sub.2 within the mixture is measured when the mixture is at a
production well.
2770. The method of claim 2741, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
2771. The method of claim 2741, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
2772. The method of claim 2741, further comprising: providing
hydrogen (H.sub.2) to the selected section to hydrogenate
hydrocarbons within the selected section; and heating a portion of
the selected section with heat from hydrogenation.
2773. The method of claim 2741, further comprising: producing
hydrogen and condensable hydrocarbons from the formation; and
hydrogenating a portion of the produced condensable hydrocarbons
with at least a portion of the produced hydrogen.
2774. The method of claim 2741, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
2775. The method of claim 2741, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
2776. The method of claim 2741, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
2777. The method of claim 2741, wherein at least about 7 heat
sources are disposed in the formation for each production well.
2778. The method of claim 2741, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
2779. The method of claim 2741, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
2780. A system configured to heat a coal formation, comprising: a
heater disposed in an opening in the formation, wherein the heater
is configured to provide heat to at least a portion of the
formation during use; an oxidizing fluid source; a conduit disposed
in the opening, wherein the conduit is configured to provide an
oxidizing fluid from the oxidizing fluid source to a reaction zone
in the formation during use, and wherein the oxidizing fluid is
selected to oxidize at least some hydrocarbons at the reaction zone
during use such that heat is generated at the reaction zone; and
wherein the system is configured to allow heat to transfer
substantially by conduction from the reaction zone to a pyrolysis
zone of the formation during use.
2781. The system of claim 2780, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2782. The system of claim 2780, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
2783. The system of claim 2780, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2784. The system of claim 2780, wherein the conduit is further
configured to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2785. The system of claim 2780, wherein the conduit is further
configured to remove an oxidation product.
2786. The system of claim 2780, wherein the conduit is further
configured to remove an oxidation product such that the oxidation
product transfers substantial heat to the oxidizing fluid.
2787. The system of claim 2780, wherein the conduit is further
configured to remove an oxidation product, and wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
2788. The system of claim 2780, wherein the conduit is further
configured to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
2789. The system of claim 2780, wherein the conduit is further
configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
2790. The system of claim 2780, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2791. The system of claim 2780, further comprising a center conduit
disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the conduit is further configured to remove an
oxidation product during use.
2792. The system of claim 2780, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2793. The system of claim 2780, further comprising a conductor
disposed in a second conduit, wherein the second conduit is
disposed within the opening, and wherein the conductor is
configured to heat at least a portion of the formation during
application of an electrical current to the conductor.
2794. The system of claim 2780, further comprising an insulated
conductor disposed within the opening, wherein the insulated
conductor is configured to heat at least a portion of the formation
during application of an electrical current to the insulated
conductor.
2795. The system of claim 2780, further comprising at least one
elongated member disposed within the opening, wherein the at least
the one elongated member is configured to heat at least a portion
of the formation during application of an electrical current to the
at least the one elongated member.
2796. The system of claim 2780, further comprising a heat exchanger
disposed external to the formation, wherein the heat exchanger is
configured to heat the oxidizing fluid, wherein the conduit is
further configured to provide the heated oxidizing fluid into the
opening during use, and wherein the heated oxidizing fluid is
configured to heat at least a portion of the formation during
use.
2797. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2798. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2799. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2800. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2801. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2802. The system of claim 2780, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2803. The system of claim 2780, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2804. A system configurable to heat a coal formation, comprising: a
heater configurable to be disposed in an opening in the formation,
wherein the heater is further configurable to provide heat to at
least a portion of the formation during use; a conduit configurable
to be disposed in the opening, wherein the conduit is configurable
to provide an oxidizing fluid from an oxidizing fluid source to a
reaction zone in the formation during use, and wherein the system
is configurable to allow the oxidizing fluid to oxidize at least
some hydrocarbons at the reaction zone during use such that heat is
generated at the reaction zone; and wherein the system is further
configurable to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
2805. The system of claim 2804, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2806. The system of claim 2804, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
2807. The system of claim 2804, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2808. The system of claim 2804, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2809. The system of claim 2804, wherein the conduit is further
configurable to remove an oxidation product.
2810. The system of claim 2804, wherein the conduit is further
configurable to remove an oxidation product, such that the
oxidation product transfers heat to the oxidizing fluid.
2811. The system of claim 2804, wherein the conduit is further
configurable to remove an oxidation product, and wherein a flow
rate of the oxidizing fluid in the conduit is approximately equal
to a flow rate of the oxidation product in the conduit.
2812. The system of claim 2804, wherein the conduit is further
configurable to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
2813. The system of claim 2804, wherein the conduit is further
configurable to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
2814. The system of claim 2804, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2815. The system of claim 2804, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use, and
wherein the conduit is further configurable to remove an oxidation
product during use.
2816. The system of claim 2804, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2817. The system of claim 2804, further comprising a conductor
disposed in a second conduit, wherein the second conduit is
disposed within the opening, and wherein the conductor is
configurable to heat at least a portion of the formation during
application of an electrical current to the conductor.
2818. The system of claim 2804, further comprising an insulated
conductor disposed within the opening, wherein the insulated
conductor is configurable to heat at least a portion of the
formation during application of an electrical current to the
insulated conductor.
2819. The system of claim 2804, further comprising at least one
elongated member disposed within the opening, wherein the at least
the one elongated member is configurable to heat at least a portion
of the formation during application of an electrical current to the
at least the one elongated member.
2820. The system of claim 2804, further comprising a heat exchanger
disposed external to the formation, wherein the heat exchanger is
configurable to heat the oxidizing fluid, wherein the conduit is
further configurable to provide the heated oxidizing fluid into the
opening during use, and wherein the heated oxidizing fluid is
configurable to heat at least a portion of the formation during
use.
2821. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2822. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2823. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2824. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2825. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2826. The system of claim 2804, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2827. The system of claim 2804, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2828. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid; providing the oxidizing fluid to
a reaction zone in the formation; allowing the oxidizing fluid to
react with at least a portion of the hydrocarbons at the reaction
zone to generate heat at the reaction zone; and transferring the
generated heat substantially by conduction from the reaction zone
to a pyrolysis zone in the formation.
2829. The method of claim 2828, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
2830. The method of claim 2828, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
2831. The method of claim 2828, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
2832. The method of claim 2828, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
2833. The method of claim 2828, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid to reduce heating of the conduit by
oxidation.
2834. The method of claim 2828, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit.
2835. The method of claim 2828, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to
oxidizing fluid in the conduit.
2836. The method of claim 2828, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
2837. The method of claim 2828, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
2838. The method of claim 2828, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
2839. The method of claim 2828, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
2840. The method of claim 2828, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
2841. The method of claim 2828, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2842. The method of claim 2828, wherein heating the portion
comprises applying electrical current to a conductor disposed in a
conduit, wherein the conduit is disposed within the opening.
2843. The method of claim 2828, wherein heating the portion
comprises applying electrical current to an insulated conductor
disposed within the opening.
2844. The method of claim 2828, wherein heating the portion
comprises applying electrical current to at least one elongated
member disposed within the opening.
2845. The method of claim 2828, wherein heating the portion
comprises heating the oxidizing fluid in a heat exchanger disposed
external to the formation such that providing the oxidizing fluid
into the opening comprises transferring heat from the heated
oxidizing fluid to the portion.
2846. The method of claim 2828, further comprising removing water
from the formation prior to heating the portion.
2847. The method of claim 2828, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
2848. The method of claim 2828, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2849. The method of claim 2828, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2850. The method of claim 2828, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2851. The method of claim 2828, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2852. The method of claim 2828, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
2853. A system configured to heat a coal formation, comprising: a
heater disposed in an opening in the formation, wherein the heater
is configured to provide heat to at least a portion of the
formation during use; an oxidizing fluid source; a conduit disposed
in the opening, wherein the conduit is configured to provide an
oxidizing fluid from the oxidizing fluid source to a reaction zone
in the formation during use, wherein the oxidizing fluid is
selected to oxidize at least some hydrocarbons at the reaction zone
during use such that heat is generated at the reaction zone, and
wherein the conduit is further configured to remove an oxidation
product from the formation during use; and wherein the system is
configured to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
2854. The system of claim 2853, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2855. The system of claim 2853, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
2856. The system of claim 2853, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2857. The system of claim 2853, wherein the conduit is further
configured to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2858. The system of claim 2853, wherein the conduit is further
configured such that the oxidation product transfers heat to the
oxidizing fluid.
2859. The system of claim 2853, wherein a flow rate of the
oxidizing fluid in the conduit is approximately equal to a flow
rate of the oxidation product in the conduit.
2860. The system of claim 2853, wherein a pressure of the oxidizing
fluid in the conduit and a pressure of the oxidation product in the
conduit are controlled to reduce contamination of the oxidation
product by the oxidizing fluid.
2861. The system of claim 2853, wherein the oxidation product is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2862. The system of claim 2853, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2863. The system of claim 2853, further comprising a center conduit
disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use.
2864. The system of claim 2853, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2865. The system of claim 2853, further comprising a conductor
disposed in a second conduit, wherein the second conduit is
disposed within the opening, and wherein the conductor is
configured to heat at least a portion of the formation during
application of an electrical current to the conductor.
2866. The system of claim 2853, further comprising an insulated
conductor disposed within the opening, wherein the insulated
conductor is configured to heat at least a portion of the formation
during application of an electrical current to the insulated
conductor.
2867. The system of claim 2853, further comprising at least one
elongated member disposed within the opening, wherein the at least
the one elongated member is configured to heat at least a portion
of the formation during application of an electrical current to
the, at least the one elongated member.
2868. The system of claim 2853, further comprising a heat exchanger
disposed external to the formation, wherein the heat exchanger is
configured to heat the oxidizing fluid, wherein the conduit is
further configured to provide the heated oxidizing fluid into the
opening during use, and wherein the heated oxidizing fluid is
configured to heat at least a portion of the formation during
use.
2869. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2870. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2871. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2872. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2873. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2874. The system of claim 2853, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2875. The system of claim 2853, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2876. A system configurable to heat a coal formation, comprising: a
heater configurable to be disposed in an opening in the formation,
wherein the heater is further configurable to provide heat to at
least a portion of the formation during use; a conduit configurable
to be disposed in the opening, wherein the conduit is further
configurable to provide an oxidizing fluid from an oxidizing fluid
source to a reaction zone in the formation during use, wherein the
system is configurable to allow the oxidizing fluid to oxidize at
least some hydrocarbons at the reaction zone during use such that
heat is generated at the reaction zone, and wherein the conduit is
further configurable to remove an oxidation product from the
formation during use; and wherein the system is further
configurable to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone during use.
2877. The system of claim 2876, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2878. The system of claim 2876, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
2879. The system of claim 2876, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2880. The system of claim 2876, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2881. The system of claim 2876, wherein the conduit is further
configurable such that the oxidation product transfers heat to the
oxidizing fluid.
2882. The system of claim 2876, wherein a flow rate of the
oxidizing fluid in the conduit is approximately equal to a flow
rate of the oxidation product in the conduit.
2883. The system of claim 2876, wherein a pressure of the oxidizing
fluid in the conduit and a pressure of the oxidation product in the
conduit are controlled to reduce contamination of the oxidation
product by the oxidizing fluid.
2884. The system of claim 2876, wherein the oxidation product is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2885. The system of claim 2876, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2886. The system of claim 2876, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use.
2887. The system of claim 2876, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2888. The system of claim 2876, further comprising a conductor
disposed in a second conduit, wherein the second conduit is
disposed within the opening, and wherein the conductor is
configurable to heat at least a portion of the formation during
application of an electrical current to the conductor.
2889. The system of claim 2876, further comprising an insulated
conductor disposed within the opening, wherein the insulated
conductor is configurable to heat at least a portion of the
formation during application of an electrical current to the
insulated conductor.
2890. The system of claim 2876, further comprising at least one
elongated member disposed within the opening, wherein the at least
the one elongated member is configurable to heat at least a portion
of the formation during application of an electrical current to the
at least the one elongated member.
2891. The system of claim 2876, further comprising a heat exchanger
disposed external to the formation, wherein the heat exchanger is
configurable to heat the oxidizing fluid, wherein the conduit is
further configurable to provide the heated oxidizing fluid into the
opening during use, and wherein the heated oxidizing fluid is
configurable to heat at least a portion of the formation during
use.
2892. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2893. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2894. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2895. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2896. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2897. The system of claim 2876, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2898. The system of claim 2876, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2899. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein the portion is located
substantially adjacent to an opening in the formation; providing
the oxidizing fluid to a reaction zone in the formation; allowing
the oxidizing gas to react with at least a portion of the
hydrocarbons at the reaction zone to generate heat in the reaction
zone; removing at least a portion of an oxidation product through
the opening; and transferring the generated heat substantially by
conduction from the reaction zone to a pyrolysis zone in the
formation.
2900. The method of claim 2899, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
2901. The method of claim 2899, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
2902. The method of claim 2899, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
2903. The method of claim 2899, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially maintained within the reaction zone.
2904. The method of claim 2899, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid such that the conduit is not substantially
heated by oxidation.
2905. The method of claim 2899, wherein a conduit is disposed
within the opening, and wherein removing at least the portion of
the oxidation product through the opening comprises removing at
least the portion of the oxidation product through the conduit.
2906. The method of claim 2899, wherein a conduit is disposed
within the opening, and wherein removing at least the portion of
the oxidation product through the opening comprises removing at
least the portion of the oxidation product through the conduit, the
method further comprising transferring substantial heat from the
oxidation product in the conduit to the oxidizing fluid in the
conduit.
2907. The method of claim 2899, wherein a conduit is disposed
within the opening, wherein removing at least the portion of the
oxidation product through the opening comprises removing at least
the portion of the oxidation product through the conduit, and
wherein a flow rate of the oxidizing fluid in the conduit is
approximately equal to a flow rate of the oxidation product in the
conduit.
2908. The method of claim 2899, wherein a conduit is disposed
within the opening, and wherein removing at least the portion of
the oxidation product through the opening comprises removing at
least the portion of the oxidation product through the conduit, the
method further comprising controlling a pressure between the
oxidizing fluid and the oxidation product in the conduit to reduce
contamination of the oxidation product by the oxidizing fluid.
2909. The method of claim 2899, wherein a conduit is disposed
within the opening, and wherein removing at least the portion of
the oxidation product through the opening comprises removing at
least the portion of the oxidation product through the conduit, the
method further comprising substantially inhibiting the oxidation
product from flowing into portions of the formation beyond the
reaction zone.
2910. The method of claim 2899, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
2911. The method of claim 2899, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing at least a portion of the oxidation product
through the outer conduit.
2912. The method of claim 2899, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2913. The method of claim 2899, wherein heating the portion
comprises applying electrical current to a conductor disposed in a
conduit, wherein the conduit is disposed within the opening.
2914. The method of claim 2899, wherein heating the portion
comprises applying electrical current to an insulated conductor
disposed within the opening.
2915. The method of claim 2899, wherein heating the portion
comprises applying electrical current to at least one elongated
member disposed within the opening.
2916. The method of claim 2899, wherein heating the portion
comprises heating the oxidizing fluid in a heat exchanger disposed
external to the formation such that providing the oxidizing fluid
into the opening comprises transferring heat from the heated
oxidizing fluid to the portion.
2917. The method of claim 2899, further comprising removing water
from the formation prior to heating the portion.
2918. The method of claim 2899, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
2919. The method of claim 2899, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2920. The method of claim 2899, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2921. The method of claim 2899, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2922. The method of claim 2899, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2923. The method of claim 2899, wherein the pyrolysis zone is
substantially adjacent to the reaction.
2924. A system configured to heat a coal formation, comprising: an
electric heater disposed in an opening in the formation, wherein
the electric heater is configured to provide heat to at least a
portion of the formation during use; an oxidizing fluid source; a
conduit disposed in the opening, wherein the conduit is configured
to provide an oxidizing fluid from the oxidizing fluid source to a
reaction zone in the formation during use, and wherein the
oxidizing fluid is selected to oxidize at least some hydrocarbons
at the reaction zone during use such that heat is generated at the
reaction zone; and wherein the system is configured to allow heat
to transfer substantially by conduction from the reaction zone to a
pyrolysis zone of the formation during use.
2925. The system of claim 2924, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2926. The system of claim 2924, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
2927. The system of claim 2924, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2928. The system of claim 2924, wherein the conduit is further
configured to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2929. The system of claim 2924, wherein the conduit is further
configured to remove an oxidation product.
2930. The system of claim 2924, wherein the conduit is further
configured to remove an oxidation product, such that the oxidation
product transfers heat to the oxidizing fluid.
2931. The system of claim 2924, wherein the conduit is further
configured to remove an oxidation product, and wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
2932. The system of claim 2924, wherein the conduit is further
configured to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
2933. The system of claim 2924, wherein the conduit is further
configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing in to
portions of the formation beyond the reaction zone.
2934. The system of claim 2924, wherein the oxidizing flu id is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2935. The system of claim 2924, further comp rising a center
conduit disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the conduit is further configured to remove an
oxidation product during use.
2936. The system of claim 2924, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2937. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2938. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2939. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2940. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2941. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2942. The system of claim 2924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2943. The system of claim 2924, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2944. A system configurable to heat a coal formation, comprising:
an electric heater configurable to be disposed in an opening in the
formation, wherein the electric heater is further configurable to
provide heat to at least a portion of the formation during use, and
wherein at least the portion is located substantially adjacent to
the opening; a conduit configurable to be disposed in the opening,
wherein the conduit is further configurable to provide an oxidizing
fluid from an oxidizing fluid source to a reaction zone in the
formation during use, and wherein the system is configurable to
allow the oxidizing fluid to oxidize at least some hydrocarbons at
the reaction zone during use such that heat is generated at the
reaction zone; and wherein the system is further configurable to
allow heat to transfer substantially by conduction from the
reaction zone to a pyrolysis zone of the formation during use.
2945. The system of claim 2944, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2946. The system of claim 2944, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
2947. The system of claim 2944, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
2948. The system of claim 2944, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
2949. The system of claim 2944, wherein the conduit is further
configurable to remove an oxidation product.
2950. The system of claim 2944, wherein the conduit is further
configurable to remove an oxidation product such that the oxidation
product transfers heat to the oxidizing fluid.
2951. The system of claim 2944, wherein the conduit is further
configurable to remove an oxidation product, and wherein a flow
rate of the oxidizing fluid in the conduit is approximately equal
to a flow rate of the oxidation product in the conduit.
2952. The system of claim 2944, wherein the conduit is further
configurable to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
2953. The system of claim 2944, wherein the conduit is further
configurable to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
2954. The system of claim 2944, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2955. The system of claim 2944, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use, and
wherein the conduit is further configurable to remove an oxidation
product during use.
2956. The system of claim 2944, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2957. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2958. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2959. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2960. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2961. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2962. The system of claim 2944, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2963. The system of claim 2944, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2964. A system configured to heat a coal formation, comprising: a
conductor disposed in a first conduit, wherein the first conduit is
disposed in an opening in the formation, and wherein the conductor
is configured to provide heat to at least a portion of the
formation during use; an oxidizing fluid source; a second conduit
disposed in the opening, wherein the second conduit is configured
to provide an oxidizing fluid from the oxidizing fluid source to a
reaction zone in the formation during use, and wherein the
oxidizing fluid is selected to oxidize at least some hydrocarbons
at the reaction zone during use such that heat is generated at the
reaction zone; and wherein the system is configured to allow heat
to transfer substantially by conduction from the reaction zone to a
pyrolysis zone of the formation during use.
2965. The system of claim 2964, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2966. The system of claim 2964, wherein the second conduit
comprises orifices, and wherein the orifices are configured to
provide the oxidizing fluid into the opening.
2967. The system of claim 2964, wherein the second conduit
comprises critical flow orifices, and wherein the critical flow
orifices are configured to control a flow of the oxidizing fluid
such that a rate of oxidation in the formation is controlled.
2968. The system of claim 2964, wherein the second conduit is
further configured to be cooled with the oxidizing fluid to reduce
heating of the second conduit by oxidation.
2969. The system of claim 2964, wherein the second conduit is
further configured to remove an oxidation product.
2970. The system of claim 2964, wherein the second conduit is
further configured to remove an oxidation product such that the
oxidation product transfers heat to the oxidizing fluid.
2971. The system of claim 2964, wherein the second conduit is
further configured to remove an oxidation product, and wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the second
conduit.
2972. The system of claim 2964, wherein the second conduit is
further configured to remove an oxidation product, and wherein a
pressure of the oxidizing fluid in the second conduit and a
pressure of the oxidation product in the second conduit are
controlled to reduce contamination of the oxidation product by the
oxidizing fluid.
2973. The system of claim 2964, wherein the second conduit is
further configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
2974. The system of claim 2964, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2975. The system of claim 2964, further comprising a center conduit
disposed within the second conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the second conduit is further configured to remove
an oxidation product during use.
2976. The system of claim 2964, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2977. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2978. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2979. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
2980. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
2981. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
2982. The system of claim 2964, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
2983. The system of claim 2964, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
2984. A system configurable to heat a coal formation, comprising: a
conductor configurable to be disposed in a first conduit, wherein
the first conduit is configurable to be disposed in an opening in
the formation, and wherein the conductor is further configurable to
provide heat to at least a portion of the formation during use; a
second conduit configurable to be disposed in the opening, wherein
the second conduit is further configurable to provide an oxidizing
fluid from an oxidizing fluid source to a reaction zone in the
formation during use, and wherein the system is configurable to
allow the oxidizing fluid to oxidize at least some hydrocarbons at
the reaction zone during use such that heat is generated at the
reaction zone; and wherein the system is further configurable to
allow heat to transfer substantially by conduction from the
reaction zone to a pyrolysis zone of the formation during use.
2985. The system of claim 2984, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
2986. The system of claim 2984, wherein the second conduit
comprises orifices, and wherein the orifices are configurable to
provide the oxidizing fluid into the opening.
2987. The system of claim 2984, wherein the second conduit
comprises critical flow orifices, and wherein the critical flow
orifices are configurable to control a flow of the oxidizing fluid
such that a rate of oxidation in the formation is controlled.
2988. The system of claim 2984, wherein the second conduit is
further configurable to be cooled with the oxidizing fluid to
reduce heating of the second conduit by oxidation.
2989. The system of claim 2984, wherein the second conduit is
further configurable to remove an oxidation product.
2990. The system of claim 2984, wherein the second conduit is
further configurable to remove an oxidation product such that the
oxidation product transfers heat to the oxidizing fluid.
2991. The system of claim 2984, wherein the second conduit is
further configurable to remove an oxidation product, and wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the second
conduit.
2992. The system of claim 2984, wherein the second conduit is
further configurable to remove an oxidation product, and wherein a
pressure of the oxidizing fluid in the second conduit and a
pressure of the oxidation product in the second conduit are
controlled to reduce contamination of the oxidation product by the
oxidizing fluid.
2993. The system of claim 2984, wherein the second conduit is
further configurable to remove an oxidation product, and wherein
the oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
2994. The system of claim 2984, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
2995. The system of claim 2984, further comprising a center conduit
disposed within the second conduit, wherein center conduit is
configurable to provide the oxidizing fluid into the opening during
use, and wherein the second conduit is further configurable to
remove an oxidation product during use.
2996. The system of claim 2984, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
2997. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
2998. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
2999. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3000. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3001. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3002. The system of claim 2984, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3003. The system of claim 2984, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
3004. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein heating comprises
applying an electrical current to a conductor disposed in a first
conduit to provide heat to the portion, and wherein the first
conduit is disposed within the opening; providing the oxidizing
fluid to a reaction zone in the formation; allowing the oxidizing
fluid to react with at least a portion of the hydrocarbons at the
reaction zone to generate heat at the reaction zone; and
transferring the generated heat substantially by conduction from
the reaction zone to a pyrolysis zone in the formation.
3005. The method of claim 3004, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3006. The method of claim 3004, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a second conduit disposed in the opening.
3007. The method of claim 3004, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a second
conduit disposed in the opening such that a rate of oxidation is
controlled.
3008. The method of claim 3004, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3009. The method of claim 3004, wherein a second conduit is
disposed in the opening, the method further comprising cooling the
second conduit with the oxidizing fluid to reduce heating of the
second conduit by oxidation.
3010. The method of claim 3004, wherein a second conduit is
disposed within the opening, the method further comprising removing
an oxidation product from the formation through the second
conduit.
3011. The method of claim 3004, wherein a second conduit is
disposed within the opening, the method further comprising removing
an oxidation product from the formation through the second conduit
and transferring heat from the oxidation product in the conduit to
the oxidizing fluid in the second conduit.
3012. The method of claim 3004, wherein a second conduit is
disposed within the opening, the method further comprising removing
an oxidation product from the formation through the second conduit,
wherein a flow rate of the oxidizing fluid in the second conduit is
approximately equal to a flow rate of the oxidation product in the
second conduit.
3013. The method of claim 3004, wherein a second conduit is
disposed within the opening, the method further comprising removing
an oxidation product from the formation through the second conduit
and controlling a pressure between the oxidizing fluid and the
oxidation product in the second conduit to reduce contamination of
the oxidation product by the oxidizing fluid.
3014. The method of claim 3004, wherein a second conduit is
disposed within the opening, the method further comprising removing
an oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3015. The method of claim 3004, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3016. The method of claim 3004, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
3017. The method of claim 3004, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3018. The method of claim 3004, further comprising removing water
from the formation prior to heating the portion.
3019. The method of claim 3004, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3020. The method of claim 3004, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3021. The method of claim 3004, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3022. The method of claim 3004, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3023. The method of claim 3004, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3024. A system configured to heat a coal formation, comprising: an
insulated conductor disposed in an opening in the formation,
wherein the insulated conductor is configured to provide heat to at
least a portion of the formation during use; an oxidizing fluid
source; a conduit disposed in the opening, wherein the conduit is
configured to provide an oxidizing fluid from the oxidizing fluid
source to a reaction zone in the formation during use, and wherein
the oxidizing fluid is selected to oxidize at least some
hydrocarbons at the reaction zone during use such that heat is
generated at the reaction zone; and wherein the system is
configured to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
3025. The system of claim 3024, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3026. The system of claim 3024, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
3027. The system of claim 3024, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3028. The system of claim 3024, wherein the conduit is configured
to be cooled with the oxidizing fluid such that the conduit is not
substantially heated by oxidation.
3029. The system of claim 3024, wherein the conduit is further
configured to remove an oxidation product.
3030. The system of claim 3024, wherein the conduit is further
configured to remove an oxidation product, and wherein the conduit
is further configured such that the oxidation product transfers
substantial heat to the oxidizing fluid.
3031. The system of claim 3024, wherein the conduit is further
configured to remove an oxidation product, and wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
3032. The system of claim 3024, wherein the conduit is further
configured to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the second conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3033. The system of claim 3024, wherein the conduit is further
configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3034. The system of claim 3024, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3035. The system of claim 3024, further comprising a center conduit
disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the conduit is further configured to remove an
oxidation product during use.
3036. The system of claim 3024, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3037. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3038. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3039. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3040. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3041. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3042. The system of claim 3024, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3043. The system of claim 3024, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
3044. A system configurable to heat a coal formation, comprising:
an insulated conductor configurable to be disposed in an opening in
the formation, wherein the insulated conductor is further
configurable to provide heat to at least a portion of the formation
during use; a conduit configurable to be disposed in the opening,
wherein the conduit is further configurable to provide an oxidizing
fluid from an oxidizing fluid source to a reaction zone in the
formation during use, and wherein the system is configurable to
allow the oxidizing fluid to oxidize at least some hydrocarbons at
the reaction zone during use such that heat is generated at the
reaction zone; and wherein the system is further configurable to
allow heat to transfer substantially by conduction from the
reaction zone to a pyrolysis zone of the formation during use.
3045. The system of claim 3044, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3046. The system of claim 3044, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
3047. The system of claim 3044, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3048. The system of claim 3044, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
3049. The system of claim 3044, wherein the conduit is further
configurable to remove an oxidation product.
3050. The system of claim 3044, wherein the conduit is further
configurable to remove an oxidation product, such that the
oxidation product transfers heat to the oxidizing fluid.
3051. The system of claim 3044, wherein the conduit is further
configurable to remove an oxidation product, and wherein a flow
rate of the oxidizing fluid in the conduit is approximately equal
to a flow rate of the oxidation product in the conduit.
3052. The system of claim 3044, wherein the conduit is further
configurable to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3053. The system of claim 3044, wherein the conduit is further
configurable to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3054. The system of claim 3044, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3055. The system of claim 3044, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use, and
wherein the conduit is further configurable to remove an oxidation
product during use.
3056. The system of claim 3044, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3057. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3058. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3059. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3060. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3061. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3062. The system of claim 3044, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3063. The system of claim 3044, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
3064. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein heating comprises
applying an electrical current to an insulated conductor to provide
heat to the portion, and wherein the insulated conductor is
disposed within the opening; providing the oxidizing fluid to a
reaction zone in the formation; allowing the oxidizing fluid to
react with at least a portion of the hydrocarbons at the reaction
zone to generate heat at the reaction zone; and transferring the
generated heat substantially by conduction from the reaction zone
to a pyrolysis zone in the formation.
3065. The method of claim 3064, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3066. The method of claim 3064, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
3067. The method of claim 3064, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
3068. The method of claim 3064, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3069. The method of claim 3064, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid to reduce heating of the conduit by
oxidation.
3070. The method of claim 3064, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit.
3071. The method of claim 3064, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
3072. The method of claim 3064, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
3073. The method of claim 3064, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
3074. The method of claim 3064, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3075. The method of claim 3064, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3076. The method of claim 3064, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
3077. The method of claim 3064, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3078. The method of claim 3064, further comprising removing water
from the formation prior to heating the portion.
3079. The method of claim 3064, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3080. The method of claim 3064, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3081. The method of claim 3064, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3082. The method of claim 3064, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3083. The method of claim 3064, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3084. The method of claim 3064, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
3085. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein the portion is located
substantially adjacent to an opening in the formation, wherein
heating comprises applying an electrical current to an insulated
conductor to provide heat to the portion, wherein the insulated
conductor is coupled to a conduit, wherein the conduit comprises
critical flow orifices, and wherein the conduit is disposed within
the opening; providing the oxidizing fluid to a reaction zone in
the formation; allowing the oxidizing fluid to react with at least
a portion of the hydrocarbons at the reaction zone to generate heat
at the reaction zone; and transferring the generated heat
substantially by conduction from the reaction zone to a pyrolysis
zone in the formation.
3086. The method of claim 3085, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3087. The method of claim 3085, further comprising controlling a
flow of the oxidizing fluid with the critical flow orifices such
that a rate of oxidation is controlled.
3088. The method of claim 3085, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3089. The method of claim 3085, further comprising cooling the
conduit with the oxidizing fluid to reduce heating of the conduit
by oxidation.
3090. The method of claim 3085, further comprising removing an
oxidation product from the formation through the conduit.
3091. The method of claim 3085, further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
3092. The method of claim 3085, further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
3093. The method of claim 3085, further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
3094. The method of claim 3085, further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3095. The method of claim 3085, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3096. The method of claim 3085, wherein a center conduit is
disposed within the conduit, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the conduit.
3097. The method of claim 3085, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3098. The method of claim 3085, further comprising removing water
from the formation prior to heating the portion.
3099. The method of claim 3085, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3100. The method of claim 3085, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3101. The method of claim 3085, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3102. The method of claim 3085, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3103. The method of claim 3085, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3104. The method of claim 3085, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
3105. A system configured to heat a coal formation, comprising: at
least one elongated member disposed in an opening in the formation,
wherein at least the one elongated member is configured to provide
heat to at least a portion of the formation during use; an
oxidizing fluid source; a conduit disposed in the opening, wherein
the conduit is configured to provide an oxidizing fluid from the
oxidizing fluid source to a reaction zone in the formation during
use, and wherein the oxidizing fluid is selected to oxidize at
least some hydrocarbons at the reaction zone during use such that
heat is generated at the reaction zone; and wherein the system is
configured to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
3106. The system of claim 3105, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3107. The system of claim 3105, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
3108. The system of claim 3105, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3109. The system of claim 3105, wherein the conduit is further
configured to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
3110. The system of claim 3105, wherein the conduit is further
configured to remove an oxidation product.
3111. The system of claim 3105, wherein the conduit is further
configured to remove an oxidation product such that the oxidation
product transfers heat to the oxidizing fluid.
3112. The system of claim 3105, wherein the conduit is further
configured to remove an oxidation product, and wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
3113. The system of claim 3105, wherein the conduit is further
configured to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3114. The system of claim 3105, wherein the conduit is further
configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3115. The system of claim 3105, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3116. The system of claim 3105, further comprising a center conduit
disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the conduit is further configured to remove an
oxidation product during use.
3117. The system of claim 3105, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3118. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3119. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3120. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3121. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3122. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3123. The system of claim 3105, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3124. The system of claim 3105, wherein the system is further
configured such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
3125. A system configurable to heat a coal formation, comprising:
at least one elongated member configurable to be disposed in an
opening in the formation, wherein at least the one elongated member
is further configurable to provide heat to at least a portion of
the formation during use; a conduit configurable to be disposed in
the opening, wherein the conduit is further configurable to provide
an oxidizing fluid from the oxidizing fluid source to a reaction
zone in the formation during use, and wherein the system is
configurable to allow the oxidizing fluid to oxidize at least some
hydrocarbons at the reaction zone during use such that heat is
generated at the reaction zone; and wherein the system is further
configurable to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
3126. The system of claim 3125, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3127. The system of claim 3125, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
3128. The system of claim 3125, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3129. The system of claim 3125, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
3130. The system of claim 3125, wherein the conduit is further
configurable to remove an oxidation product.
3131. The system of claim 3125, wherein the conduit is further
configurable to remove an oxidation product such that the oxidation
product transfers heat to the oxidizing fluid.
3132. The system of claim 3125, wherein the conduit is further
configurable to remove an oxidation product, and wherein a flow
rate of the oxidizing fluid in the conduit is approximately equal
to a flow rate of the oxidation product in the conduit.
3133. The system of claim 3125, wherein the conduit is further
configurable to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3134. The system of claim 3125, wherein the conduit is further
configurable to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3135. The system of claim 3125, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3136. The system of claim 3125, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use, and
wherein the conduit is further configurable to remove an oxidation
product during use.
3137. The system of claim 3125, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3138. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3139. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3140. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3141. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3142. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3143. The system of claim 3125, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3144. The system of claim 3125, wherein the system is further
configurable such that transferred heat can pyrolyze at least some
hydrocarbons in the pyrolysis zone.
3145. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein heating comprises
applying an electrical current to at least one elongated member to
provide heat to the portion, and wherein at least the one elongated
member is disposed within the opening; providing the oxidizing
fluid to a reaction zone in the formation; allowing the oxidizing
fluid to react with at least a portion of the hydrocarbons at the
reaction zone to generate heat at the reaction zone; and
transferring the generated heat substantially by conduction from
the reaction zone to a pyrolysis zone in the formation.
3146. The method of claim 3145, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3147. The method of claim 3145, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
3148. The method of claim 3145, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
3149. The method of claim 3145, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3150. The method of claim 3145, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid to reduce heating of the conduit by
oxidation.
3151. The method of claim 3145, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit.
3152. The method of claim 3145, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
3153. The method of claim 3145, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
3154. The method of claim 3145, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
3155. The method of claim 3145, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3156. The method of claim 3145, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3157. The method of claim 3145, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
3158. The method of claim 3145, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3159. The method of claim 3145, further comprising removing water
from the formation prior to heating the portion.
3160. The method of claim 3145, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3161. The method of claim 3145, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3162. The method of claim 3145, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3163. The method of claim 3145, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3164. The method of claim 3145, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3165. The method of claim 3145, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
3166. A system configured to heat a coal formation, comprising: a
heat exchanger disposed external to the formation, wherein the heat
exchanger is configured to heat an oxidizing fluid during use; a
conduit disposed in the opening, wherein the conduit is configured
to provide the heated oxidizing fluid from the heat exchanger to at
least a portion of the formation during use, wherein the system is
configured to allow heat to transfer from the heated oxidizing
fluid to at least the portion of the formation during use, and
wherein the oxidizing fluid is selected to oxidize at least some
hydrocarbons at a reaction zone in the formation during use such
that heat is generated at the reaction zone; and wherein the system
is configured to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
3167. The system of claim 3166, wherein the oxidizing fluid is
configured to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3168. The system of claim 3166, wherein the conduit comprises
orifices, and wherein the orifices are configured to provide the
oxidizing fluid into the opening.
3169. The system of claim 3166, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configured to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3170. The system of claim 3166, wherein the conduit is further
configured to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
3171. The system of claim 3166, wherein the conduit is further
configured to remove an oxidation product.
3172. The system of claim 3166, wherein the conduit is further
configured to remove an oxidation product, such that the oxidation
product transfers heat to the oxidizing fluid.
3173. The system of claim 3166, wherein the conduit is further
configured to remove an oxidation product, and wherein a flow rate
of the oxidizing fluid in the conduit is approximately equal to a
flow rate of the oxidation product in the conduit.
3174. The system of claim 3166, wherein the conduit is further
configured to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3175. The system of claim 3166, wherein the conduit is further
configured to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3176. The system of claim 3166, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3177. The system of claim 3166, further comprising a center conduit
disposed within the conduit, wherein the center conduit is
configured to provide the oxidizing fluid into the opening during
use, and wherein the conduit is further configured to remove an
oxidation product during use.
3178. The system of claim 3166, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3179. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3180. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3181. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3182. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3183. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3184. The system of claim 3166, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3185. A system configurable to heat a coal formation, comprising: a
heat exchanger configurable to be disposed external to the
formation, wherein the heat exchanger is further configurable to
heat an oxidizing fluid during use; a conduit configurable to be
disposed in the opening, wherein the conduit is further
configurable to provide the heated oxidizing fluid from the heat
exchanger to at least a portion of the formation during use,
wherein the system is configurable to allow heat to transfer from
the heated oxidizing fluid to at least the portion of the formation
during use, and wherein the system is further configurable to allow
the oxidizing fluid to oxidize at least some hydrocarbons at a
reaction zone in the formation during use such that heat is
generated at the reaction zone; and wherein the system is further
configurable to allow heat to transfer substantially by conduction
from the reaction zone to a pyrolysis zone of the formation during
use.
3186. The system of claim 3185, wherein the oxidizing fluid is
configurable to generate heat in the reaction zone such that the
oxidizing fluid is transported through the reaction zone
substantially by diffusion.
3187. The system of claim 3185, wherein the conduit comprises
orifices, and wherein the orifices are configurable to provide the
oxidizing fluid into the opening.
3188. The system of claim 3185, wherein the conduit comprises
critical flow orifices, and wherein the critical flow orifices are
configurable to control a flow of the oxidizing fluid such that a
rate of oxidation in the formation is controlled.
3189. The system of claim 3185, wherein the conduit is further
configurable to be cooled with the oxidizing fluid such that the
conduit is not substantially heated by oxidation.
3190. The system of claim 3185, wherein the conduit is further
configurable to remove an oxidation product.
3191. The system of claim 3185, wherein the conduit is further
configurable to remove an oxidation product such that the oxidation
product transfers heat to the oxidizing fluid.
3192. The system of claim 3185, wherein the conduit is further
configurable to remove an oxidation product, and wherein a flow
rate of the oxidizing fluid in the conduit is approximately equal
to a flow rate of the oxidation product in the conduit.
3193. The system of claim 3185, wherein the conduit is further
configurable to remove an oxidation product, and wherein a pressure
of the oxidizing fluid in the conduit and a pressure of the
oxidation product in the conduit are controlled to reduce
contamination of the oxidation product by the oxidizing fluid.
3194. The system of claim 3185, wherein the conduit is further
configurable to remove an oxidation product, and wherein the
oxidation product is substantially inhibited from flowing into
portions of the formation beyond the reaction zone.
3195. The system of claim 3185, wherein the oxidizing fluid is
substantially inhibited from flowing into portions of the formation
beyond the reaction zone.
3196. The system of claim 3185, further comprising a center conduit
disposed within the conduit, wherein center conduit is configurable
to provide the oxidizing fluid into the opening during use, and
wherein the second conduit is further configurable to remove an
oxidation product during use.
3197. The system of claim 3185, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3198. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3199. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3200. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3201. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3202. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3203. The system of claim 3185, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement. NDC
(HEAT EXCHANGER PREHEATING METHOD)
3204. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein heating comprises:
heating the oxidizing fluid with a heat exchanger, wherein the heat
exchanger is disposed external to the formation; providing the
heated oxidizing fluid from the heat exchanger to the portion of
the formation; and allowing heat to transfer from the heated
oxidizing fluid to the portion of the formation; providing the
oxidizing fluid to a reaction zone in the formation; allowing the
oxidizing fluid to react with at least a portion of the
hydrocarbons at the reaction zone to generate heat at the reaction
zone; and transferring the generated heat substantially by
conduction from the reaction zone to a pyrolysis zone in the
formation.
3205. The method of claim 3204, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3206. The method of claim 3204, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
3207. The method of claim 3204, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
3208. The method of claim 3204, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3209. The method of claim 3204, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid to reduce heating of the conduit by
oxidation.
3210. The method of claim 3204, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit.
3211. The method of claim 3204, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
3212. The method of claim 3204, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
3213. The method of claim 3204, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
3214. The method of claim 3204, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3215. The method of claim 3204, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3216. The method of claim 3204, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
3217. The method of claim 3204, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3218. The method of claim 3204, further comprising removing water
from the formation prior to heating the portion.
3219. The method of claim 3204, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3220. The method of claim 3204, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3221. The method of claim 3204, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3222. The method of claim 3204, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3223. The method of claim 3204, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3224. The method of claim 3204, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
3225. An in situ method for heating a coal formation, comprising:
heating a portion of the formation to a temperature sufficient to
support reaction of hydrocarbons within the portion of the
formation with an oxidizing fluid, wherein heating comprises:
oxidizing a fuel gas in a heater, wherein the heater is disposed
external to the formation; providing the oxidized fuel gas from the
heater to the portion of the formation; and allowing heat to
transfer from the oxidized fuel gas to the portion of the
formation; providing the oxidizing fluid to a reaction zone in the
formation; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbons at the reaction zone to generate heat
at the reaction zone; and transferring the generated heat
substantially by conduction from the reaction zone to a pyrolysis
zone in the formation.
3226. The method of claim 3225, further comprising transporting the
oxidizing fluid through the reaction zone by diffusion.
3227. The method of claim 3225, further comprising directing at
least a portion of the oxidizing fluid into the opening through
orifices of a conduit disposed in the opening.
3228. The method of claim 3225, further comprising controlling a
flow of the oxidizing fluid with critical flow orifices of a
conduit disposed in the opening such that a rate of oxidation is
controlled.
3229. The method of claim 3225, further comprising increasing a
flow of the oxidizing fluid in the opening to accommodate an
increase in a volume of the reaction zone such that a rate of
oxidation is substantially constant over time within the reaction
zone.
3230. The method of claim 3225, wherein a conduit is disposed in
the opening, the method further comprising cooling the conduit with
the oxidizing fluid to reduce heating of the conduit by
oxidation.
3231. The method of claim 3225, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit.
3232. The method of claim 3225, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
transferring heat from the oxidation product in the conduit to the
oxidizing fluid in the conduit.
3233. The method of claim 3225, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit, wherein a
flow rate of the oxidizing fluid in the conduit is approximately
equal to a flow rate of the oxidation product in the conduit.
3234. The method of claim 3225, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
controlling a pressure between the oxidizing fluid and the
oxidation product in the conduit to reduce contamination of the
oxidation product by the oxidizing fluid.
3235. The method of claim 3225, wherein a conduit is disposed
within the opening, the method further comprising removing an
oxidation product from the formation through the conduit and
substantially inhibiting the oxidation product from flowing into
portions of the formation beyond the reaction zone.
3236. The method of claim 3225, further comprising substantially
inhibiting the oxidizing fluid from flowing into portions of the
formation beyond the reaction zone.
3237. The method of claim 3225, wherein a center conduit is
disposed within an outer conduit, and wherein the outer conduit is
disposed within the opening, the method further comprising
providing the oxidizing fluid into the opening through the center
conduit and removing an oxidation product through the outer
conduit.
3238. The method of claim 3225, wherein the portion of the
formation extends radially from the opening a width of less than
approximately 0.2 m.
3239. The method of claim 3225, further comprising removing water
from the formation prior to heating the portion.
3240. The method of claim 3225, further comprising controlling the
temperature of the formation to substantially inhibit production of
oxides of nitrogen during oxidation.
3241. The method of claim 3225, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3242. The method of claim 3225, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3243. The method of claim 3225, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3244. The method of claim 3225, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
3245. The method of claim 3225, wherein the pyrolysis zone is
substantially adjacent to the reaction zone.
3246. A system configured to heat a coal formation, comprising: an
insulated conductor disposed within an open wellbore in the
formation, wherein the insulated conductor is configured to provide
radiant heat to at least a portion of the formation during use; and
wherein the system is configured to allow heat to transfer from the
insulated conductor to a selected section of the formation during
use.
3247. The system of claim 3246, wherein the insulated conductor is
further configured to generate heat during application of an
electrical current to the insulated conductor during use.
3248. The system of claim 3246, further comprising a support
member, wherein the support member is configured to support the
insulated conductor.
3249. The system of claim 3246, further comprising a support member
and a centralizer, wherein the support member is configured to
support the insulated conductor, and wherein the centralizer is
configured to maintain a location of the insulated conductor on the
support member.
3250. The system of claim 3246, wherein the open wellbore comprises
a diameter of at least approximately 5 cm.
3251. The system of claim 3246, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a low resistance conductor configured to
generate substantially no heat.
3252. The system of claim 3246, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a rubber insulated conductor.
3253. The system of claim 3246, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a copper wire.
3254. The system of claim 3246, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor.
3255. The system of claim 3246, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3256. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath.
3257. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the conductor comprises a copper-nickel
alloy.
3258. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper, nickel alloy,
and wherein the copper-nickel alloy comprises approximately 7%
nickel by weight to approximately 12% nickel by weight.
3259. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 2%
nickel by weight to approximately 6% nickel by weight.
3260. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises a thermally conductive material.
3261. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises magnesium oxide.
3262. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, and wherein the magnesium oxide comprises a
thickness of at least approximately 1 mm.
3263. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises aluminum oxide and magnesium oxide.
3264. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configured to occupy
porous spaces within the magnesium oxide.
3265. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath, and wherein the sheath comprises a
corrosion-resistant material.
3266. The system of claim 3246, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath, and wherein the sheath comprises stainless
steel.
3267. The system of claim 3246, further comprising two additional
insulated conductors, wherein the insulated conductor and the two
additional insulated conductors are configured in a 3-phase Y
configuration.
3268. The system of claim 3246, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configured in a series electrical configuration.
3269. The system of claim 3246, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configured in a parallel electrical
configuration.
3270. The system of claim 3246, wherein the insulated conductor is
configured to generate radiant heat of approximately 500 W/m to
approximately 1150 W/m during use.
3271. The system of claim 3246, further comprising a support member
configured to support the insulated conductor, wherein the support
member comprises orifices configured to provide fluid flow through
the support member into the open wellbore during use.
3272. The system of claim 3246, further comprising a support member
configured to support the insulated conductor, wherein the support
member comprises critical flow orifices configured to provide a
substantially constant amount of fluid flow through the support
member into the open wellbore during use.
3273. The system of claim 3246, further comprising a tube coupled
to the insulated conductor, wherein the tube is configured to
provide a flow of fluid into the open wellbore during use.
3274. The system of claim 3246, further comprising a tube coupled
to the insulated conductor, wherein the tube comprises critical
flow orifices configured to provide a substantially constant amount
of fluid flow through the support member into the open wellbore
during use.
3275. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation.
3276. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3277. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3278. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein a
packing material is disposed at a junction of the overburden casing
and the open wellbore.
3279. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
open wellbore, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the open wellbore and
the overburden casing during use.
3280. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
open wellbore, and wherein the packing material comprises
cement.
3281. The system of claim 3246, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configured to couple to the lead-in
conductor.
3282. The system of claim 3246, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some of the hydrocarbons in the selected
section.
3283. A system configurable to heat a coal formation, comprising:
an insulated conductor configurable to be disposed within an open
wellbore in the formation, wherein the insulated conductor is
further configurable to provide radiant heat to at least a portion
of the formation during use; and wherein the system is configurable
to allow heat to transfer from the insulated conductor to a
selected section of the formation during use.
3284. The system of claim 3283, wherein the insulated conductor is
further configurable to generate heat during application of an
electrical current to the insulated conductor during use.
3285. The system of claim 3283, further comprising a support
member, wherein the support member is configurable to support the
insulated conductor.
3286. The system of claim 3283, further comprising a support member
and a centralizer, wherein the support member is configurable to
support the insulated conductor, and wherein the centralizer is
configurable to maintain a location of the insulated conductor on
the support member.
3287. The system of claim 3283, wherein the open wellbore comprises
a diameter of at least approximately 5 cm.
3288. The system of claim 3283, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a low resistance conductor configurable to
generate substantially no heat.
3289. The system of claim 3283, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a rubber insulated conductor.
3290. The system of claim 3283, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a copper wire.
3291. The system of claim 3283, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor.
3292. The system of claim 3283, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3293. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath.
3294. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the conductor comprises a copper-nickel
alloy.
3295. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 7%
nickel by weight to approximately 12% nickel by weight.
3296. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 2%
nickel by weight to approximately 6% nickel by weight.
3297. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises a thermally conductive material.
3298. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises magnesium oxide.
3299. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material, comprises
magnesium oxide, and wherein the magnesium oxide comprises a
thickness of at least approximately 1 mm.
3300. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises aluminum oxide and magnesium oxide.
3301. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configurable to
occupy porous spaces within the magnesium oxide.
3302. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath, and wherein the sheath comprises a
corrosion-resistant material.
3303. The system of claim 3283, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material is
disposed in a sheath, and wherein the sheath comprises stainless
steel.
3304. The system of claim 3283, further comprising two additional
insulated conductors, wherein the insulated conductor and the two
additional insulated conductors are configurable in a 3-phase Y
configuration.
3305. The system of claim 3283, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configurable in a series electrical
configuration.
3306. The system of claim 3283, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configurable in a parallel electrical
configuration.
3307. The system of claim 3283, wherein the insulated conductor is
configurable to generate radiant heat of approximately 500 W/m to
approximately 1150 W/m during use.
3308. The system of claim 3283, further comprising a support member
configurable to support the insulated conductor, wherein the
support member comprises orifices configurable to provide fluid
flow through the support member into the open wellbore during
use.
3309. The system of claim 3283, further comprising a support member
configurable to support the insulated conductor, wherein the
support member comprises critical flow orifices configurable to
provide a substantially constant amount of fluid flow through the
support member into the open wellbore during use.
3310. The system of claim 3283, further comprising a tube coupled
to the insulated conductor, wherein the tube is configurable to
provide a flow of fluid into the open wellbore during use.
3311. The system of claim 3283, further comprising a tube coupled
to the first insulated conductor, wherein the tube comprises
critical flow orifices configurable to provide a substantially
constant amount of fluid flow through the support member into the
open wellbore during use.
3312. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation.
3313. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3314. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3315. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, and wherein a
packing material is disposed at a junction of the overburden casing
and the open wellbore.
3316. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
open wellbore, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the open wellbore and
the overburden casing during use.
3317. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
open wellbore, and wherein the packing material comprises
cement.
3318. The system of claim 3283, further comprising an overburden
casing coupled to the open wellbore, wherein the overburden casing
is disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configurable to couple to the
lead-in conductor.
3319. The system of claim 3283, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
3320. An in situ method for heating a coal formation, comprising:
applying an electrical current to an insulated conductor to provide
radiant heat to at least a portion of the formation, wherein the
insulated conductor is disposed within an open wellbore in the
formation; and allowing the radiant heat to transfer from the
insulated conductor to a selected section of the formation.
3321. The method of claim 3320, further comprising supporting the
insulated conductor on a support member.
3322. The method of claim 3320, further comprising supporting the
insulated conductor on a support member and maintaining a location
of the insulated conductor on the support member with a
centralizer.
3323. The method of claim 3320, wherein the insulated conductor is
coupled to two additional insulated conductors, wherein the
insulated conductor and the two insulated conductors are disposed
within the open wellbore, and wherein the three insulated
conductors are electrically coupled in a 3-phase Y
configuration.
3324. The method of claim 3320, wherein an additional insulated
conductor is disposed within the open wellbore.
3325. The method of claim 3320, wherein an additional insulated
conductor is disposed within the open wellbore, and wherein the
insulated conductor and the additional insulated conductor are
electrically coupled in a series configuration.
3326. The method of claim 3320, wherein an additional insulated
conductor is disposed within the open wellbore, and wherein the
insulated conductor and the additional insulated conductor are
electrically coupled in a parallel configuration.
3327. The method of claim 3320, wherein the provided heat comprises
approximately 500 W/m to approximately 1150 W/m.
3328. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the conductor comprises a copper-nickel
alloy.
3329. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 7%
nickel by weight to approximately 12% nickel by weight.
3330. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 2%
nickel by weight to approximately 6% nickel by weight.
3331. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises magnesium oxide.
3332. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, and wherein the magnesium oxide comprises a
thickness of at least approximately 1 mm.
3333. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises aluminum oxide and magnesium oxide.
3334. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configured to occupy
porous spaces within the magnesium oxide.
3335. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the insulating material is disposed in a sheath,
and wherein the sheath comprises a corrosion-resistant
material.
3336. The method of claim 3320, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the insulating material is disposed in a sheath,
and wherein the sheath comprises stainless steel.
3337. The method of claim 3320, further comprising supporting the
insulated conductor on a support member and flowing a fluid into
the open wellbore through an orifice in the support member.
3338. The method of claim 3320, further comprising supporting the
insulated conductor on a support member and flowing a substantially
constant amount of fluid into the open wellbore through critical
flow orifices in the support member.
3339. The method of claim 3320, wherein a perforated tube is
disposed in the open wellbore proximate to the insulated conductor,
the method further comprising flowing a fluid into the open
wellbore through the perforated tube.
3340. The method of claim 3320, wherein a tube is disposed in the
open wellbore proximate to the insulated conductor, the method
further comprising flowing a substantially constant amount a fluid
into the open wellbore through critical flow orifices in the
tube.
3341. The method of claim 3320, further comprising supporting the
insulated conductor on a support member and flowing a corrosion
inhibiting fluid into the open wellbore through an orifice in the
support member.
3342. The method of claim 3320, wherein a perforated tube is
disposed in the open wellbore proximate to the insulated conductor,
the method further comprising flowing a corrosion inhibiting fluid
into the open wellbore through the perforated tube.
3343. The method of claim 3320, further comprising determining a
temperature distribution in the insulated conductor using an
electromagnetic signal provided to the insulated conductor.
3344. The method of claim 3320, further comprising monitoring a
leakage current of the insulated conductor.
3345. The method of claim 3320, further comprising monitoring the
applied electrical current.
3346. The method of claim 3320, further comprising monitoring a
voltage applied to the insulated conductor.
3347. The method of claim 3320, further comprising monitoring a
temperature in the insulated conductor with at least one
thermocouple.
3348. The method of claim 3320, further comprising electrically
coupling a lead-in conductor to the insulated conductor, wherein
the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
3349. The method of claim 3320, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor.
3350. The method of claim 3320, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor, wherein the cold pin transition
conductor comprises a substantially low resistance insulated
conductor.
3351. The method of claim 3320, further comprising coupling an
overburden casing to the open wellbore, wherein the overburden
casing is disposed in an overburden of the formation.
3352. The method of claim 3320, further comprising coupling an
overburden casing to the open wellbore, wherein the overburden
casing is disposed in an overburden of the formation, and wherein
the overburden casing comprises steel.
3353. The method of claim 3320, further comprising coupling an
overburden casing to the open wellbore, wherein the overburden
casing is disposed in an overburden of the formation, and wherein
the overburden casing is further disposed in cement.
3354. The method of claim 3320, further comprising coupling an
overburden casing to the open wellbore, wherein the overburden
casing is disposed in an overburden of the formation, and wherein a
packing material is disposed at a junction of the overburden casing
and the open wellbore.
3355. The method of claim 3320, further comprising coupling an
overburden casing to the open wellbore, wherein the overburden
casing is disposed in an overburden of the formation, and wherein
the method further comprises inhibiting a flow of fluid between the
open wellbore and the overburden casing with a packing
material.
3356. The method of claim 3320, further comprising heating at least
the portion of the formation to pyrolyze at least some hydrocarbons
within the formation.
3357. An in situ method for heating a coal formation, comprising:
applying an electrical current to an insulated conductor to provide
heat to at least a portion of the formation, wherein the insulated
conductor is disposed within an opening in the formation; and
allowing the heat to transfer from the insulated conductor to a
section of the formation.
3358. The method of claim 3357, further comprising supporting the
insulated conductor on a support member.
3359. The method of claim 3357, further comprising supporting the
insulated conductor on a support member and maintaining a location
of the first insulated conductor on the support member with a
centralizer.
3360. The method of claim 3357, wherein the insulated conductor is
coupled to two additional insulated conductors, wherein the
insulated conductor and the two insulated conductors are disposed
within the opening, and wherein the three insulated conductors are
electrically coupled in a 3-phase Y configuration.
3361. The method of claim 3357, wherein an additional insulated
conductor is disposed within the opening.
3362. The method of claim 3357, wherein an additional insulated
conductor is disposed within the opening, and wherein the insulated
conductor and the additional insulated conductor are electrically
coupled in a series configuration.
3363. The method of claim 3357, wherein an additional insulated
conductor is disposed within the opening, and wherein the insulated
conductor and the additional insulated conductor are electrically
coupled in a parallel configuration.
3364. The method of claim 3357, wherein the provided heat comprises
approximately 500 W/m to approximately 1150 W/m.
3365. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the conductor comprises a copper-nickel
alloy.
3366. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 7%
nickel by weight to approximately 12% nickel by weight.
3367. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the conductor comprises a copper-nickel alloy,
and wherein the copper-nickel alloy comprises approximately 2%
nickel by weight to approximately 6% nickel by weight.
3368. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises magnesium oxide.
3369. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, and wherein the magnesium oxide comprises a
thickness of at least approximately 1 mm.
3370. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, and wherein the electrically insulating material
comprises aluminum oxide and magnesium oxide.
3371. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configured to occupy
porous spaces within the magnesium oxide.
3372. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the insulating material is disposed in a sheath,
and wherein the sheath comprises a corrosion-resistant
material.
3373. The method of claim 3357, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the insulating material is disposed in a sheath,
and wherein the sheath comprises stainless steel.
3374. The method of claim 3357, further comprising supporting the
insulated conductor on a support member and flowing a fluid into
the opening through an orifice in the support member.
3375. The method of claim 3357, further comprising supporting the
insulated conductor on a support member and flowing a substantially
constant amount of fluid into the opening through critical flow
orifices in the support member.
3376. The method of claim 3357, wherein a perforated tube is
disposed in the opening proximate to the insulated conductor, the
method further comprising flowing a fluid into the opening through
the perforated tube.
3377. The method of claim 3357, wherein a tube is disposed in the
opening proximate to the insulated conductor, the method further
comprising flowing a substantially constant amount a fluid into the
opening through critical flow orifices in the tube.
3378. The method of claim 3357, further comprising supporting the
insulated conductor on a support member and flowing a corrosion
inhibiting fluid into the opening through an orifice in the support
member.
3379. The method of claim 3357, wherein a perforated tube is
disposed in the opening proximate to the insulated conductor, the
method further comprising flowing a corrosion inhibiting fluid into
the opening through the perforated tube.
3380. The method of claim 3357, further comprising determining a
temperature distribution in the insulated conductor using an
electromagnetic signal provided to the insulated conductor.
3381. The method of claim 3357, further comprising monitoring a
leakage current of the insulated conductor.
3382. The method of claim 3357, further comprising monitoring the
applied electrical current.
3383. The method of claim 3357, further comprising monitoring a
voltage applied to the insulated conductor.
3384. The method of claim 3357, further comprising monitoring a
temperature in the insulated conductor with at least one
thermocouple.
3385. The method of claim 3357, further comprising electrically
coupling a lead-in conductor to the insulated conductor, wherein
the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
3386. The method of claim 3357, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor.
3387. The method of claim 3357, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor, wherein the cold pin transition
conductor comprises a substantially low resistance insulated
conductor.
3388. The method of claim 3357, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3389. The method of claim 3357, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3390. The method of claim 3357, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3391. The method of claim 3357, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3392. The method of claim 3357, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3393. The method of claim 3357, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some hydrocarbons within the formation.
3394. A system configured to heat a coal formation, comprising: an
insulated conductor disposed within an opening in the formation,
wherein the insulated conductor is configured to provide heat to at
least a portion of the formation during use, wherein the insulated
conductor comprises a copper-nickel alloy, and wherein the
copper-nickel alloy comprises approximately 7% nickel by weight to
approximately 12% nickel by weight; and wherein the system is
configured to allow heat to transfer from the insulated conductor
to a selected section of the formation during use.
3395. The system of claim 3394, wherein the insulated conductor is
further configured to generate heat during application of an
electrical current to the insulated conductor during use.
3396. The system of claim 3394, further comprising a support
member, wherein the support member is configured to support the
insulated conductor.
3397. The system of claim 3394, further comprising a support member
and a centralizer, wherein the support member is configured to
support the insulated conductor, and wherein the centralizer is
configured to maintain a location of the insulated conductor on the
support member.
3398. The system of claim 3394, wherein the opening comprises a
diameter of at least approximately 5 cm.
3399. The system of claim 3394, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a low resistance conductor configured to
generate substantially no heat.
3400. The system of claim 3394, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a rubber insulated conductor.
3401. The system of claim 3394, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a copper wire.
3402. The system of claim 3394, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor.
3403. The system of claim 3394, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3404. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises a thermally conductive
material.
3405. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises magnesium oxide.
3406. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, and
wherein the magnesium oxide comprises a thickness of at least
approximately 1 mm.
3407. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises aluminum oxide and
magnesium oxide.
3408. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, wherein
the magnesium oxide comprises grain particles, and wherein the
grain particles are configured to occupy porous spaces within the
magnesium oxide.
3409. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material is disposed in a sheath, and
wherein the sheath comprises a corrosion-resistant material.
3410. The system of claim 3394, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material is disposed in a sheath, and
wherein the sheath comprises stainless steel.
3411. The system of claim 3394, further comprising two additional
insulated conductors, wherein the insulated conductor and the two
additional insulated conductors are configured in a 3-phase Y
configuration.
3412. The system of claim 3394, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configured in a series electrical configuration.
3413. The system of claim 3394, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configured in a parallel electrical
configuration.
3414. The system of claim 3394, wherein the insulated conductor is
configured to generate radiant heat of approximately 500 W/m to
approximately 1150 W/m during use.
3415. The system of claim 3394, further comprising a support member
configured to support the insulated conductor, wherein the support
member comprises orifices configured to provide fluid flow through
the support member into the opening during use.
3416. The system of claim 3394, further comprising a support member
configured to support the insulated conductor, wherein the support
member comprises critical flow orifices configured to provide a
substantially constant amount of fluid flow through the support
member into the opening during use.
3417. The system of claim 3394, further comprising a tube coupled
to the insulated conductor, wherein the tube is configured to
provide a flow of fluid into the opening during use.
3418. The system of claim 3394, further comprising a tube coupled
to the insulated conductor, wherein the tube comprises critical
flow orifices configured to provide a substantially constant amount
of fluid flow through the support member into the opening during
use.
3419. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3420. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden ca sing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3421. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3422. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3423. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3424. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3425. The system of claim 3394, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configured to couple to the lead-in
conductor.
3426. The system of claim 3394, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
3427. A system configurable to heat a coal formation, comprising:
an insulated conductor configurable to be disposed within an
opening in the formation, wherein the insulated conductor is
further configurable to provide heat to at least a portion of the
formation during use, wherein the insulated conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 7% nickel by weight to approximately 12% nickel by
weight; wherein the system is configurable to allow heat to
transfer from the insulated conductor to a selected section of the
formation during use.
3428. The system of claim 3427, wherein the insulated conductor is
further configurable to generate heat during application of an
electrical current to the insulated conductor during use.
3429. The system of claim 3427, further comprising a support
member, wherein the support member is configurable to support the
insulated conductor.
3430. The system of claim 3427, further comprising a support member
and a centralizer, wherein the support member is configurable to
support the insulated conductor, and wherein the centralizer is
configurable to maintain a location of the insulated conductor on
the support member.
3431. The system of claim 3427, wherein the opening comprises a
diameter of at least approximately 5 cm.
3432. The system of claim 3427, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a low resistance conductor configurable to
generate substantially no heat.
3433. The system of claim 3427, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a rubber insulated conductor.
3434. The system of claim 3427, further comprising a lead-in
conductor coupled to the insulated conductor, wherein the lead-in
conductor comprises a copper wire.
3435. The system of claim 3427, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor.
3436. The system of claim 3427, further comprising a lead-in
conductor coupled to the insulated conductor with a cold pin
transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3437. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises a thermally conductive
material.
3438. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises magnesium oxide.
3439. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, and
wherein the magnesium oxide comprises a thickness of at least
approximately 1 mm.
3440. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises aluminum oxide and
magnesium oxide.
3441. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, wherein
the magnesium oxide comprises grain particles, and wherein the
grain particles are configurable to occupy porous spaces within the
magnesium oxide.
3442. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material is disposed in a sheath, and
wherein the sheath comprises a corrosion-resistant material.
3443. The system of claim 3427, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material is disposed in a sheath, and
wherein the sheath comprises stainless steel.
3444. The system of claim 3427, further comprising two additional
insulated conductors, wherein the insulated conductor and the two
additional insulated conductors are configurable in a 3-phase Y
configuration.
3445. The system of claim 3427, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configurable in a series electrical
configuration.
3446. The system of claim 3427, further comprising an additional
insulated conductor, wherein the insulated conductor and the
additional insulated conductor are coupled to a support member, and
wherein the insulated conductor and the additional insulated
conductor are configurable in a parallel electrical
configuration.
3447. The system of claim 3427, wherein the insulated conductor is
configurable to generate radiant heat of approximately 500 W/m to
approximately 1150 W/m during use.
3448. The system of claim 3427, further comprising a support member
configurable to support the insulated conductor, wherein the
support member comprises orifices configurable to provide fluid
flow through the support member into the open wellbore during
use.
3449. The system of claim 3427, further comprising a support member
configurable to support the insulated conductor, wherein the
support member comprises critical flow orifices configurable to
provide a substantially constant amount of fluid flow through the
support member into the opening during use.
3450. The system of claim 3427, further comprising a tube coupled
to the insulated conductor, wherein the tube is configurable to
provide a flow of fluid into the opening during use.
3451. The system of claim 3427, further comprising a tube coupled
to the insulated conductor, wherein the tube comprises critical
flow orifices configurable to provide a substantially constant
amount of fluid flow through the support member into the opening
during use.
3452. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3453. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3454. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3455. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3456. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3457. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3458. The system of claim 3427, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configurable to couple to the
lead-in conductor.
3459. The system of claim 3427, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
3460. An in situ method for heating a coal formation, comprising:
applying an electrical current to an insulated conductor to provide
heat to at least a portion of the formation, wherein the insulated
conductor is disposed within an opening in the formation, and
wherein the insulated conductor comprises a copper-nickel alloy of
approximately 7% nickel by weight to approximately 12% nickel by
weight; and allowing the heat to transfer from the insulated
conductor to a selected section of the formation.
3461. The method of claim 3460, further comprising supporting the
insulated conductor on a support member.
3462. The method of claim 3460, further comprising supporting the
insulated conductor on a support member and maintaining a location
of the first insulated conductor on the support member with a
centralizer.
3463. The method of claim 3460, wherein the insulated conductor is
coupled to two additional insulated conductors, wherein the
insulated conductor and the two insulated conductors are disposed
within the opening, and wherein the three insulated conductors are
electrically coupled in a 3-phase Y configuration.
3464. The method of claim 3460, wherein an additional insulated
conductor is disposed within the opening.
3465. The method of claim 3460, wherein an additional insulated
conductor is disposed within the opening, and wherein the insulated
conductor and the additional insulated conductor are electrically
coupled in a series configuration.
3466. The method of claim 3460, wherein an additional insulated
conductor is disposed within the opening, and wherein the insulated
conductor and the additional insulated conductor are electrically
coupled in a parallel configuration.
3467. The method of claim 3460, wherein the provided heat comprises
approximately 500 W/m to approximately 1150 W/m.
3468. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material.
3469. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises magnesium oxide.
3470. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, and
wherein the magnesium oxide comprises a thickness of at least
approximately 1 mm.
3471. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, and wherein the
electrically insulating material comprises aluminum oxide and
magnesium oxide.
3472. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
electrically insulating material comprises magnesium oxide, wherein
the magnesium oxide comprises grain particles, and wherein the
grain particles are configured to occupy porous spaces within the
magnesium oxide.
3473. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
insulating material is disposed in a sheath, and wherein the sheath
comprises a corrosion-resistant material.
3474. The method of claim 3460, wherein the copper-nickel alloy is
disposed in an electrically insulating material, wherein the
insulating material is disposed in a sheath, and wherein the sheath
comprises stainless steel.
3475. The method of claim 3460, further comprising supporting the
insulated conductor on a support member and flowing a fluid into
the opening through an orifice in the support member.
3476. The method of claim 3460, further comprising supporting the
insulated conductor on a support member and flowing a substantially
constant amount of fluid into the opening through critical flow
orifices in the support member.
3477. The method of claim 3460, wherein a perforated tube is
disposed in the opening proximate to the insulated conductor, the
method further comprising flowing a fluid into the opening through
the perforated tube.
3478. The method of claim 3460, wherein a tube is disposed in the
opening proximate to the insulated conductor, the method further
comprising flowing a substantially constant amount a fluid into the
opening through critical flow orifices in the tube.
3479. The method of claim 3460, further comprising supporting the
insulated conductor on a support member and flowing a corrosion
inhibiting fluid into the opening through an orifice in the support
member.
3480. The method of claim 3460, wherein a perforated tube is
disposed in the opening proximate to the insulated conductor, the
method further comprising flowing a corrosion inhibiting fluid into
the opening through the perforated tube.
3481. The method of claim 3460, further comprising determining a
temperature distribution in the insulated conductor using an
electromagnetic signal provided to the insulated conductor.
3482. The method of claim 3460, further comprising monitoring a
leakage current of the insulated conductor.
3483. The method of claim 3460, further comprising monitoring the
applied electrical current.
3484. The method of claim 3460, further comprising monitoring a
voltage applied to the insulated conductor.
3485. The method of claim 3460, further comprising monitoring a
temperature in the insulated conductor with at least one
thermocouple.
3486. The method of claim 3460, further comprising electrically
coupling a lead-in conductor to the insulated conductor, wherein
the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
3487. The method of claim 3460, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor.
3488. The method of claim 3460, further comprising electrically
coupling a lead-in conductor to the insulated conductor using a
cold pin transition conductor, wherein the cold pin transition
conductor comprises a substantially low resistance insulated
conductor.
3489. The method of claim 3460, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3490. The method of claim 3460, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3491. The method of claim 3460, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3492. The method of claim 3460, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3493. The method of claim 3460, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3494. The method of claim 3460, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some hydrocarbons within the formation.
3495. A system configured to heat a coal formation, comprising: at
least three insulated conductors disposed within an opening in the
formation, wherein at least the three insulated conductors are
electrically coupled in a 3-phase Y configuration, and wherein at
least the three insulated conductors are configured to provide heat
to at least a portion of the formation during use; and wherein the
system is configured to allow heat to transfer from at least the
three insulated conductors to a selected section of the formation
during use.
3496. The system of claim 3495, wherein at least the three
insulated conductors are further configured to generate heat during
application of an electrical current to at least the three
insulated conductors during use.
3497. The system of claim 3495, further comprising a support
member, wherein the support member is configured to support at
least the three insulated conductors.
3498. The system of claim 3495, further comprising a support member
and a centralizer, wherein the support member is configured to
support at least the three insulated conductors, and wherein the
centralizer is configured to maintain a location of at least the
three insulated conductors on the support member.
3499. The system of claim 3495, wherein the opening comprises a
diameter of at least approximately 5 cm.
3500. The system of claim 3495, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
low resistance conductor configured to generate substantially no
heat.
3501. The system of claim 3495, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
rubber insulated conductor.
3502. The system of claim 3495, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
copper wire.
3503. The system of claim 3495, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors with a cold pin transition conductor.
3504. The system of claim 3495, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors with a cold pin transition conductor, wherein the cold
pin transition conductor comprises a substantially low resistance
insulated conductor.
3505. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath.
3506. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the conductor
comprises a copper-nickel alloy.
3507. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 7% nickel by weight to approximately 12% nickel by
weight.
3508. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 2% nickel by weight to approximately 6% nickel by
weight.
3509. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises a thermally conductive material.
3510. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises magnesium oxide.
3511. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the electrically
insulating material comprises magnesium oxide, and wherein the
magnesium oxide comprises a thickness of at least approximately 1
mm.
3512. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises aluminum oxide and magnesium
oxide.
3513. The system of claim 3495, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configured to occupy
porous spaces within the magnesium oxide.
3514. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath, and wherein the sheath
comprises a corrosion-resistant material.
3515. The system of claim 3495, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath, and wherein the sheath
comprises stainless steel.
3516. The system of claim 3495, wherein at least the three
insulated conductors are configured to generate radiant heat of
approximately 500 W/m to approximately 150 W/m of at least the
three insulated conductors during use.
3517. The system of claim 3495, further comprising a support member
configured to support at least the three insulated conductors,
wherein the support member comprises orifices configured to provide
fluid flow through the support member into the opening during
use.
3518. The system of claim 3495, further comprising a support member
configured to support at least the three insulated conductors,
wherein the support member comprises critical flow orifices
configured to provide a substantially constant amount of fluid flow
through the support member into the opening during use.
3519. The system of claim 3495, further comprising a tube coupled
to at least the three insulated conductors, wherein the tube is
configured to provide a flow of fluid into the opening during
use.
3520. The system of claim 3495, further comprising a tube coupled
to at least the three insulated conductors, wherein the tube
comprises critical flow orifices configured to provide a
substantially constant amount of fluid flow through the support
member into the opening during use.
3521. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3522. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3523. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3524. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3525. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3526. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3527. The system of claim 3495, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configured to couple to the lead-in
conductor.
3528. The system of claim 3495, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
3529. A system configurable to heat a coal formation, comprising:
at least three insulated conductors configurable to be disposed
within an opening in the formation, wherein at least the three
insulated conductors are electrically coupled in a 3-phase Y
configuration, and wherein at least the three insulated conductors
are further configurable to provide heat to at least a portion of
the formation during use; and wherein the system is configurable to
allow heat to transfer from at least the three insulated conductors
to a selected section of the formation during use.
3530. The system of claim 3529, wherein at least the three
insulated conductors are further configurable to generate heat
during application of an electrical current to at least the three
insulated conductors during use.
3531. The system of claim 3529, further comprising a support
member, wherein the support member is configurable to support at
least the three insulated conductors.
3532. The system of claim 3529, further comprising a support member
and a centralizer, wherein the support member is configurable to
support at least the three insulated conductors, and wherein the
centralizer is configurable to maintain a location of at least the
three insulated conductors on the support member.
3533. The system of claim 3529, wherein the opening comprises a
diameter of at least approximately 5 cm.
3534. The system of claim 3529, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
low resistance conductor configurable to generate substantially no
heat.
3535. The system of claim 3529, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
rubber insulated conductor.
3536. The system of claim 3529, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors, wherein at least the one lead-in conductor comprises a
copper wire.
3537. The system of claim 3529, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors with a cold pin transition conductor.
3538. The system of claim 3529, further comprising at least one
lead-in conductor coupled to at least the three insulated
conductors with a cold pin transition conductor, wherein the cold
pin transition conductor comprises a substantially low resistance
insulated conductor.
3539. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath.
3540. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the conductor
comprises a copper-nickel alloy.
3541. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 7% nickel by weight to approximately 12% nickel by
weight.
3542. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 2% nickel by weight to approximately 6% nickel by
weight.
3543. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises a thermally conductive material.
3544. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises magnesium oxide.
3545. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the electrically
insulating material comprises magnesium oxide, and wherein the
magnesium oxide comprises a thickness of at least approximately 1
mm.
3546. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises aluminum oxide and magnesium
oxide.
3547. The system of claim 3529, wherein the insulated conductor
comprises a conductor disposed in an electrically insulating
material, wherein the electrically insulating material comprises
magnesium oxide, wherein the magnesium oxide comprises grain
particles, and wherein the grain particles are configurable to
occupy porous spaces within the magnesium oxide.
3548. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath, and wherein the sheath
comprises a corrosion-resistant material.
3549. The system of claim 3529, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material is disposed in a sheath, and wherein the sheath
comprises stainless steel.
3550. The system of claim 3529, wherein at least the three
insulated conductors are configurable to generate radiant heat of
approximately 500 W/m to approximately 1150 W/m during use.
3551. The system of claim 3529, further comprising a support member
configurable to support at least the three insulated conductors,
wherein the support member comprises orifices configurable to
provide fluid flow through the support member into the opening
during use.
3552. The system of claim 3529, further comprising a support member
configurable to support at least the three insulated conductors,
wherein the support member comprises critical flow orifices
configurable to provide a substantially constant amount of fluid
flow through the support member into the opening during use.
3553. The system of claim 3529, further comprising a tube coupled
to at least the three insulated conductors, wherein the tube is
configurable to provide a flow of fluid into the opening during
use.
3554. The system of claim 3529, further comprising a tube coupled
to at least the three insulated conductors, wherein the tube
comprises critical flow orifices configurable to provide a
substantially constant amount of fluid flow through the support
member into the opening during use.
3555. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3556. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3557. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3558. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3559. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is configurable to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3560. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3561. The system of claim 3529, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, the system further
comprising a wellhead coupled to the overburden casing and a
lead-in conductor coupled to the insulated conductor, wherein the
wellhead is disposed external to the overburden, wherein the
wellhead comprises at least one sealing flange, and wherein at
least the one sealing flange is configurable to couple to the
lead-in conductor.
3562. The system of claim 3529, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
3563. An in situ method for heating a coal formation, comprising:
applying an electrical current to at least three insulated
conductors to provide heat to at least a portion of the formation,
wherein at least the three insulated conductors are disposed within
an opening in the formation; and allowing the heat to transfer from
at least the three insulated conductors to a selected section of
the formation.
3564. The method of claim 3563, further comprising supporting at
least the three insulated conductors on a support member.
3565. The method of claim 3563, further comprising supporting at
least the three insulated conductors on a support member and
maintaining a location of at least the three insulated conductors
on the support member with a centralizer.
3566. The method of claim 3563, wherein the provided heat comprises
approximately 500 W/m to approximately 1150 W/m.
3567. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the conductor
comprises a copper-nickel alloy.
3568. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 7% nickel by weight to approximately 12% nickel by
weight.
3569. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the conductor comprises a
copper-nickel alloy, and wherein the copper-nickel alloy comprises
approximately 2% nickel by weight to approximately 6% nickel by
weight.
3570. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises magnesium oxide.
3571. The method of claim 3563 wherein at least the three insulated
conductors comprise a conductor disposed in an electrically
insulating material, wherein the electrically insulating material
comprises magnesium oxide, and wherein the magnesium oxide
comprises a thickness of at least approximately 1 mm.
3572. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, and wherein the electrically
insulating material comprises aluminum oxide and magnesium
oxide.
3573. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the electrically
insulating material comprises magnesium oxide, wherein the
magnesium oxide comprises grain particles, and wherein the grain
particles are configured to occupy porous spaces within the
magnesium oxide.
3574. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the insulating material
is disposed in a sheath, and wherein the sheath comprises a
corrosion-resistant material.
3575. The method of claim 3563, wherein at least the three
insulated conductors comprise a conductor disposed in an
electrically insulating material, wherein the insulating material
is disposed in a sheath, and wherein the sheath comprises stainless
steel.
3576. The method of claim 3563, further comprising supporting at
least the three insulated conductors on a support member and
flowing a fluid into the opening through an orifice in the support
member.
3577. The method of claim 3563, further comprising supporting at
least the three insulated conductors on a support member and
flowing a substantially constant amount of fluid into the opening
through critical flow orifices in the support member.
3578. The method of claim 3563, wherein a perforated tube is
disposed in the opening proximate to at least the three insulated
conductors, the method further comprising flowing a fluid into the
opening through the perforated tube.
3579. The method of claim 3563, wherein a tube is disposed in the
opening proximate to at least the three insulated conductors, the
method further comprising flowing a substantially constant amount a
fluid into the opening through critical flow orifices in the
tube.
3580. The method of claim 3563, further comprising supporting at
least the three insulated conductors on a support member and
flowing a corrosion inhibiting fluid into the opening through an
orifice in the support member.
3581. The method of claim 3563, wherein a perforated tube is
disposed in the opening proximate to at least the three insulated
conductors, the method further comprising flowing a corrosion
inhibiting fluid into the opening through the perforated tube.
3582. The method of claim 3563, further comprising determining a
temperature distribution in at least the three insulated conductors
using an electromagnetic signal provided to the insulated
conductor.
3583. The method of claim 3563, further comprising monitoring a
leakage current of at least the three insulated conductors.
3584. The method of claim 3563, further comprising monitoring the
applied electrical current.
3585. The method of claim 3563, further comprising monitoring a
voltage applied to at least the three insulated conductors.
3586. The method of claim 3563, further comprising monitoring a
temperature in at least the three insulated conductors with at
least one thermocouple.
3587. The method of claim 3563, further comprising electrically
coupling a lead-in conductor to at least the three insulated
conductors, wherein the lead-in conductor comprises a low
resistance conductor configured to generate substantially no
heat.
3588. The method of claim 3563, further comprising electrically
coupling a lead-in conductor to at least the three insulated
conductors using a cold pin transition conductor.
3589. The method of claim 3563, further comprising electrically
coupling a lead-in conductor to at least the three insulated
conductors using a cold pin transition conductor, wherein the cold
pin transition conductor comprises a substantially low resistance
insulated conductor.
3590. The method of claim 3563, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3591. The method of claim 3563, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3592. The method of claim 3563, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3593. The method of claim 3563, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3594. The method of claim 3563, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3595. The method of claim 3563, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the hydrocarbons within the formation.
3596. A system configured to heat a coal formation, comprising: a
first conductor disposed in a first conduit, wherein the first
conduit is disposed within an opening in the formation, and wherein
the first conductor is configured to provide heat to at least a
portion of the formation during use; and wherein the system is
configured to allow heat to transfer from the first conductor to a
section of the formation during use.
3597. The system of claim 3596, wherein the first conductor is
further configured to generate heat during application of an
electrical current to the first conductor.
3598. The system of claim 3596, wherein the first conductor
comprises a pipe.
3599. The system of claim 3596, wherein the first conductor
comprises stainless steel.
3600. The system of claim 3596, wherein the first conduit comprises
stainless steel.
3601. The system of claim 3596, further comprising a centralizer
configured to maintain a location of the first conductor within the
first conduit.
3602. The system of claim 3596, further comprising a centralizer
configured to maintain a location of the first conductor within the
first conduit, wherein the centralizer comprises ceramic
material.
3603. The system of claim 3596, further comprising a centralizer
configured to maintain a location of the first conductor within the
first conduit, wherein the centralizer comprises ceramic material
and stainless steel.
3604. The system of claim 3596, wherein the opening comprises a
diameter of at least approximately 5 cm.
3605. The system of claim 3596, further comprising a lead-in
conductor coupled to the first conductor, wherein the lead-in
conductor comprises a low resistance conductor configured to
generate substantially no heat.
3606. The system of claim 3596, further comprising a lead-in
conductor coupled to the first conductor, wherein the lead-in
conductor comprises copper.
3607. The system of claim 3596, further comprising a sliding
electrical connector coupled to the first conductor.
3608. The system of claim 3596, further comprising a sliding
electrical connector coupled to the first conductor, wherein the
sliding electrical connector is further coupled to the first
conduit.
3609. The system of claim 3596, further comprising a sliding
electrical connector coupled to the first conductor, where in the
sliding electrical connector is further coupled to the first
conduit, and wherein the sliding electrical connector is configured
to complete an electrical circuit with the first conductor and the
first conduit.
3610. The system of claim 3596, further comprising a second
conductor disposed within the first conduit and at least one
sliding electrical connector coupled to the first conductor and the
second conductor, wherein at least the one sliding electrical
connector is configured to generate less heat than the first
conductor or the second conductor during use.
3611. The system of claim 3596, wherein the first conduit comprises
a first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3612. The system of claim 3596, further comprising a fluid disposed
within the first conduit, wherein the fluid is configured to
maintain a pressure within the first conduit to substantially
inhibit deformation of the first conduit during use.
3613. The system of claim 3596, further comprising a thermally
conductive fluid disposed within the first conduit.
3614. The system of claim 3596, further comprising a thermally
conductive fluid disposed within the first conduit, wherein the
thermally conductive fluid comprises helium.
3615. The system of claim 3596, further comprising a fluid disposed
within the first conduit, wherein the fluid is configured to
substantially inhibit arcing between the first conductor and the
first conduit during use.
3616. The system of claim 3596, further comprising a tube disposed
within the opening external to the first conduit, wherein the tube
is configured to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the first conduit and the opening to substantially inhibit
deformation of the first conduit during use.
3617. The system of claim 3596, wherein the first conductor is
further configured to generate radiant heat of approximately 650
W/m to approximately 1650 W/m during use.
3618. The system of claim 3596, further comprising a second
conductor disposed within a second conduit and a third conductor
disposed within a third conduit, wherein first conduit, the second
conduit and the third conduit are disposed in different openings of
the formation, wherein the first conductor is electrically coupled
to the second conductor and the third conductor, and wherein the
first, second, and third conductors are configured to operate in a
3-phase Y configuration during use.
3619. The system of claim 3596, further comprising a second
conductor disposed within the first conduit, wherein the second
conductor is electrically coupled to the first conductor to form an
electrical circuit.
3620. The system of claim 3596, further comprising a second
conductor disposed within the first conduit, wherein the second
conductor is electrically coupled to the first conductor to form an
electrical circuit with a connector.
3621. The system of claim 3596, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3622. The system of claim 3596, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3623. The system of claim 3596, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3624. The system of claim 3596, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3625. The system of claim 3596, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3626. The system of claim 3596, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
the first conductor.
3627. The system of claim 3596, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
the first conductor, and wherein the substantially low resistance
conductor comprises carbon steel.
3628. The system of claim 3596, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing and a centralizer
configured to support the substantially low resistance conductor
within the overburden casing.
3629. The system of claim 3596, wherein the heated section of the
formation is substantially pyrolyzed.
3630. A system configurable to heat a coal formation, comprising: a
first conductor configurable to be disposed in a first conduit,
wherein the first conduit is configurable to be disposed within an
opening in the formation, and wherein the first conductor is
further configurable to provide heat to at least a portion of the
formation during use; and wherein the system is configurable to
allow heat to transfer from the first conductor to a section of the
formation during use.
3631. The system of claim 3630, wherein the first conductor is
further configurable to generate heat during application of an
electrical current to the first conductor.
3632. The system of claim 3630, wherein the first conductor
comprises a pipe.
3633. The system of claim 3630, wherein the first conductor
comprises stainless steel.
3634. The system of claim 3630, wherein the first conduit comprises
stainless steel.
3635. The system of claim 3630, further comprising a centralizer
configurable to maintain a location of the first conductor within
the first conduit.
3636. The system of claim 3630, further comprising a centralizer
configurable to maintain a location of the first conductor within
the first conduit, wherein the centralizer comprises ceramic
material.
3637. The system of claim 3630, further comprising a centralizer
configurable to maintain a location of the first conductor within
the first conduit, wherein the centralizer comprises ceramic
material and stainless steel.
3638. The system of claim 3630, wherein the opening comprises a
diameter of at least approximately 5 cm.
3639. The system of claim 3630, further comprising a lead-in
conductor coupled to the first conductor, wherein the lead-in
conductor comprises a low resistance conductor configurable to
generate substantially no heat.
3640. The system of claim 3630, further comprising a lead-in
conductor coupled to the first conductor, wherein the lead-in
conductor comprises copper.
3641. The system of claim 3630, further comprising a sliding
electrical connector coupled to the first conductor.
3642. The system of claim 3630, further comprising a sliding
electrical connector coupled to the first conductor, wherein the
sliding electrical connector is further coupled to the first
conduit.
3643. The system of claim 3630, further comprising a sliding
electrical connector coupled to the first conductor, wherein the
sliding electrical connector is further coupled to the first
conduit, and wherein the sliding electrical connector is
configurable to complete an electrical circuit with the first
conductor and the first conduit.
3644. The system of claim 3630, further comprising a second
conductor disposed within the first conduit and at least one
sliding electrical connector coupled to the first conductor and the
second conductor, wherein at least the one sliding electrical
connector is configurable to generate less heat than the first
conductor or the second conductor during use.
3645. The system of claim 3630, wherein the first conduit comprises
a first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3646. The system of claim 3630, further comprising a fluid disposed
within the first conduit, wherein the fluid is configurable to
maintain a pressure within the first conduit to substantially
inhibit deformation of the first conduit during use.
3647. The system of claim 3630, further comprising a thermally
conductive fluid disposed within the first conduit.
3648. The system of claim 3630, further comprising a thermally
conductive fluid disposed within the first conduit, wherein the
thermally conductive fluid comprises helium.
3649. The system of claim 3630, further comprising a fluid disposed
within the first conduit, wherein the fluid is configurable to
substantially inhibit arcing between the first conductor and the
first conduit during use.
3650. The system of claim 3630, further comprising a tube disposed
within the opening external to the first conduit, wherein the tube
is configurable to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the first conduit and the opening to substantially inhibit
deformation of the first conduit during use.
3651. The system of claim 3630, wherein the first conductor is
further configurable to generate radiant heat of approximately 650
W/m to approximately 1650 W/m during use.
3652. The system of claim 3630, further comprising a second
conductor disposed within a second conduit and a third conductor
disposed within a third conduit, wherein first conduit, the second
conduit and the third conduit are disposed in different openings of
the formation, wherein the first conductor is electrically coupled
to the second conductor and the third conductor, and wherein the
first, second, and third conductors are configurable to operate in
a 3-phase Y configuration during use.
3653. The system of claim 3630, further comprising a second
conductor disposed within the first conduit, wherein the second
conductor is electrically coupled to the first conductor to form an
electrical circuit.
3654. The system of claim 3630, further comprising a second
conductor disposed within the first conduit, wherein the second
conductor is electrically coupled to the first conductor to form an
electrical circuit with a connector.
3655. The system of claim 3630, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3656. The system of claim 3630, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3657. The system of claim 3630, further comprising an overburden
casing coupled to the opening, wherein the overburden casing, is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3658. The system of claim 3630, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3659. The system of claim 3630, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configurable
to substantially inhibit a flow of fluid between the opening and
the overburden casing during use.
3660. The system of claim 3630, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
the first conductor.
3661. The system of claim 3630, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
the first conductor, and wherein the substantially low resistance
conductor comprises carbon steel.
3662. The system of claim 3630, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing and a centralizer
configurable to support the substantially low resistance conductor
within the overburden casing.
3663. The system of claim 3630, wherein the heated section of the
formation is substantially pyrolyzed.
3664. An in situ method for heating a coal formation, comprising:
applying an electrical current to a first conductor to provide heat
to at least a portion of the formation, wherein the first conductor
is disposed in a first conduit, and wherein the first conduit is
disposed within an opening in the formation; and allowing the heat
to transfer from the first conductor to a section of the
formation.
3665. The method of claim 3664, wherein the first conductor
comprises a pipe.
3666. The method of claim 3664, wherein the first conductor
comprises stainless steel.
3667. The method of claim 3664, wherein the first conduit comprises
stainless steel.
3668. The method of claim 3664, further comprising maintaining a
location of the first conductor in the first conduit with a
centralizer.
3669. The method of claim 3664, further comprising maintaining a
location of the first conductor in the first conduit with a
centralizer, wherein the centralizer comprises ceramic
material.
3670. The method of claim 3664, further comprising maintaining a
location of the first conductor in the first conduit with a
centralizer, wherein the centralizer comprises ceramic material and
stainless steel.
3671. The method of claim 3664, further comprising coupling a
sliding electrical connector to the first conductor.
3672. The method of claim 3664, further comprising electrically
coupling a sliding electrical connector to the first conductor and
the first conduit, wherein the first conduit comprises an
electrical lead configured to complete an electrical circuit with
the first conductor.
3673. The method of claim 3664, further comprising coupling a
sliding electrical connector to the first conductor and the first
conduit, wherein the first conduit comprises an electrical lead
configured to complete an electrical circuit with the first
conductor, and wherein the generated heat comprises approximately
20 percent generated by the first conduit.
3674. The method of claim 3664, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
3675. The method of claim 3664, further comprising determining a
temperature distribution in the first conduit using an
electromagnetic signal provided to the conduit.
3676. The method of claim 3664, further comprising monitoring the
applied electrical current.
3677. The method of claim 3664, further comprising monitoring a
voltage applied to the first conductor.
3678. The method of claim 3664, further comprising monitoring a
temperature in the conduit with at least one thermocouple.
3679. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3680. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3681. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3682. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3683. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3684. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing, and
wherein the substantially low resistance conductor is electrically
coupled to the first conductor.
3685. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing,
wherein the substantially low resistance conductor is electrically
coupled to the first conductor, and wherein the substantially low
resistance conductor comprises carbon steel.
3686. The method of claim 3664, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing,
wherein the substantially low resistance conductor is electrically
coupled to the first conductor, and wherein the method further
comprises maintaining a location of the substantially low
resistance conductor in the overburden casing with a centralizer
support.
3687. The method of claim 3664, further comprising electrically
coupling a lead-in conductor to the first conductor, wherein the
lead-in conductor comprises a low resistance conductor configured
to generate substantially no heat.
3688. The method of claim 3664, further comprising electrically
coupling a lead-in conductor to the first conductor, wherein the
lead-in conductor comprises copper.
3689. The method of claim 3664, further comprising maintaining a
sufficient pressure between the first conduit and the formation to
substantially inhibit deformation of the first conduit.
3690. The method of claim 3664, further comprising providing a
thermally conductive fluid within the first conduit.
3691. The method of claim 3664, further comprising providing a
thermally conductive fluid within the first conduit, wherein the
thermally conductive fluid comprises helium.
3692. The method of claim 3664, further comprising inhibiting
arcing between the first conductor and the first conduit with a
fluid disposed within the first conduit.
3693. The method of claim 3664, further comprising removing a vapor
from the opening using a perforated tube disposed proximate to the
first conduit in the opening to control a pressure in the
opening.
3694. The method of claim 3664, further comprising flowing a
corrosion inhibiting fluid through a perforated tube disposed
proximate to the first conduit in the opening.
3695. The method of claim 3664, wherein a second conductor is
disposed within the first conduit, wherein the second conductor is
electrically coupled to the first conductor to form an electrical
circuit.
3696. The method of claim 3664, wherein a second conductor is
disposed within the first conduit, wherein the second conductor is
electrically coupled to the first conductor with a connector.
3697. The method of claim 3664, wherein a second conductor is
disposed within a second conduit and a third conductor is disposed
within a third conduit, wherein the second conduit and the third
conduit are disposed in different openings of the formation,
wherein the first conductor is electrically coupled to the second
conductor and the third conductor, and wherein the first, second,
and third conductors are configured to operate in a 3-phase Y
configuration.
3698. The method of claim 3664, wherein a second conductor is
disposed within the first conduit, wherein at least one sliding
electrical connector is coupled to the first conductor and the
second conductor, and wherein heat generated by at least the one
sliding electrical connector is less than heat generated by the
first conductor or the second conductor.
3699. The method of claim 3664, wherein the first conduit comprises
a first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3700. The method of claim 3664, further comprising flowing an
oxidizing fluid through an orifice in the first conduit.
3701. The method of claim 3664, further comprising disposing a
perforated tube proximate to the first conduit and flowing an
oxidizing fluid through the perforated tube.
3702. The method of claim 3664, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
3703. A system configured to heat a coal formation, comprising: a
first conductor disposed in a first conduit, wherein the first
conduit is disposed within a first opening in the formation; a
second conductor disposed in a second conduit, wherein the second
conduit is disposed within a second opening in the formation; a
third conductor disposed in a third conduit, wherein the third
conduit is disposed within a third opening in the formation,
wherein the first, second, and third conductors are electrically
coupled in a 3-phase Y configuration, and wherein the first,
second, and third conductors are configured to provide heat to at
least a portion of the formation during use; and wherein the system
is configured to allow heat to transfer from the first, second, and
third conductors to a selected section of the formation during
use.
3704. The system of claim 3703, wherein the first, second, and
third conductors are further configured to generate heat during
application of an electrical current to the first conductor.
3705. The system of claim 3703, wherein the first, second, and
third conductors comprise a pipe.
3706. The system of claim 3703, wherein the first, second, and
third conductors comprise stainless steel.
3707. The system of claim 3703, wherein the first, second, and
third openings comprise a diameter of at least approximately 5
cm.
3708. The system of claim 3703, further comprising a first sliding
electrical connector coupled to the first conductor and a second
sliding electrical connector coupled to the second conductor and a
third sliding electrical connector coupled to the third
conductor.
3709. The system of claim 3703, further comprising a first sliding
electrical connector coupled to the first conductor, wherein the
first sliding electrical connector is further coupled to the first
conduit.
3710. The system of claim 3703, further comprising a second sliding
electrical connector coupled to the second conductor, wherein the
second sliding electrical connector is further coupled to the
second conduit.
3711. The system of claim 3703, further comprising a third sliding
electrical connector coupled to the third conductor, wherein the
third sliding electrical connector is further coupled to the third
conduit.
3712. The system of claim 3703, wherein each of the first, second,
and third conduits comprises a first section and a second section,
wherein a thickness of the first section is greater than a
thickness of the second section such that heat radiated from each
of the first, second, and third conductors to the section along the
first section of each of the conduits is less than heat radiated
from the first, second, and third conductors to the section along
the second section of each of the conduits.
3713. The system of claim 3703, further comprising a fluid disposed
within the first, second, and third conduits, wherein the fluid is
configured to maintain a pressure within the first conduit to
substantially inhibit deformation of the first, second, and third
conduits during use.
3714. The system of claim 3703, further comprising a thermally
conductive fluid disposed within the first, second, and third
conduits.
3715. The system of claim 3703, further comprising a thermally
conductive fluid disposed within the first, second, and third
conduits, wherein the thermally conductive fluid comprises
helium.
3716. The system of claim 3703, further comprising a fluid disposed
within the first, second, and third conduits, wherein the fluid is
configured to substantially inhibit arcing between the first,
second, and third conductors and the first, second, and third
conduits during use.
3717. The system of claim 3703, further comprising at least one
tube disposed within the first, second, and third openings external
to the first, second, and third conduits, wherein at least the one
tube is configured to remove vapor produced from at least the
heated portion of the formation such that a pressure balance is
maintained between the first, second, and third conduits and the
first, second, and third openings to substantially inhibit
deformation of the first, second, and third conduits during
use.
3718. The system of claim 3703, wherein the first, second, and
third conductors are further configured to generate radiant heat of
approximately 650 W/m to approximately 1650 W/m during use.
3719. The system of claim 3703, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation.
3720. The system of claim 3703, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein at least the one
overburden casing comprises steel.
3721. The system of claim 3703, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein at least the one
overburden casing is further disposed in cement.
3722. The system of claim 3703, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein a packing material is
disposed at a junction of at least the one overburden casing and
the first, second, and third openings.
3723. The system of claim 3703, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, wherein a packing material is disposed
at a junction of at least the one overburden casing and the first,
second, and third openings, and wherein the packing material is
further configured to substantially inhibit a flow of fluid between
the first, second, and third opening and at least the one
overburden casing during use.
3724. The system of claim 3703, wherein the heated section of the
formation is substantially pyrolyzed.
3725. A system configurable to heat a coal formation, comprising: a
first conductor configurable to be disposed in a first conduit,
wherein the first conduit is configurable to be disposed within a
first opening in the formation; a second conductor configurable to
be disposed in a second conduit, wherein the second conduit is
configurable to be disposed within a second opening in the
formation; a third conductor configurable to be disposed in a third
conduit, wherein the third conduit is configurable to be disposed
within a third opening in the formation, wherein the first, second,
and third conductors are further configurable to be electrically
coupled in a 3-phase Y configuration, and wherein the first,
second, and third conductors are further configurable to provide
heat to at least a portion of the formation during use; and wherein
the system is configurable to allow heat to transfer from the
first, second, and third conductors to a selected section of the
formation during use.
3726. The system of claim 3725, wherein the first, second, and
third conductors are further configurable to generate heat during
application of an electrical current to the first conductor.
3727. The system of claim 3725, wherein the first, second, and
third conductors comprise a pipe.
3728. The system of claim 3725, wherein the first, second, and
third conductors comprise stainless steel.
3729. The system of claim 3725, wherein the first, second, and
third opening comprise a diameter of at least approximately 5
cm.
3730. The system of claim 3725, further comprising a first sliding
electrical connector coupled to the first conductor and a second
sliding electrical connector coupled to the second conductor and a
third sliding electrical connector coupled to the third
conductor.
3731. The system of claim 3725, further comprising a first sliding
electrical connector coupled to the first conductor, wherein the
first sliding electrical connector is further coupled to the first
conduit.
3732. The system of claim 3725, further comprising a second sliding
electrical connector coupled to the second conductor, wherein the
second sliding electrical connector is further coupled to the
second conduit.
3733. The system of claim 3725, further comprising a third sliding
electrical connector coupled to the third conductor, wherein the
third sliding electrical connector is further coupled to the third
conduit.
3734. The system of claim 3725, wherein each of the first, second,
and third conduits comprises a first section and a second section,
wherein a thickness of the first section is greater than a
thickness of the second section such that heat radiated from each
of the first, second, and third conductors to the section along the
first section of each of the conduits is less than heat radiated
from the first, second, and third conductors to the section along
the second section of each of the conduits.
3735. The system of claim 3725, further comprising a fluid disposed
within the first, second, and third conduits, wherein the fluid is
configurable to maintain a pressure within the first conduit to
substantially inhibit deformation of the first, second, and third
conduits during use.
3736. The system of claim 3725, further comprising a thermally
conductive fluid disposed within the first, second, and third
conduits.
3737. The system of claim 3725, further comprising a thermally
conductive fluid disposed within the first, second, and third
conduits, wherein the thermally conductive fluid comprises
helium.
3738. The system of claim 3725, further comprising a fluid disposed
within the first, second, and third conduits, wherein the fluid is
configurable to substantially inhibit arcing between the first,
second, and third conductors and the first, second, and third
conduits during use.
3739. The system of claim 3725, further comprising at least one
tube disposed within the first, second, and third openings external
to the first, second, and third conduits, wherein at least the one
tube is configurable to remove vapor produced from at least the
heated portion of the formation such that a pressure balance is
maintained between the first, second, and third conduits and the
first, second, and third openings to substantially inhibit
deformation of the first, second, and third conduits during
use.
3740. The system of claim 3725, wherein the first, second, and
third conductors are further configurable to generate radiant heat
of approximately 650 W/m to approximately 1650 W/m during use.
3741. The system of claim 3725, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation.
3742. The system of claim 3725, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein at least the one
overburden casing comprises steel.
3743. The system of claim 3725, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein at least the one
overburden casing is further disposed in cement.
3744. The system of claim 3725, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, and wherein a packing material is
disposed at a junction of at least the one overburden casing and
the first, second, and third openings.
3745. The system of claim 3725, further comprising at least one
overburden casing coupled to the first, second, and third openings,
wherein at least the one overburden casing is disposed in an
overburden of the formation, wherein a packing material is disposed
at a junction of at least the one overburden casing and the first,
second, and third openings, and wherein the packing material is
further configurable to substantially inhibit a flow of fluid
between the first, second, and third opening and at least the one
overburden casing during use.
3746. The system of claim 3725, wherein the heated section of the
formation is substantially pyrolyzed.
3747. An in situ method for heating a coal formation, comprising:
applying an electrical current to a first conductor to provide heat
to at least a portion of the formation, wherein the first conductor
is disposed in a first conduit, and wherein the first conduit is
disposed within a first opening in the formation; applying an
electrical current to a second conductor to provide heat to at
least a portion of the formation, wherein the second conductor is
disposed in a second conduit, and wherein the second conduit is
disposed within a second opening in the formation; applying an
electrical current to a third conductor to provide heat to at least
a portion of the formation, wherein the third conductor is disposed
in a third conduit, and wherein the third conduit is disposed
within a third opening in the formation; and allowing the heat to
transfer from the first, second, and third conductors to a selected
section of the formation.
3748. The method of claim 3747, wherein the first, second, and
third conductors comprise a pipe.
3749. The method of claim 3747, wherein the first, second, and
third conductors comprise stainless steel.
3750. The method of claim 3747, wherein the first, second, and
third conduits comprise stainless steel.
3751. The method of claim 3747, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
3752. The method of claim 3747, further comprising determining a
temperature distribution in the first, second, and third conduits
using an electromagnetic signal provided to the first, second, and
third conduits.
3753. The method of claim 3747, further comprising monitoring the
applied electrical current.
3754. The method of claim 3747, further comprising monitoring a
voltage applied to the first, second, and third conductors.
3755. The method of claim 3747, further comprising monitoring a
temperature in the first, second, and third conduits with at least
one thermocouple.
3756. The method of claim 3747, further comprising maintaining a
sufficient pressure between the first, second, and third conduits
and the first, second, and third openings to substantially inhibit
deformation of the first, second, and third conduits.
3757. The method of claim 3747, further comprising providing a
thermally conductive fluid within the first, second, and third
conduits.
3758. The method of claim 3747, further comprising providing a
thermally conductive fluid within the first, second, and third
conduits, wherein the thermally conductive fluid comprises
helium.
3759. The method of claim 3747, further comprising inhibiting
arcing between the first, second, and third conductors and the
first, second, and third conduits with a fluid disposed within the
first, second, and third conduits.
3760. The method of claim 3747, further comprising removing a vapor
from the first, second, and third openings using at least one
perforated tube disposed proximate to the first, second, and third
conduits in the first, second, and third openings to control a
pressure in the first, second, and third openings.
3761. The method of claim 3747, wherein the first, second, and
third conduits comprise a first section and a second section,
wherein a thickness of the first section is greater than a
thickness of the second section such that heat radiated from the
first, second, and third conductors to the section along the first
section of the first, second, and third conduits is less than heat
radiated from the first, second, and third conductors to the
section along the second section of the first, second, and third
conduits.
3762. The method of claim 3747, further comprising flowing an
oxidizing fluid through an orifice in the first, second, and third
conduits.
3763. The method of claim 3747, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
3764. A system configured to heat a coal formation, comprising: a
first conductor disposed in a conduit, wherein the conduit is
disposed within an opening in the formation; and a second conductor
disposed in the conduit, wherein the second conductor is
electrically coupled to the first conductor with a connector, and
wherein the first and second conductors are configured to provide
heat to at least a portion of the formation during use; and wherein
the system is configured to allow heat to transfer from the first
and second conductors to a selected section of the formation during
use.
3765. The system of claim 3764, wherein the first conductor is
further configured to generate heat during application of an
electrical current to the first conductor.
3766. The system of claim 3764, wherein the first and second
conductors comprise a pipe.
3767. The system of claim 3764, wherein the first and second
conductors comprise stainless steel.
3768. The system of claim 3764, wherein the conduit comprises
stainless steel.
3769. The system of claim 3764, further comprising a centralizer
configured to maintain a location of the first and second
conductors within the conduit.
3770. The system of claim 3764, further comprising a centralizer
configured to maintain a location of the first and second
conductors within the conduit, wherein the centralizer comprises
ceramic material.
3771. The system of claim 3764, further comprising a centralizer
configured to maintain a location of the first and second
conductors within the conduit, wherein the centralizer comprises
ceramic material and stainless steel.
3772. The system of claim 3764, wherein the opening comprises a
diameter of at least approximately 5 cm.
3773. The system of claim 3764, further comprising a lead-in
conductor coupled to the first and second conductors, wherein the
lead-in conductor comprises a low resistance conductor configured
to generate substantially no heat.
3774. The system of claim 3764, further comprising a lead-in
conductor coupled to the first and second conductors, wherein the
lead-in conductor comprises copper.
3775. The system of claim 3764, wherein the conduit comprises a
first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3776. The system of claim 3764, further comprising a fluid disposed
within the conduit, wherein the fluid is configured to maintain a
pressure within the conduit to substantially inhibit deformation of
the conduit during use.
3777. The system of claim 3764, further comprising a thermally
conductive fluid disposed within the conduit.
3778. The system of claim 3764, further comprising a thermally
conductive fluid disposed within the conduit, wherein the thermally
conductive fluid comprises helium.
3779. The system of claim 3764, further comprising a fluid disposed
within the conduit, wherein the fluid is configured to
substantially inhibit arcing between the first and second
conductors and the conduit during use.
3780. The system of claim 3764, further comprising a tube disposed
within the opening external to the conduit, wherein the tube is
configured to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the conduit and the opening to substantially inhibit
deformation of the conduit during use.
3781. The system of claim 3764, wherein the first and second
conductors are further configured to generate radiant heat of
approximately 650 W/m to approximately 1650 W/m during use.
3782. The system of claim 3764, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3783. The system of claim 3764, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3784. The system of claim 3764, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3785. The system of claim 3764, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3786. The system of claim 3764, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3787. The system of claim 3764, wherein the heated section of the
formation is substantially pyrolyzed.
3788. A system configurable to heat a coal formation, comprising: a
first conductor configurable to be disposed in a conduit, wherein
the conduit is configurable to be disposed within an opening in the
formation; and a second conductor configurable to be disposed in
the conduit, wherein the second conductor is configurable to be
electrically coupled to the first conductor with a connector, and
wherein the first and second conductors are further configurable to
provide heat to at least a portion of the formation during use; and
wherein the system is configurable to allow heat to transfer from
the first and second conductors to a selected section of the
formation during use.
3789. The system of claim 3788, wherein the first conductor is
further configurable to generate heat during application of an
electrical current to the first conductor.
3790. The system of claim 3788, wherein the first and second
conductors comprise a pipe.
3791. The system of claim 3788, wherein the first and second
conductors comprise stainless steel.
3792. The system of claim 3788, wherein the conduit comprises
stainless steel.
3793. The system of claim 3788, further comprising a centralizer
configurable to maintain a location of the first and second
conductors within the conduit.
3794. The system of claim 3788, further comprising a centralizer
configurable to maintain a location of the first and second
conductors within the conduit, wherein the centralizer comprises
ceramic material.
3795. The system of claim 3788, further comprising a centralizer
configurable to maintain a location of the first and second
conductors within the conduit, wherein the centralizer comprises
ceramic material and stainless steel.
3796. The system of claim 3788, wherein the opening comprises a
diameter of at least approximately 5 cm.
3797. The system of claim 3788, further comprising a lead-in
conductor coupled to the first and second conductors, wherein the
lead-in conductor comprises a low resistance conductor configurable
to generate substantially no heat.
3798. The system of claim 3788, further comprising a lead-in
conductor coupled to the first and second conductors, wherein the
lead-in conductor comprises copper.
3799. The system of claim 3788, wherein the conduit comprises a
first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3800. The system of claim 3788, further comprising a fluid disposed
within the conduit, wherein the fluid is configurable to maintain a
pressure within the conduit to substantially inhibit deformation of
the conduit during use.
3801. The system of claim 3788, further comprising a thermally
conductive fluid disposed within the conduit.
3802. The system of claim 3788, further comprising a thermally
conductive fluid disposed within the conduit, wherein the thermally
conductive fluid comprises helium.
3803. The system of claim 3788, further comprising a fluid disposed
within the conduit, wherein the fluid is configurable to
substantially inhibit arcing between the first and second
conductors and the conduit during use.
3804. The system of claim 3788, further comprising a tube disposed
within the opening external to the conduit, wherein the tube is
configurable to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the conduit and the opening to substantially inhibit
deformation of the conduit during use.
3805. The system of claim 3788, wherein the first and second
conductors are further configurable to generate radiant heat of
approximately 650 W/m to approximately 1650 W/m during use.
3806. The system of claim 3788, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3807. The system of claim 3788, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3808. The system of claim 3788, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3809. The system of claim 3788, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3810. The system of claim 3788, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configurable
to substantially inhibit a flow of fluid between the opening and
the overburden casing during use.
3811. The system of claim 3788, wherein the heated section of the
formation is substantially pyrolyzed.
3812. An in situ method for heating a coal formation, comprising:
applying an electrical current to at least two conductors to
provide heat to at least a portion of the formation, wherein at
least the two conductors are disposed within a conduit, wherein the
conduit is disposed within an opening in the formation, and wherein
at least the two conductors are electrically coupled with a
connector; and allowing heat to transfer from at least the two
conductors to a selected section of the formation.
3813. The method of claim 3812, wherein at least the two conductors
comprise a pipe.
3814. The method of claim 3812, wherein at least the two conductors
comprise stainless steel.
3815. The method of claim 3812, wherein the conduit comprises
stainless steel.
3816. The method of claim 3812, further comprising maintaining a
location of at least the two conductors in the conduit with a
centralizer.
3817. The method of claim 3812, further comprising maintaining a
location of at least the two conductors in the conduit with a
centralizer, wherein the centralizer comprises ceramic
material.
3818. The method of claim 3812, further comprising maintaining a
location of at least the two conductors in the conduit with a
centralizer, wherein the centralizer comprises ceramic material and
stainless steel.
3819. The method of claim 3812, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
3820. The method of claim 3812, further comprising determining a
temperature distribution in the conduit using an electromagnetic
signal provided to the conduit.
3821. The method of claim 3812, further comprising monitoring the
applied electrical current.
3822. The method of claim 3812, further comprising monitoring a
voltage applied to at least the two conductors.
3823. The method of claim 3812, further comprising monitoring a
temperature in the conduit with at least one thermocouple.
3824. The method of claim 3812, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3825. The method of claim 3812, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3826. The method of claim 3812, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3827. The method of claim 3812, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3828. The method of claim 3812, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3829. The method of claim 3812, further comprising maintaining a
sufficient pressure between the conduit and the formation to
substantially inhibit deformation of the conduit.
3830. The method of claim 3812, further comprising providing a
thermally conductive fluid within the conduit.
3831. The method of claim 3812, further comprising providing a
thermally conductive fluid within the conduit, wherein the
thermally conductive fluid comprises helium.
3832. The method of claim 3812, further comprising inhibiting
arcing between at least the two conductors and the conduit with a
fluid disposed within the conduit.
3833. The method of claim 3812, further comprising removing a vapor
from the opening using a perforated tube disposed proximate to the
conduit in the opening to control a pressure in the opening.
3834. The method of claim 3812, further comprising flowing a
corrosion inhibiting fluid through a perforated tube disposed
proximate to the conduit in the opening.
3835. The method of claim 3812, wherein the conduit comprises a
first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3836. The method of claim 3812, further comprising flowing an
oxidizing fluid through an orifice in the conduit.
3837. The method of claim 3812, further comprising disposing a
perforated tube proximate to the conduit and flowing an oxidizing
fluid through the perforated tube.
3838. The method of claim 3812, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
3839. A system configured to heat a coal formation, comprising: at
least one conductor disposed in a conduit, wherein the conduit is
disposed within an opening in the formation, and wherein at least
the one conductor is configured to provide heat to at least a first
portion of the formation during use; at least one sliding
connector, wherein at least the one sliding connector is coupled to
at least the one conductor, wherein at least the one sliding
connector is configured to provide heat during use, and wherein
heat provided by at least the one sliding connector is
substantially less than the heat provided by at least the one
conductor during use; and wherein the system is configured to allow
heat to transfer from at least the one conductor to a section of
the formation during use.
3840. The system of claim 3839, wherein at least the one conductor
is further configured to generate heat during application of an
electrical current to at least the one conductor.
3841. The system of claim 3839, wherein at least the one conductor
comprises a pipe.
3842. The system of claim 3839, wherein at least the one conductor
comprises stainless steel.
3843. The system of claim 3839, wherein the conduit comprises
stainless steel.
3844. The system of claim 3839, further comprising a centralizer
configured to maintain a location of at least the one conductor
within the conduit.
3845. The system of claim 3839, further comprising a centralizer
configured to maintain a location of at least the one conductor
within the conduit, wherein the centralizer comprises ceramic
material.
3846. The system of claim 3839, further comprising a centralizer
configured to maintain a location of at least the one conductor
within the conduit, wherein the centralizer comprises ceramic
material and stainless steel.
3847. The system of claim 3839, wherein the opening comprises a
diameter of at least approximately 5 cm.
3848. The system of claim 3839, further comprising a lead-in
conductor coupled to at least the one conductor, wherein the
lead-in conductor comprises a low resistance conductor configured
to generate substantially no heat.
3849. The system of claim 3839, further comprising a lead-in
conductor coupled to at least the one conductor, wherein the
lead-in conductor comprises copper.
3850. The system of claim 3839, wherein the conduit comprises a
first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3851. The system of claim 3839, further comprising a fluid disposed
within the conduit, wherein the fluid is configured to maintain a
pressure within the conduit to substantially inhibit deformation of
the conduit during use.
3852. The system of claim 3839, further comprising a thermally
conductive fluid disposed within the conduit.
3853. The system of claim 3839, further comprising a thermally
conductive fluid disposed within the conduit, wherein the thermally
conductive fluid comprises helium.
3854. The system of claim 3839, further comprising a fluid disposed
within the conduit, wherein the fluid is configured to
substantially inhibit arcing between at least the one conductor and
the conduit during use.
3855. The system of claim 3839, further comprising a tube disposed
within the opening external to the conduit, wherein the tube is
configured to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the conduit and the opening to substantially inhibit
deformation of the conduit during use.
3856. The system of claim 3839, wherein at least the one conductor
is further configured to generate radiant heat of approximately 650
W/m to approximately 1650 W/m during use.
3857. The system of claim 3839, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3858. The system of claim 3839, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3859. The system of claim 3839, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3860. The system of claim 3839, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3861. The system of claim 3839, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3862. The system of claim 3839, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
at least the one conductor.
3863. The system of claim 3839, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
at least the one conductor, and wherein the substantially low
resistance conductor comprises carbon steel.
3864. The system of claim 3839, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing and a centralizer
configured to support the substantially low resistance conductor
within the overburden casing.
3865. The system of claim 3839, wherein the heated section of the
formation is substantially pyrolyzed.
3866. A system configurable to heat a coal formation, comprising:
at least one conductor configurable to be disposed in a conduit,
wherein the conduit is configurable to be disposed within an
opening in the formation, and wherein at least the one conductor is
further configurable to provide heat to at least a first portion of
the formation during use; at least one sliding connector, wherein
at least the one sliding connector is configurable to be coupled to
at least the one conductor, wherein at least the one sliding
connector is further configurable to provide heat during use, and
wherein heat provided by at least the one sliding connector is
substantially less than the heat provided by at least the one
conductor during use; and wherein the system is configurable to
allow heat to transfer from at least the one conductor to a section
of the formation during use.
3867. The system of claim 3866, wherein at least the one conductor
is further configurable to generate heat during application of an
electrical current to at least the one conductor.
3868. The system of claim 3866, wherein at least the one conductor
comprises a pipe.
3869. The system of claim 3866, wherein at least the one conductor
comprises stainless steel.
3870. The system of claim 3866, wherein the conduit comprises
stainless steel.
3871. The system of claim 3866, further comprising a centralizer
configurable to maintain a location of at least the one conductor
within the conduit.
3872. The system of claim 3866, further comprising a centralizer
configurable to maintain a location of at least the one conductor
within the conduit, wherein the centralizer comprises ceramic
material.
3873. The system of claim 3866, further comprising a centralizer
configurable to maintain a location of at least the one conductor
within the conduit, wherein the centralizer comprises ceramic
material and stainless steel.
3874. The system of claim 3866, wherein the opening comprises a
diameter of at least approximately 5 cm.
3875. The system of claim 3866, further comprising a lead-in
conductor coupled to at least the one conductor, wherein the
lead-in conductor comprises a low resistance conductor configurable
to generate substantially no heat.
3876. The system of claim 3866, further comprising a lead-in
conductor coupled to at least the one conductor, wherein the
lead-in conductor comprises copper.
3877. The system of claim 3866, wherein the conduit comprises a
first section and a second section, wherein a thickness of the
first section is greater than a thickness of the second section
such that heat radiated from the first conductor to the section
along the first section of the conduit is less than heat radiated
from the first conductor to the section along the second section of
the conduit.
3878. The system of claim 3866, further comprising a fluid disposed
within the conduit, wherein the fluid is configurable to maintain a
pressure within the conduit to substantially inhibit deformation of
the conduit during use.
3879. The system of claim 3866, further comprising a thermally
conductive fluid disposed within the conduit.
3880. The system of claim 3866, further comprising a thermally
conductive fluid disposed within the conduit, wherein the thermally
conductive fluid comprises helium.
3881. The system of claim 3866, further comprising a fluid disposed
within the conduit, wherein the fluid is configurable to
substantially inhibit arcing between at least the one conductor and
the conduit during use.
3882. The system of claim 3866, further comprising a tube disposed
within the opening external to the conduit, wherein the tube is
configurable to remove vapor produced from at least the heated
portion of the formation such that a pressure balance is maintained
between the conduit and the opening to substantially inhibit
deformation of the conduit during use.
3883. The system of claim 3866, wherein at least the one conductor
is further configurable to generate radiant heat of approximately
650 W/m to approximately 1650 W/m during use.
3884. The system of claim 3866, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3885. The system of claim 3866, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3886. The system of claim 3866, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3887. The system of claim 3866, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3888. The system of claim 3866, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configurable
to substantially inhibit a flow of fluid between the opening and
the overburden casing during use.
3889. The system of claim 3866, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
at least the one conductor.
3890. The system of claim 3866, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing, wherein the
substantially low resistance conductor is electrically coupled to
at least the one conductor, and wherein the substantially low
resistance conductor comprises carbon steel.
3891. The system of claim 3866, further comprising an overburden
casing coupled to the opening and a substantially low resistance
conductor disposed within the overburden casing and a centralizer
configurable to support the substantially low resistance conductor
within the overburden casing.
3892. The system of claim 3866, wherein the heated section of the
formation is substantially pyrolyzed.
3893. An in situ method for heating a coal formation, comprising:
applying an electrical current to at least one conductor and at
least one sliding connector to provide heat to at least a portion
of the formation, wherein at least the one conductor and at least
the one sliding connector are disposed within a conduit, and
wherein heat provided by at least the one conductor is
substantially greater than heat provided by at least the one
sliding connector; and allowing the heat to transfer from at least
the one conductor and at least the one sliding connector to a
section of the formation.
3894. The method of claim 3893, wherein at least the one conductor
comprises a pipe.
3895. The method of claim 3893, wherein at least the one conductor
comprises stainless steel.
3896. The method of claim 3893, wherein the conduit comprises
stainless steel.
3897. The method of claim 3893, further comprising maintaining a
location of at least the one conductor in the conduit with a
centralizer.
3898. The method of claim 3893, further comprising maintaining a
location of at least the one conductor in the conduit with a
centralizer, wherein the centralizer comprises ceramic
material.
3899. The method of claim 3893, further comprising maintaining a
location of at least the one conductor in the conduit with a
centralizer, wherein the centralizer comprises ceramic material and
stainless steel.
3900. The method of claim 3893, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
3901. The method of claim 3893, further comprising determining a
temperature distribution in the conduit using an electromagnetic
signal provided to the conduit.
3902. The method of claim 3893, further comprising monitoring the
applied electrical current.
3903. The method of claim 3893, further comprising monitoring a
voltage applied to at least the one conductor.
3904. The method of claim 3893, further comprising monitoring a
temperature in the conduit with at least one thermocouple.
3905. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3906. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3907. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3908. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3909. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the method
further comprises inhibiting a flow of fluid between the opening
and the overburden casing with a packing material.
3910. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing, and
wherein the substantially low resistance conductor is electrically
coupled to at least the one conductor.
3911. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing,
wherein the substantially low resistance conductor is electrically
coupled to at least the one conductor, and wherein the
substantially low resistance conductor comprises carbon steel.
3912. The method of claim 3893, further comprising coupling an
overburden casing to the opening, wherein a substantially low
resistance conductor is disposed within the overburden casing,
wherein the substantially low resistance conductor is electrically
coupled to at least the one conductor, and wherein the method
further comprises maintaining a location of the substantially low
resistance conductor in the overburden casing with a centralizer
support.
3913. The method of claim 3893, further comprising electrically
coupling a lead-in conductor to at least the one conductor, wherein
the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
3914. The method of claim 3893, further comprising electrically
coupling a lead-in conductor to at least the one conductor, wherein
the lead-in conductor comprises copper.
3915. The method of claim 3893, further comprising maintaining a
sufficient pressure between the conduit and the formation to
substantially inhibit deformation of the conduit.
3916. The method of claim 3893, further comprising providing a
thermally conductive fluid within the conduit.
3917. The method of claim 3893, further comprising providing a
thermally conductive fluid within the conduit, wherein the
thermally conductive fluid comprises helium.
3918. The method of claim 3893, further comprising inhibiting
arcing between the conductor and the conduit with a fluid disposed
within the conduit.
3919. The method of claim 3893, further comprising removing a vapor
from the opening using a perforated tube disposed proximate to the
conduit in the opening to control a pressure in the opening.
3920. The method of claim 3893, further comprising flowing a
corrosion inhibiting fluid through a perforated tube disposed
proximate to the conduit in the opening.
3921. The method of claim 3893, further comprising flowing an
oxidizing fluid through an orifice in the conduit.
3922. The method of claim 3893, further comprising disposing a
perforated tube proximate to the conduit and flowing an oxidizing
fluid through the perforated tube.
3923. The method of claim 3893, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
3924. A system configured to heat a coal formation, comprising: at
least one elongated member disposed within an opening in the
formation, wherein at least the one elongated member is configured
to provide heat to at least a portion of the formation during use;
and wherein the system is configured to allow heat to transfer from
at least the one elongated member to a section of the formation
during use.
3925. The system of claim 3924, wherein at least the one elongated
member comprises stainless steel.
3926. The system of claim 3924, wherein at least the one elongated
member is further configured to generate heat during application of
an electrical current to at least the one elongated member.
3927. The system of claim 3924, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configured to support at least the one elongated
member.
3928. The system of claim 3924, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configured to support at least the one elongated member,
and wherein the support member comprises openings.
3929. The system of claim 3924, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configured to support at least the one elongated member,
wherein the support member comprises openings, wherein the openings
are configured to flow a fluid along a length of at least the one
elongated member during use, and wherein the fluid is configured to
substantially inhibit carbon deposition on or proximate to at least
the one elongated member during use.
3930. The system of claim 3924, further comprising a tube disposed
in the opening, wherein the tube comprises openings, wherein the
openings are configured to flow a fluid along a length of at least
the one elongated member during use, and wherein the fluid is
configured to substantially inhibit carbon deposition on or
proximate to at least the one elongated member during use.
3931. The system of claim 3924, further comprising a centralizer
coupled to at least the one elongated member, wherein the
centralizer is configured to electrically isolate at least the one
elongated member.
3932. The system of claim 3924, further comprising a centralizer
coupled to at least the one elongated member and a support member
coupled to at least the one elongated member, wherein the
centralizer is configured to maintain a location of at least the
one elongated member on the support member.
3933. The system of claim 3924, wherein the opening comprises a
diameter of at least approximately 5 cm.
3934. The system of claim 3924, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a low resistance conductor configured
to generate substantially no heat.
3935. The system of claim 3924, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a rubber insulated conductor.
3936. The system of claim 3924, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises copper wire.
3937. The system of claim 3924, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor.
3938. The system of claim 3924, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3939. The system of claim 3924, wherein at least the one elongated
member is arranged in a series electrical configuration.
3940. The system of claim 3924, wherein at least the one elongated
member is arranged in a parallel electrical configuration.
3941. The system of claim 3924, wherein at least the one elongated
member is configured to generate radiant heat of approximately 650
W/m to approximately 1650 W/m during use.
3942. The system of claim 3924, further comprising a perforated
tube disposed in the opening external to at least the one elongated
member, wherein the perforated tube is configured to remove vapor
from the opening to control a pressure in the opening during
use.
3943. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3944. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3945. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3946. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3947. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3948. The system of claim 3924, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
3949. The system of claim 3924, wherein the heated section of the
formation is substantially pyrolyzed.
3950. A system configurable to heat a coal formation, comprising:
at least one elongated member configurable to be disposed within an
opening in the formation, wherein at least the one elongated member
is further configurable to provide heat to at least a portion of
the formation during use; and wherein the system is configurable to
allow heat to transfer from at least the one elongated member to a
section of the formation during use.
3951. The system of claim 3950, wherein at least the one elongated
member comprises stainless steel.
3952. The system of claim 3950, wherein at least the one elongated
member is further configurable to generate heat during application
of an electrical current to at least the one elongated member.
3953. The system of claim 3950, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configurable to support at least the one elongated
member.
3954. The system of claim 3950, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configurable to support at least the one elongated
member, and wherein the support member comprises openings.
3955. The system of claim 3950, further comprising a support member
coupled to at least the one elongated member, wherein the support
member is configurable to support at least the one elongated
member, wherein the support member comprises openings, wherein the
openings are configurable to flow a fluid along a length of at
least the one elongated member during use, and wherein the fluid is
configurable to substantially inhibit carbon deposition on or
proximate to at least the one elongated member during use.
3956. The system of claim 3950, further comprising a tube disposed
in the opening, wherein the tube comprises openings, wherein the
openings are configurable to flow a fluid along a length of at
least the one elongated member during use, and wherein the fluid is
configurable to substantially inhibit carbon deposition on or
proximate to at least the one elongated member during use.
3957. The system of claim 3950, further comprising a centralizer
coupled to at least the one elongated member, wherein the
centralizer is configurable to electrically isolate at least the
one elongated member.
3958. The system of claim 3950, further comprising a centralizer
coupled to at least the one elongated member and a support member
coupled to at least the one elongated member, wherein the
centralizer is configurable to maintain a location of at least the
one elongated member on the support member.
3959. The system of claim 3950, wherein the opening comprises a
diameter of at least approximately 5 cm.
3960. The system of claim 3950, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a low resistance conductor configurable
to generate substantially no heat.
3961. The system of claim 3950, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a rubber insulated conductor.
3962. The system of claim 3950, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises copper wire.
3963. The system of claim 3950, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor.
3964. The system of claim 3950, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
3965. The system of claim 3950, wherein at least the one elongated
member is arranged in a series electrical configuration.
3966. The system of claim 3950, wherein at least the one elongated
member is arranged in a parallel electrical configuration.
3967. The system of claim 3950, wherein at least the one elongated
member is configurable to generate radiant heat of approximately
650 W/m to approximately 1650 W/m during use.
3968. The system of claim 3950, further comprising a perforated
tube disposed in the opening external to at least the one elongated
member, wherein the perforated tube is configurable to remove vapor
from the opening to control a pressure in the opening during
use.
3969. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3970. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
3971. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
3972. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
3973. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
3974. The system of claim 3950, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configurable
to substantially inhibit a flow of fluid between the opening and
the overburden casing during use.
3975. The system of claim 3950, wherein the heated section of the
formation is substantially pyrolyzed.
3976. An in situ method for heating a coal formation, comprising:
applying an electrical current to at least one elongated member to
provide heat to at least a portion of the formation, wherein at
least the one elongated member is disposed within an opening of the
formation; and allowing heat to transfer from at least the one
elongated member to a section of the formation.
3977. The method of claim 3976, wherein at least the one elongated
member comprises a metal strip.
3978. The method of claim 3976, wherein at least the one elongated
member comprises a metal rod.
3979. The method of claim 3976, wherein at least the one elongated
member comprises stainless steel.
3980. The method of claim 3976, further comprising supporting at
least the one elongated member on a center support member.
3981. The method of claim 3976, further comprising supporting at
least the one elongated member on a center support member, wherein
the center support member comprises a tube.
3982. The method of claim 3976, further comprising electrically
isolating at least the one elongated member with a centralizer.
3983. The method of claim 3976, further comprising laterally
spacing at least the one elongated member with a centralizer.
3984. The method of claim 3976, further comprising electrically
coupling at least the one elongated member in a series
configuration.
3985. The method of claim 3976, further comprising electrically
coupling at least the one elongated member in a parallel
configuration.
3986. The method of claim 3976, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
3987. The method of claim 3976, further comprising determining a
temperature distribution in at least the one elongated member using
an electromagnetic signal provided to at least the one elongated
member.
3988. The method of claim 3976, further comprising monitoring the
applied electrical current.
3989. The method of claim 3976, further comprising monitoring a
voltage applied to at least the one elongated member.
3990. The method of claim 3976, further comprising monitoring a
temperature in at least the one elongated member with at least one
thermocouple.
3991. The method of claim 3976, further comprising supporting at
least the one elongated member on a center support member, wherein
the center support member comprises openings, the method further
comprising flowing an oxidizing fluid through the openings to
substantially inhibit carbon deposition proximate to or on at least
the one elongated member.
3992. The method of claim 3976, further comprising flowing an
oxidizing fluid through a tube disposed proximate to at least the
one elongated member to substantially inhibit carbon deposition
proximate to or on at least the one elongated member.
3993. The method of claim 3976, further comprising flowing an
oxidizing fluid through an opening in at least the one elongated
member to substantially inhibit carbon deposition proximate to or
on at least the one elongated member.
3994. The method of claim 3976, further comprising electrically
coupling a lead-in conductor to at least the one elongated member,
wherein the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
3995. The method of claim 3976, further comprising electrically
coupling a lead-in conductor to at least the one elongated member
using a cold pin transition conductor.
3996. The method of claim 3976, further comprising electrically
coupling a lead-in conductor to at least the one elongated member
using a cold pin transition conductor, wherein the cold pin
transition conductor comprises a substantially low resistance
insulated conductor.
3997. The method of claim 3976, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
3998. The method of claim 3976, further comprising coupling an
overburden casing to the opening, wherein the overburden casing
comprises steel.
3999. The method of claim 3976, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in cement.
4000. The method of claim 3976, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
4001. The method of claim 3976, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the opening,
and wherein the method further comprises inhibiting a flow of fluid
between the opening and the overburden casing with the packing
material.
4002. The method of claim 3976, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
4003. A system configured to heat a coal formation, comprising: at
least one elongated member disposed within an opening in the
formation, wherein at least the one elongated member is configured
to provide heat to at least a portion of the formation during use;
an oxidizing fluid source; a conduit disposed within the opening,
wherein the conduit is configured to provide an oxidizing fluid
from the oxidizing fluid source to the opening during use, and
wherein the oxidizing fluid is selected to substantially inhibit
carbon deposition on or proximate to at least the one elongated
member during use; and wherein the system is configured to allow
heat to transfer from at least the one elongated member to a
section of the formation during use.
4004. The system of claim 4003, wherein at least the one elongated
member comprises stainless steel.
4005. The system of claim 4003, wherein at least the one elongated
member is further configured to generate heat during application of
an electrical current to at least the one elongated member.
4006. The system of claim 4003, wherein at least the one elongated
member is coupled to the conduit, wherein the conduit is further
configured to support at least the one elongated member.
4007. The system of claim 4003, wherein at least the one elongated
member is coupled to the conduit, wherein the conduit is further
configured to support at least the one elongated member, and
wherein the conduit comprises openings.
4008. The system of claim 4003, further comprising a centralizer
coupled to at least the one elongated member and the conduit,
wherein the centralizer is configured to electrically isolate at
least the one elongated member from the conduit.
4009. The system of claim 4003, further comprising a centralizer
coupled to at least the one elongated member and the conduit,
wherein the centralizer is configured to maintain a location of at
least the one elongated member on the conduit.
4010. The system of claim 4003, wherein the opening comprises a
diameter of at least approximately 5 cm.
4011. The system of claim 4003, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a low resistance conductor configured
to generate substantially no heat.
4012. The system of claim 4003, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a rubber insulated conductor.
4013. The system of claim 4003, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises copper wire.
4014. The system of claim 4003, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor.
4015. The system of claim 4003, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
4016. The system of claim 4003, wherein at least the one elongated
member is arranged in a series electrical configuration.
4017. The system of claim 4003, wherein at least the one elongated
member is arranged in a parallel electrical configuration.
4018. The system of claim 4003, wherein at least the one elongated
member is configured to generate radiant heat of approximately 650
W/m to approximately 1650 W/m during use.
4019. The system of claim 4003, further comprising a perforated
tube disposed in the opening external to at least the one elongated
member, wherein the perforated tube is configured to remove vapor
from the opening to control a pressure in the opening during
use.
4020. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
4021. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
4022. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
4023. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
4024. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
4025. The system of claim 4003, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configured to
substantially inhibit a flow of fluid between the opening and the
overburden casing during use.
4026. The system of claim 4003, wherein the heated section of the
formation is substantially pyrolyzed.
4027. A system configurable to heat a coal formation, comprising:
at least one elongated member configurable to be disposed within an
opening in the formation, wherein at least the one elongated member
is further configurable to provide heat to at least a portion of
the formation during use; a conduit configurable to be disposed
within the opening, wherein the conduit is further configurable to
provide an oxidizing fluid from the oxidizing fluid source to the
opening during use, and wherein the system is configurable to allow
the oxidizing fluid to substantially inhibit carbon deposition on
or proximate to at least the one elongated member during use; and
wherein the system is further configurable to allow heat to
transfer from at least the one elongated member to a section of the
formation during use.
4028. The system of claim 4027, wherein at least the one elongated
member comprises stainless steel.
4029. The system of claim 4027, wherein at least the one elongated
member is further configurable to generate heat during application
of an electrical current to at least the one elongated member.
4030. The system of claim 4027, wherein at least the one elongated
member is coupled to the conduit, wherein the conduit is further
configurable to support at least the one elongated member.
4031. The system of claim 4027, wherein at least the one elongated
member is coupled to the conduit, wherein the conduit is further
configurable to support at least the one elongated member, and
wherein the conduit comprises openings.
4032. The system of claim 4027, further comprising a centralizer
coupled to at least the one elongated member and the conduit,
wherein the centralizer is configurable to electrically isolate at
least the one elongated member from the conduit.
4033. The system of claim 4027, further comprising a centralizer
coupled to at least the one elongated member and the conduit,
wherein the centralizer is configurable to maintain a location of
at least the one elongated member on the conduit.
4034. The system of claim 4027, wherein the opening comprises a
diameter of at least approximately 5 cm.
4035. The system of claim 4027, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a low resistance conductor configurable
to generate substantially no heat.
4036. The system of claim 4027, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises a rubber insulated conductor.
4037. The system of claim 4027, further comprising a lead-in
conductor coupled to at least the one elongated member, wherein the
lead-in conductor comprises copper wire.
4038. The system of claim 4027, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor.
4039. The system of claim 4027, further comprising a lead-in
conductor coupled to at least the one elongated member with a cold
pin transition conductor, wherein the cold pin transition conductor
comprises a substantially low resistance insulated conductor.
4040. The system of claim 4027, wherein at least the one elongated
member is arranged in a series electrical configuration.
4041. The system of claim 4027, wherein at least the one elongated
member is arranged in a parallel electrical configuration.
4042. The system of claim 4027, wherein at least the one elongated
member is configurable to generate radiant heat of approximately
650 W/m to approximately 1650 W/m during use.
4043. The system of claim 4027, further comprising a perforated
tube disposed in the opening external to at least the one elongated
member, wherein the perforated tube is configurable to remove vapor
from the opening to control a pressure in the opening during
use.
4044. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
4045. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing comprises steel.
4046. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein the
overburden casing is further disposed in cement.
4047. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, and wherein a packing
material is disposed at a junction of the overburden casing and the
opening.
4048. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material comprises cement.
4049. The system of claim 4027, further comprising an overburden
casing coupled to the opening, wherein the overburden casing is
disposed in an overburden of the formation, wherein a packing
material is disposed at a junction of the overburden casing and the
opening, and wherein the packing material is further configurable
to substantially inhibit a flow of fluid between the opening and
the overburden casing during use.
4050. The system of claim 4027, wherein the heated section of the
formation is substantially pyrolyzed.
4051. An in situ method for heating a coal formation, comprising:
applying an electrical current to at least one elongated member to
provide heat to at least a portion of the formation, wherein at
least the one elongated member is disposed within an opening in the
formation; providing an oxidizing fluid to at least the one
elongated member to substantially inhibit carbon deposition on or
proximate to at least the one elongated member; and allowing heat
to transfer from at least the one elongated member to a section of
the formation.
4052. The method of claim 4051, wherein at least the one elongated
member comprises a metal strip.
4053. The method of claim 4051, wherein at least the one elongated
member comprises a metal rod.
4054. The method of claim 4051, wherein at least the one elongated
member comprises stainless steel.
4055. The method of claim 4051, further comprising supporting at
least the one elongated member on a center support member.
4056. The method of claim 4051, further comprising supporting at
least the one elongated member on a center support member, wherein
the center support member comprises a tube.
4057. The method of claim 4051, further comprising electrically
isolating at least the one elongated member with a centralizer.
4058. The method of claim 4051, further comprising laterally
spacing at least the one elongated member with a centralizer.
4059. The method of claim 4051, further comprising electrically
coupling at least the one elongated member in a series
configuration.
4060. The method of claim 4051, further comprising electrically
coupling at least the one elongated member in a parallel
configuration.
4061. The method of claim 4051, wherein the provided heat comprises
approximately 650 W/m to approximately 1650 W/m.
4062. The method of claim 4051, further comprising determining a
temperature distribution in at least the one elongated member using
an electromagnetic signal provided to at least the one elongated
member.
4063. The method of claim 4051, further comprising monitoring the
applied electrical current.
4064. The method of claim 4051, further comprising monitoring a
voltage applied to at least the one elongated member.
4065. The method of claim 4051, further comprising monitoring a
temperature in at least the one elongated member with at least one
thermocouple.
4066. The method of claim 4051, further comprising supporting at
least the one elongated member on a center support member, wherein
the center support member comprises openings, wherein providing the
oxidizing fluid to at least the one elongated member comprises
flowing the oxidizing fluid through the openings in the center
support member.
4067. The method of claim 4051, wherein providing the oxidizing
fluid to at least the one elongated member comprises flowing the
oxidizing fluid through orifices in a tube disposed in the opening
proximate to at least the one elongated member.
4068. The method of claim 4051, further comprising electrically
coupling a lead-in conductor to at least the one elongated member,
wherein the lead-in conductor comprises a low resistance conductor
configured to generate substantially no heat.
4069. The method of claim 4051, further comprising electrically
coupling a lead-in conductor to at least the one elongated member
using a cold pin transition conductor.
4070. The method of claim 4051, further comprising electrically
coupling a lead-in conductor to at least the one elongated member
using a cold pin transition conductor, wherein the cold pin
transition conductor comprises a substantially low resistance
insulated conductor.
4071. The method of claim 4051, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in an overburden of the formation.
4072. The method of claim 4051, further comprising coupling an
overburden casing to the opening, wherein the overburden casing
comprises steel.
4073. The method of claim 4051, further comprising coupling an
overburden casing to the opening, wherein the overburden casing is
disposed in cement.
4074. The method of claim 4051, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the
opening.
4075. The method of claim 4051, further comprising coupling an
overburden casing to the opening, wherein a packing material is
disposed at a junction of the overburden casing and the opening,
and wherein the method further comprises inhibiting a flow of fluid
between the opening and the overburden casing with the packing
material.
4076. The method of claim 4051, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
4077. An in situ method for heating a coal formation, comprising:
oxidizing a fuel fluid in a heater; providing at least a portion of
the oxidized fuel fluid into a conduit disposed in an opening of
the formation; allowing heat to transfer from the oxidized fuel
fluid to a section of the formation; and allowing additional heat
to transfer from an electric heater disposed in the opening to the
section of the formation, wherein heat is allowed to transfer
substantially uniformly along a length of the opening.
4078. The method of claim 4077, wherein providing at least the
portion of the oxidized fuel fluid into the opening comprises
flowing the oxidized fuel fluid through a perforated conduit
disposed in the opening.
4079. The method of claim 4077, wherein providing at least the
portion of the oxidized fuel fluid into the opening comprises
flowing the oxidized fuel fluid through a perforated conduit
disposed in the opening, the method further comprising removing an
exhaust fluid through the opening.
4080. The method of claim 4077, further comprising initiating
oxidation of the fuel fluid in the heater with a flame.
4081. The method of claim 4077, further comprising removing the
oxidized fuel fluid through the conduit.
4082. The method of claim 4077, further comprising removing the
oxidized fuel fluid through the conduit and providing the removed
oxidized fuel fluid to at least one additional heater disposed in
the formation.
4083. The method of claim 4077, wherein the conduit comprises an
insulator disposed on a surface of the conduit, the method further
comprising tapering a thickness of the insulator such that heat is
allowed to transfer substantially uniformly along a length of the
conduit.
4084. The method of claim 4077, wherein the electric heater is an
insulated conductor.
4085. The method of claim 4077, wherein the electric heater is a
conductor disposed in the conduit.
4086. The method of claim 4077, wherein the electric heater is an
elongated conductive member.
4087. A system configured to heat a coal formation, comprising: one
or more heat sources disposed within one or more open wellbores in
the formation, wherein the one or more heat sources are configured
to provide heat to at least a portion of the formation during use;
and wherein the system is configured to allow heat to transfer from
the one or more heat sources to a selected section of the formation
during use.
4088. The system of claim 4087, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4089. The system of claim 4087, wherein the one or more heat
sources comprise electrical heaters.
4090. The system of claim 4087, wherein the one or more heat
sources comprise surface burners.
4091. The system of claim 4087, wherein the one or more heat
sources comprise Blameless distributed combustors.
4092. The system of claim 4087, wherein the one or more heat
sources comprise natural distributed combustors.
4093. The system of claim 4087, wherein the one or more open
wellbores comprise a diameter of at least approximately 5 cm.
4094. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation.
4095. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation, and wherein the overburden casing comprises steel.
4096. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation, and wherein the overburden casing is further disposed in
cement.
4097. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation, and wherein a packing material is disposed at a junction
of the overburden casing and the at least one of the one or more
open wellbores.
4098. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation, wherein a packing material is disposed at a junction of
the overburden casing and the at least one of the one or more open
wellbores, and wherein the packing material is configured to
substantially inhibit a flow of fluid between at least one of the
one or more open wellbores and the overburden casing during
use.
4099. The system of claim 4087, further comprising an overburden
casing coupled to at least one of the one or more open wellbores,
wherein the overburden casing is disposed in an overburden of the
formation, wherein a packing material is disposed at a junction of
the overburden casing and the at least one of the one or more open
wellbores, and wherein the packing material comprises cement.
4100. The system of claim 4087, wherein the system is further
configured to transfer heat such that the transferred heat can
pyrolyze at least some hydrocarbons in the selected section.
4101. The system of claim 4087, further comprising a valve coupled
to at least one of the one or more heat sources configured to
control pressure within at least a majority of the selected section
of the formation.
4102. The system of claim 4087, further comprising a valve coupled
to a production well configured to control a pressure within at
least a majority of the selected section of the formation.
4103. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least one
portion of the formation, wherein the one or more heat sources are
disposed within one or more open wellbores in the formation;
allowing the heat to transfer from the one or more heat sources to
a selected section of the formation; and producing a mixture from
the formation.
4104. The method of claim 4103, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4105. The method of claim 4103, wherein controlling formation
conditions comprises maintaining a temperature within the selected
section within a pyrolysis temperature range with a lower pyrolysis
temperature of about 250.degree. C. and an upper pyrolysis
temperature of about 400.degree. C.
4106. The method of claim 4103, wherein the one or more heat
sources comprise electrical heaters.
4107. The method of claim 4103, wherein the one or more heat
sources comprise surface burners.
4108. The method of claim 4103, wherein the one or more heat
sources comprise flameless distributed combustors.
4109. The method of claim 4103, wherein the one or more heat
sources comprise natural distributed combustors.
4110. The method of claim 4103, wherein the one or more heat
sources are suspended within the one or more open wellbores.
4111. The method of claim 4103, wherein a tube is disposed in at
least one of the one or more open wellbores proximate to heat
source, the method further comprising flowing a substantially
constant amount a fluid into at least one of the one or more open
wellbores through critical flow orifices in the tube.
4112. The method of claim 4103, wherein a perforated tube is
disposed in at least one of the one or more open wellbores
proximate to the heat source, the method further comprising flowing
a corrosion inhibiting fluid into at least one of the open
wellbores through the perforated tube.
4113. The method of claim 4103, further comprising coupling an
overburden casing to at least one of the one or more open
wellbores, wherein the overburden casing is disposed in an
overburden of the formation.
4114. The method of claim 4103, further comprising coupling an
overburden casing to at least one of the one or more open
wellbores, wherein the overburden casing is disposed in an
overburden of the formation, and wherein the overburden casing
comprise steel.
4115. The method of claim 4103, further comprising coupling an
overburden casing to at least one of the one or more open
wellbores, wherein the overburden casing is disposed in an
overburden of the formation, and wherein the overburden casing is
further disposed in cement.
4116. The method of claim 4103, further comprising coupling an
overburden casing to at least one of the one or more open
wellbores, wherein the overburden casing is disposed in an
overburden of the formation, and wherein a packing material is
disposed at a junction of the overburden casing and the at least
one of the one or more open wellbores.
4117. The method of claim 4103, further comprising coupling an
overburden casing to at least one of the one or more open
wellbores, wherein the overburden casing is disposed in an
overburden of the formation, and wherein the method further
comprises inhibiting a flow of fluid between the at least one of
the one or more open wellbores and the overburden casing with a
packing material.
4118. The method of claim 4103, further comprising heating at least
the portion of the formation to substantially pyrolyze at least
some of the carbon within the formation.
4119. The method of claim 4103, further comprising controlling a
pressure and a temperature within at least a majority of the
selected section of the formation, wherein the pressure is
controlled as a function of temperature, or the temperature is
controlled as a function of pressure.
4120. The method of claim 4103, further comprising controlling a
pressure with the wellbore.
4121. The method of claim 4103, further comprising controlling a
pressure within at least a majority of the selected section of the
formation with a valve coupled to at least one of the one or more
heat sources.
4122. The method of claim 4103, further comprising controlling a
pressure within at least a majority of the selected section of the
formation with a valve coupled to a production well located in the
formation.
4123. The method of claim 4103, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.degree. C. per day during pyrolysis.
4124. The method of claim 4103, wherein providing heat from the one
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
the one or more heat sources, wherein the formation has an average
heat capacity(C.sub.v), and wherein the heating pyrolyzes at least
some hydrocarbons within the selected volume of the formation; and
wherein heating energy/day provided to the volume is equal to or
less than Pwr, wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
4125. The method of claim 4103, wherein allowing the heat to
transfer from the one or more heat sources to the selected section
comprises transferring heat substantially by conduction.
4126. The method of claim 4103, wherein providing heat from the one
or more heat sources comprises heating the selected section such
that a thermal conductivity of at least a portion of the selected
section is greater than about 0.5 W/(m.degree. C.).
4127. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons having an API gravity of at
least about 25.degree..
4128. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4129. The method of claim 4103, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
4130. The method of claim 4103, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the non-condensable hydrocarbons
are olefins.
4131. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
4132. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
4133. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
4134. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
4135. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
4136. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4137. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.3% by weight of the condensable hydrocarbons are asphaltenes.
4138. The method of claim 4103, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4139. The method of claim 4103, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, and wherein the hydrogen is greater
than about 10% by volume of the non-condensable component and
wherein the hydrogen is less than about 80% by volume of the
non-condensable component.
4140. The method of claim 4103, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
4141. The method of claim 4103, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
4142. The method of claim 4103, further comprising controlling a
pressure within at least a majority of the selected section of the
formation.
4143. The method of claim 4103, further comprising controlling a
pressure within at least a majority of the selected section of the
formation, wherein the controlled pressure is at least about 2.0
bar absolute.
4144. The method of claim 4103, further comprising controlling
formation conditions such that the produced mixture comprises a
partial pressure of H.sub.2 within the mixture greater than about
0.5 bar.
4145. The method of claim 4144, wherein the partial pressure of
H.sub.2 is measured when the mixture is at a production well.
4146. The method of claim 4103, wherein controlling formation
conditions comprises recirculating a portion of hydrogen from the
mixture into the formation.
4147. The method of claim 4103, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
4148. The method of claim 4103, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
4149. The method of claim 4103, wherein the produced mixture
comprises hydrogen and condensable hydrocarbons, the method further
comprising hydrogenating a portion of the produced condensable
hydrocarbons with at least a portion of the produced hydrogen.
4150. The method of claim 4103, wherein allowing the heat to
transfer comprises increasing a permeability of a majority of the
selected section to greater than about 100 millidarcy.
4151. The method of claim 4103, wherein allowing the heat to
transfer comprises substantially uniformly increasing a
permeability of a majority of the selected section.
4152. The method of claim 4103, further comprising controlling the
heat to yield greater than about 60% by weight of condensable
hydrocarbons, as measured by Fischer Assay.
4153. The method of claim 4103, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for the
production well.
4154. The method of claim 4103, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4155. The method of claim 4103, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4156. The method of claim 4103, further comprising separating the
produced mixture into a gas stream and a liquid stream.
4157. The method of claim 4103, further comprising separating the
produced mixture into a gas stream and a liquid stream and
separating the liquid stream into an aqueous stream and a
non-aqueous stream.
4158. The method of claim 4103, wherein the produced mixture
comprises H.sub.2S, the method further comprising separating a
portion of the H.sub.2S from non-condensable hydrocarbons.
4159. The method of claim 4103, wherein the produced mixture
comprises CO.sub.2, the method further comprising separating a
portion of the CO.sub.2 from non-condensable hydrocarbons.
4160. The method of claim 4103, wherein the mixture is produced
from a production well, wherein the heating is controlled such that
the mixture can be produced from the formation as a vapor.
4161. The method of claim 4103, wherein the mixture is produced
from a production well, the method further comprising heating a
wellbore of the production well to inhibit condensation of the
mixture within the wellbore.
4162. The method of claim 4103, wherein the mixture is produced
from a production well, wherein a wellbore of the production well
comprises a heater element configured to heat the formation
adjacent to the wellbore, and further comprising heating the
formation with the heater element to produce the mixture, wherein
the mixture comprises a large non-condensable hydrocarbon gas
component and H.sub.2.
4163. The method of claim 4103, wherein the selected section is
heated to a minimum pyrolysis temperature of about 270.degree.
C.
4164. The method of claim 4103, further comprising maintaining the
pressure within the formation above about 2.0 bar absolute to
inhibit production of fluids having carbon numbers above 25.
4165. The method of claim 4103, further comprising controlling
pressure within the formation in a range from about atmospheric
pressure to about 100 bar, as measured at a wellhead of a
production well, to control an amount of condensable hydrocarbons
within the produced mixture, wherein the pressure is reduced to
increase production of condensable hydrocarbons, and wherein the
pressure is increased to increase production of non-condensable
hydrocarbons.
4166. The method of claim 4103, further comprising controlling
pressure within the formation in a range from about atmospheric
pressure to about 100 bar, as measured at a wellhead of a
production well, to control an API gravity of condensable
hydrocarbons within the produced mixture, wherein the pressure is
reduced to decrease the API gravity, and wherein the pressure is
increased to reduce the API gravity.
4167. A mixture produced from a portion of a coal formation, the
mixture comprising: an olefin content of less than about 10% by
weight; and an average carbon number less than about 35.
4168. The mixture of claim 4167, further comprising an average
carbon number less than about 30.
4169. The mixture of claim 4167, further comprising an average
carbon number less than about 25.
4170. The mixture of claim 4167, further comprising:
non-condensable hydrocarbons comprising hydrocarbons having carbon
numbers of less than 5; and wherein a-weight ratio of the
hydrocarbons having carbon numbers from 2 through 4, to methane, in
the mixture is greater than approximately 1.
4171. The mixture of claim 4167, further comprising condensable
hydrocarbons, wherein less than about 1% by weight, when calculated
on an atomic basis, of the condensable hydrocarbons is nitrogen,
wherein less than about 1% by weight, when calculated on an atomic
basis, of the condensable hydrocarbons is oxygen, and wherein less
than about 1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4172. The mixture of claim 4167, further comprising ammonia,
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4173. The mixture of claim 4167, further comprising condensable
hydrocarbons, wherein an olefin content of the condensable
hydrocarbons is greater than about 0.1% by weight of the
condensable hydrocarbons, and wherein the olefin content of the
condensable hydrocarbons is less than about 15% by weight of the
condensable hydrocarbons.
4174. The mixture of claim 4167, further comprising condensable
hydrocarbons, wherein less than about 15% by weight of the
condensable hydrocarbons have a carbon number greater than about
25.
4175. The mixture of claim 4174, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen, wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen, and wherein less than about 1% by weight, when
calculated on an atomic basis, of the condensable hydrocarbons is
sulfur.
4176. The mixture of claim 4173, further comprising condensable
hydrocarbons, wherein greater than about 20% by weight of the
condensable hydrocarbons are aromatic compounds.
4177. The mixture of claim 4167, further comprising:
non-condensable hydrocarbons comprising hydrocarbons having carbon
numbers of less than about 5, wherein a weight ratio of the
hydrocarbons having carbon number from 2 through 4, to methane, in
the mixture is greater than approximately 1; wherein the
non-condensable hydrocarbons further comprise H.sub.2, wherein
greater than about 15% by weight of the non-condensable
hydrocarbons comprises H.sub.2; and condensable hydrocarbons,
comprising: oxygenated hydrocarbons, wherein greater than about
1.5% by weight of the condensable hydrocarbons comprises oxygenated
hydrocarbons; and aromatic compounds, wherein greater than about
20% by weight of the condensable hydrocarbons comprises aromatic
compounds.
4178. The mixture of claim 4167, further comprising: condensable
hydrocarbons, wherein less than about 5% by weight of the
condensable hydrocarbons comprises hydrocarbons having a carbon
number greater than about 25; wherein the condensable hydrocarbons
further comprise: oxygenated hydrocarbons, wherein greater than
about 5% by weight of the condensable hydrocarbons comprises
oxygenated hydrocarbons; and aromatic compounds, wherein greater
than about 30% by weight of the condensable hydrocarbons comprises
aromatic compounds; and non-condensable hydrocarbons comprising
H.sub.2, wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4179. The mixture of claim 4167, further comprising a condensable
mixture, comprising: olefins, wherein about 0.1% by weight to about
15% by weight of the condensable mixture comprises olefins; and
asphaltenes, wherein less than about 0.1% by weight of the
condensable mixture comprises asphaltenes.
4180. The mixture of claim 4179, further comprising, oxygenated
hydrocarbons, wherein less than about 15% by weight of the
condensable mixture comprises oxygenated hydrocarbons;
4181. The mixture of claim 4167, further comprising a condensable
mixture, comprising: olefins, wherein about 0.1% by weight to about
2% by weight of the condensable mixture comprises olefins; and
multi-ring aromatics, wherein less than about 2% by weight of the
condensable mixture comprises multi-ring aromatics with more than
two rings.
4182. The mixture of claim 4180, further comprising oxygenated
hydrocarbons, wherein greater than about 25% by weight of the
condensable mixture comprises oxygenated hydrocarbons.
4183. The mixture of claim 4167, further comprising:
non-condensable hydrocarbons, wherein the non-condensable
hydrocarbons comprise H.sub.2, wherein greater than about 10% by
weight of the non-condensable hydrocarbons comprises H.sub.2;
ammonia, wherein greater than about 0.5% by weight of the mixture
comprises ammonia; and hydrocarbons, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater than about 0.4.
4184. A mixture produced from a portion of a coal formation, the
mixture, comprising: non-condensable hydrocarbons comprising
hydrocarbons having carbon numbers of less than 5; and wherein a
weight ratio of the hydrocarbons having carbon numbers from 2
through 4, to methane, in the mixture is greater than approximately
1.
4185. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein about 0.1% by weight to about 15% by weight
of the condensable hydrocarbons are olefins.
4186. The mixture of claim 4184, wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons ranges from about 0.001
to about 0.15.
4187. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 1% by weight, when calculated
on an atomic basis, of the condensable hydrocarbons is
nitrogen.
4188. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 1% by weight, when calculated
on an atomic basis, of the condensable hydrocarbons is oxygen.
4189. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein about 5% by weight to about 30% by weight of
the condensable hydrocarbons comprise oxygen containing compounds,
and wherein the oxygen containing compounds comprise phenols.
4190. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 1% by weight, when calculated
on an atomic basis, of the condensable hydrocarbons is sulfur.
4191. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein greater than about 20% by weight of the
condensable hydrocarbons are aromatic compounds.
4192. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 5% by weight of the
condensable hydrocarbons comprises multi-ring aromatics with more
than two rings.
4193. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 0.3% by weight of the
condensable hydrocarbons are asphaltenes.
4194. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein about 5% by weight to about 30% by weight of
the condensable hydrocarbons comprise cycloalkanes.
4195. The mixture of claim 4184, wherein the non-condensable
hydrocarbons further comprises hydrogen, wherein the hydrogen is
greater than about 10% by volume of the non-condensable
hydrocarbons, and wherein the hydrogen is less than about 80% by
volume of the non-condensable hydrocarbons.
4196. The mixture of claim 4184, further comprising ammonia,
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4197. The mixture of claim 4184, further comprising ammonia,
wherein the ammonia is used to produce fertilizer.
4198. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein less than about 15 weight % of the
condensable hydrocarbons have a carbon number greater than
approximately 25.
4199. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein the condensable hydrocarbons comprise
olefins, and wherein about 0.1% to about 5% by weight of the
condensable hydrocarbons comprises olefins.
4200. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein the condensable hydrocarbons comprises
olefins, and wherein about 0.1% to about 2.5% by weight of the
condensable hydrocarbons comprises olefins.
4201. The mixture of claim 4184, further comprising condensable
hydrocarbons, wherein the condensable hydrocarbons comprise
oxygenated hydrocarbons, and wherein greater than about 5% by
weight of the condensable hydrocarbons comprises oxygenated
hydrocarbons.
4202. The mixture of claim 4184, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 5% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4203. The mixture of claim 4184, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4204. The mixture of claim 4184, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater than about 0.3.
4205. A mixture produced from a portion of a coal formation, the
mixture comprising: non-condensable hydrocarbons comprising
hydrocarbons having carbon numbers of less than 5, wherein a weight
ratio of hydrocarbons having carbon numbers from 2 through 4, to
methane, is greater than approximately 1; and condensable
hydrocarbons comprising oxygenated hydrocarbons, wherein greater
than about 5% by weight of the condensable component comprises
oxygenated hydrocarbons.
4206. The mixture of claim 4205, wherein about 0.1% by weight to
about 15% by weight of the condensable hydrocarbons are
olefins.
4207. The mixture of claim 4205, wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons ranges from about 0.001
to about 0.15.
4208. The mixture of claim 4205, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
4209. The mixture of claim 4205, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
4210. The mixture of claim 4205, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
4211. The mixture of claim 4205, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
4212. The mixture of claim 4205, wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
4213. The mixture of claim 4205, wherein less than about 5% by
weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4214. The mixture of claim 4205, wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
4215. The mixture of claim 4205, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4216. The mixture of claim 4205, wherein the non-condensable
hydrocarbons comprises hydrogen, wherein the hydrogen is greater
than about 10% by volume of the non-condensable hydrocarbons, and
wherein the hydrogen is less than about 80% by volume of the
non-condensable hydrocarbons.
4217. The mixture of claim 4205, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
4218. The mixture of claim 4205, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
4219. The mixture of claim 4205, wherein less than about 5 weight %
of the condensable hydrocarbons in the mixture have a carbon number
greater than approximately 25.
4220. The mixture of claim 4205, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% to
about 5% by weight of the condensable hydrocarbons comprises
olefins.
4221. The mixture of claim 4205, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% to
about 2.5% by weight of the condensable hydrocarbons comprises
olefins.
4222. The mixture of claim 4205, wherein the non-condensable
hydrocarbons further comprise H.sub.2, wherein greater than about
5% by weight of the mixture comprises H.sub.2.
4223. The mixture of claim 4205, wherein the non-condensable
hydrocarbons further comprise H.sub.2, wherein greater than about
15% by weight of the mixture comprises H.sub.2.
4224. The mixture of claim 4205, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater than about 0.3.
4225. A mixture produced from a portion of a coal formation, the
mixture comprising: non-condensable hydrocarbons comprising
hydrocarbons having carbon numbers of less than 5, wherein a weight
ratio of hydrocarbons having carbon numbers from 2 through 4, to
methane, is greater than approximately 1; condensable hydrocarbons;
wherein less than about 1% by weight, when calculated on an atomic
basis, of the condensable hydrocarbons comprises nitrogen; wherein
less than about 1% by weight, when calculated on an atomic basis,
of the condensable hydrocarbons comprises oxygen; and wherein less
than about 1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons comprises sulfur.
4226. The mixture of claim 4225, further comprising ammonia,
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4227. The mixture of claim 4225, wherein less than about 5 weight %
of the condensable hydrocarbons have a carbon number greater than
approximately 25.
4228. The mixture of claim 4225, wherein the condensable
hydrocarbons comprise olefins, and wherein about 0.1% by weight to
about 15% by weight of the condensable hydrocarbons are
olefins.
4229. The mixture of claim 4225, wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons ranges from about 0.001
to about 0.15.
4230. The mixture of claim 4225, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
4231. The mixture of claim 4225, wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
4232. The mixture of claim 4225, wherein less than about 5% by
weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4233. The mixture of claim 4225, wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
4234. The mixture of claim 4225, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4235. The mixture of claim 4225, wherein the non-condensable
hydrocarbons comprises hydrogen, and wherein the hydrogen is
greater than about 10% by volume of the non-condensable
hydrocarbons and wherein the hydrogen is less than about 80% by
volume of the non-condensable hydrocarbons.
4236. The mixture of claim 4225, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4237. The mixture of claim 4225, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4238. The mixture of claim 4225, wherein the condensable
hydrocarbons comprises oxygenated hydrocarbons, and wherein greater
than about 5% by weight of the condensable component comprises
oxygenated hydrocarbons.
4239. The mixture of claim 4225, wherein the non-condensable
hydrocarbons comprise H.sub.2, and wherein greater than about 5% by
weight of the non-condensable hydrocarbons comprises H.sub.2.
4240. The mixture of claim 4225, wherein the non-condensable
hydrocarbons comprise H.sub.2, and wherein greater than about 15%
by weight of the mixture comprises H.sub.2.
4241. The mixture of claim 4225, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater, than about 0.3.
4242. A mixture produced from a portion of a coal formation, the
mixture comprising: non-condensable hydrocarbons comprising
hydrocarbons having carbon numbers of less than 5, wherein a weight
ratio of hydrocarbons having carbon numbers from 2 through 4, to
methane, is greater than approximately 1; ammonia, wherein greater
than about 0.5% by weight of the mixture comprises ammonia; and
condensable hydrocarbons comprising oxygenated hydrocarbons,
wherein greater than about 5% by weight of the condensable
hydrocarbons comprises oxygenated hydrocarbons.
4243. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4244. The mixture of claim 4242, wherein the non-condensable
hydrocarbons further comprise ethene and ethane, and wherein a
molar ratio of ethene to ethane in the non-condensable hydrocarbons
ranges from about 0.001 to about 0.15.
4245. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4246. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4247. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4248. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4249. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise aromatic compounds, and wherein
greater than about 20% by weight of the condensable hydrocarbons
are aromatic compounds.
4250. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise multi-aromatic rings, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4251. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4252. The mixture of claim 4242, wherein the condensable
hydrocarbons further comprise cycloalkanes, and wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4253. The mixture of claim 4242, wherein the non-condensable
hydrocarbons further comprise hydrogen, wherein the hydrogen is
greater than about 10% by volume of the non-condensable
hydrocarbons, and wherein the hydrogen is less than about 80% by
volume of the non-condensable hydrocarbons.
4254. The mixture of claim 4242, wherein the produced mixture
further comprises ammonia, and wherein greater than about 0.05% by
weight of the produced mixture is ammonia.
4255. The mixture of claim 4242, wherein the produced mixture
further comprises ammonia, and wherein the ammonia is used to
produce fertilizer.
4256. The mixture of claim 4242, wherein the condensable
hydrocarbons comprise hydrocarbons having a carbon number of
greater than approximately 25, and wherein less than about 15
weight % of the hydrocarbons in the mixture have a carbon number
greater than approximately 25.
4257. The mixture of claim 4242, wherein the non-condensable
hydrocarbons further comprise H.sub.2, and wherein greater than
about 5% by weight of the mixture comprises H.sub.2.
4258. The mixture of claim 4242, wherein the non-condensable
hydrocarbons further comprise H.sub.2, and wherein greater than
about 15% by weight of the mixture comprises H.sub.2.
4259. The mixture of claim 4242, wherein the non-condensable
hydrocarbons further comprise hydrocarbons having carbon numbers of
greater than 2, wherein a weight ratio of hydrocarbons having
carbon numbers greater than 2, to methane, is greater than about
0.3.
4260. A mixture produced from a portion of a coal formation, the
mixture comprising: non-condensable hydrocarbons comprising
hydrocarbons having carbon numbers of less than 5, wherein a weight
ratio of hydrocarbons having carbon numbers from 2 through 4, to
methane, is greater than approximately 1; and condensable
hydrocarbons comprising olefins, wherein less than about 10% by
weight of the condensable hydrocarbons comprises olefins.
4261. The mixture of claim 4260, wherein the non-condensable
hydrocarbons further comprise ethene and ethane, and wherein a
molar ratio of ethene to ethane in the non-condensable hydrocarbons
ranges from about 0.001 to about 0.15.
4262. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4263. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4264. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4265. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4266. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise aromatic compounds, and wherein
greater than about 20% by weight of the condensable hydrocarbons
are aromatic compounds.
4267. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4268. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4269. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise cycloalkanes, and wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4270. The mixture of claim 4260, wherein the non-condensable
hydrocarbons further comprise hydrogen, and wherein the hydrogen is
greater than about 10% by volume of the non-condensable
hydrocarbons and wherein the hydrogen is less than about 80% by
volume of the non-condensable hydrocarbons.
4271. The mixture of claim 4260, wherein the produced mixture
further comprises ammonia, and wherein greater than about 0.05% by
weight of the produced mixture is ammonia.
4272. The mixture of claim 4260, wherein the produced mixture
further comprises ammonia, and wherein the ammonia is used to
produce fertilizer.
4273. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise hydrocarbons having a carbon number
of greater than approximately 25, and wherein less than about 15%
by weight of the hydrocarbons have a carbon number greater than
approximately 25.
4274. The mixture of claim 4260, wherein about 0.1% to about 5% by
weight of the condensable component comprises olefins.
4275. The mixture of claim 4260, wherein about 0.1% to about 2% by
weight of the condensable component comprises olefins.
4276. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise oxygenated hydrocarbons, and wherein
greater than about 5% by weight of the condensable hydrocarbons
comprises oxygenated hydrocarbons.
4277. The mixture of claim 4260, wherein the condensable
hydrocarbons further comprise oxygenated hydrocarbons, and wherein
greater than about 25% by weight of the condensable component
comprises oxygenated hydrocarbons.
4278. The mixture of claim 4260, wherein the non-condensable
hydrocarbons further comprise H.sub.2, and wherein greater than
about 5% by weight of the non-condensable hydrocarbons comprises
H.sub.2.
4279. The mixture of claim 4260, wherein the non-condensable
hydrocarbons further comprise H.sub.2, and wherein greater than
about 15% by weight of the non-condensable hydrocarbons comprises
H.sub.2.
4280. The mixture of claim 4260, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater than about 0.3.
4281. A mixture produced from a portion of a coal formation,
comprising: condensable hydrocarbons, wherein less than about 15
weight % of the condensable hydrocarbons have a carbon number
greater than 25; and wherein the condensable hydrocarbons comprise
oxygenated hydrocarbons, and wherein greater than about 5% by
weight of the condensable hydrocarbons comprises oxygenated
hydrocarbons.
4282. The mixture of claim 4281, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 1.
4283. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4284. The mixture of claim 4281, further comprising non-condensable
hydrocarbons, wherein a molar ratio of ethene to ethane in the
non-condensable hydrocarbons ranges from about 0.001 to about
0.15.
4285. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4286. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4287. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4288. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4289. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise aromatic compounds, and wherein
greater than about 20% by weight of the condensable hydrocarbons
are aromatic compounds.
4290. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4291. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4292. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprise cycloalkanes, and wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4293. The mixture of claim 4281, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrogen, and wherein the hydrogen is greater than about 10% by
volume of the non-condensable hydrocarbons and wherein the hydrogen
is less than about 80% by volume of the non-condensable
hydrocarbons.
4294. The mixture of claim 4281, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4295. The mixture of claim 4281, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4296. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprises olefins, and wherein less than about
10% by weight of the condensable hydrocarbons comprises
olefins.
4297. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprises olefins, and wherein about 0.1% to
about 5% by weight of the condensable hydrocarbons comprises
olefins.
4298. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprises olefins, and wherein about 0.1% to
about 2% by weight of the condensable hydrocarbons comprises
olefins.
4299. The mixture of claim 4281, wherein the condensable
hydrocarbons further comprises oxygenated hydrocarbons, and wherein
greater than about 5% by weight of the condensable hydrocarbons
comprises the oxygenated hydrocarbon.
4300. The mixture of claim 4281, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, wherein greater than about 5% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4301. The mixture of claim 4281, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, wherein greater than about 15 % by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4302. The mixture of claim 4281, wherein a weight ratio of
hydrocarbons having greater than about 2 carbon atoms, to methane,
is greater than about 0.3.
4303. A mixture produced from a portion of a coal formation,
comprising: condensable hydrocarbons, wherein less than about 15%
by weight of the condensable hydrocarbons have a carbon number
greater than about 25; wherein less than about 1% by weight of the
condensable hydrocarbons, when calculated on an atomic basis, is
nitrogen; wherein less than about 1% by weight of the condensable
hydrocarbons, when calculated on an atomic basis, is oxygen; and
wherein less than about 1% by weight of the condensable
hydrocarbons, when calculated on an atomic basis, is sulfur.
4304. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, wherein the non-condensable component comprises
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 1.
4305. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4306. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, and wherein a molar ratio of ethene to ethane in the
non-condensable hydrocarbons ranges from about 0.001 to about
0.15.
4307. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4308. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise aromatic compounds, and wherein
greater than about 20% by weight of the condensable hydrocarbons
are aromatic comp sounds.
4309. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4310. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4311. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise cycloalkanes, and wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4312. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, and wherein the non-condensable hydrocarbons comprise
hydrogen, and wherein greater than about 10% by volume and less
than about 80% by volume of the non-condensable component comprises
hydrogen.
4313. The mixture of claim 4303, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4314. The mixture of claim 4303, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4315. The mixture of claim 4303, wherein the condensable component
further comprises olefins, and wherein about 0.1% to about 5% by
weight of the condensable component comprises olefins.
4316. The mixture of claim 4303, wherein the condensable component
further comprises olefins, and wherein about 0.1% to about 2.5% by
weight of the condensable component comprises olefins.
4317. The mixture of claim 4303, wherein the condensable
hydrocarbons further comprise oxygenated hydrocarbons, and wherein
greater than about 5% by weight of the condensable hydrocarbons
comprises oxygenated hydrocarbons.
4318. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 5% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4319. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4320. The mixture of claim 4303, further comprising non-condensable
hydrocarbons, wherein a weight ratio of compounds within the
non-condensable hydrocarbons having greater than about 2 carbon
atoms, to methane, is greater than about 0.3.
4321. A mixture produced from a portion of a coal formation,
comprising: condensable hydrocarbons, wherein less than about 15%
by weight of the condensable hydrocarbons have a carbon number
greater than 20; and wherein the condensable hydrocarbons comprise
olefins, wherein an olefin content of the condensable component is
less than about 10% by weight of the condensable component.
4322. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 1.
4323. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4324. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, and wherein a molar ratio of ethene to ethane in the
non-condensable hydrocarbons ranges from about 0.001 to about
0.15.
4325. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4326. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4327. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4328. The mixture of claim 4321, wherein the condensable
hydrocarbons, wherein about 5% by weight to about 30% by weight of
the condensable hydrocarbons comprise oxygen containing compounds,
and wherein the oxygen containing compounds comprise phenols.
4329. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise aromatic compounds, and wherein
greater than about 20% by weight of the condensable hydrocarbons
are aromatic compounds.
4330. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4331. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4332. The mixture of claim 4321, wherein the condensable
hydrocarbons further comprise cycloalkanes, and wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4333. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprises
hydrogen, and wherein the hydrogen is about 10% by volume to about
80% by volume of the non-condensable hydrocarbons.
4334. The mixture of claim 4321, further comprising ammonia,
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4335. The mixture of claim 4321, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4336. The mixture of claim 4321, wherein about 0.1% to about 5% by
weight of the condensable component comprises olefins.
4337. The mixture of claim 4321, wherein about 0.1% to about 2% by
weight of the condensable component comprises olefins.
4338. The mixture of claim 4321, wherein the condensable component
further comprises oxygenated hydrocarbons, and wherein greater than
about 1.5% by weight of the condensable component comprises
oxygenated hydrocarbons.
4339. The mixture of claim 4321, wherein the condensable component
further comprises oxygenated hydrocarbons, and wherein greater than
about 25% by weight of the condensable component comprises
oxygenated hydrocarbons.
4340. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 5% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4341. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4342. The mixture of claim 4321, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 0.3.
4343. A mixture produced from a portion of a coal formation,
comprising: condensable hydrocarbons, wherein less than about 5% by
weight of the condensable hydrocarbons comprises hydrocarbons
having a carbon number greater than about 25; and wherein the
condensable hydrocarbons further comprise aromatic compounds,
wherein more than about 20% by weight of the condensable
hydrocarbons comprises aromatic compounds.
4344. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 1.
4345. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4346. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein a molar ratio of ethene to ethane in the
non-condensable hydrocarbons ranges from about 0.001 to about
0.15.
4347. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4348. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4349. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4350. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4351. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4352. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4353. The mixture of claim 4343, wherein the condensable
hydrocarbons comprise cycloalkanes, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4354. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
hydrogen, and wherein the hydrogen is greater than about 10% by
volume and less than about 80% by volume of the non-condensable
hydrocarbons.
4355. The mixture of claim 4343, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4356. The mixture of claim 4343, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4357. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprise olefins, and wherein about 0.1% to
about 5% by weight of the condensable hydrocarbons comprises
olefins.
4358. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprises olefins, and wherein about 0.1% to
about 2% by weight of the condensable hydrocarbons comprises
olefins.
4359. The mixture of claim 4343, wherein the condensable
hydrocarbons further comprises multi-ring aromatic compounds, and
wherein less than about 2% by weight of the condensable
hydrocarbons comprises multi-ring aromatic compounds.
4360. The mixture of claim 4343, wherein the condensable
hydrocarbons comprises oxygenated hydrocarbons, and wherein greater
than about 1.5% by weight of the condensable hydrocarbons comprises
oxygenated hydrocarbons.
4361. The mixture of claim 4343, wherein the condensable
hydrocarbons comprises oxygenated hydrocarbons, and wherein greater
than about 25% by weight of the condensable component comprises
oxygenated hydrocarbons.
4362. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 5% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4363. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprise
H.sub.2, and wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4364. The mixture of claim 4343, further comprising non-condensable
hydrocarbons, wherein the non-condensable hydrocarbons comprises
hydrocarbons having carbon numbers of less than 5, and wherein a
weight ratio of hydrocarbons having carbon numbers from 2 through
4, to methane, is greater than approximately 0.3.
4365. A mixture produced from a portion of a coal formation,
comprising: non-condensable hydrocarbons comprising hydrocarbons
having carbon numbers of less than about 5, wherein a weight ratio
of the hydrocarbons having carbon number from 2 through 4, to
methane, in the mixture is greater than approximately 1; wherein
the non-condensable hydrocarbons further comprise H.sub.2, wherein
greater than about 15% by weight of the non-condensable
hydrocarbons comprises H.sub.2; and condensable hydrocarbons,
comprising: oxygenated hydrocarbons, wherein greater than about
1.5% by weight of the condensable hydrocarbons comprises oxygenated
hydrocarbons; olefins, wherein less than about 10% by weight of the
condensable hydrocarbons comprises olefins; and aromatic compounds,
wherein greater than about 20% by weight of the condensable
hydrocarbons comprises aromatic compounds.
4366. The mixture of claim 4365, wherein the non-condensable
hydrocarbons further comprise ethene and ethane, and wherein a
molar ratio of ethene to ethane in the non-condensable hydrocarbons
ranges from about 0.001 to about 0.15.
4367. The mixture of claim 4365, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4368. The mixture of claim 4365, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4369. The mixture of claim 4365, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4370. The mixture of claim 4365, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4371. The mixture of claim 4365, wherein the condensable
hydrocarbons comprise multi-ring aromatics, and wherein less than
about 5% by weight of the condensable hydrocarbons comprises
multi-ring aromatics with more than two rings.
4372. The mixture of claim 4365, wherein the condensable
hydrocarbons comprise asphaltenes, and wherein less than about 0.3%
by weight of the condensable hydrocarbons are asphaltenes.
4373. The mixture of claim 4365, wherein the condensable
hydrocarbons comprise cycloalkanes, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4374. The mixture of claim 4365, wherein the non-condensable
hydrocarbons further comprises hydrogen, and wherein greater than
about 10% by volume and less than about 80% by volume of the
non-condensable hydrocarbons.
4375. The mixture of claim 4365, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4376. The mixture of claim 4365, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4377. The mixture of claim 4365, wherein the condensable
hydrocarbons further comprise hydrocarbons having a carbon number
of greater than approximately 25, wherein less than about 15% by
weight of the hydrocarbons have a carbon number greater than
approximately 25.
4378. The mixture of claim 4365, wherein about 0.1% to about 5% by
weight of the condensable hydrocarbons comprises olefins.
4379. The mixture of claim 4365, wherein about 0.1% to about 2% by
weight of the condensable hydrocarbons comprises olefins.
4380. The mixture of claim 4365, wherein greater than about 25% by
weight of the condensable hydrocarbons comprises oxygenated
hydrocarbons.
4381. The mixture of claim 4365, wherein the mixture comprises
hydrocarbons having greater than about 2 carbon atoms, and wherein
the weight ratio of hydrocarbons having greater than about 2 carbon
atoms to methane is greater than about 0.3.
4382. A mixture produced from a portion of a coal formation,
comprising: condensable hydrocarbons, wherein less than about 5% by
weight of the condensable hydrocarbons comprises hydrocarbons
having a carbon number greater than about 25; wherein the
condensable hydrocarbons further comprise: oxygenated hydrocarbons,
wherein greater than about 5% by weight of the condensable
hydrocarbons comprises oxygenated hydrocarbons; olefins, wherein
less than about 10% by weight of the condensable hydrocarbons
comprises olefins; and aromatic compounds, wherein greater than
about 30% by weight of the condensable hydrocarbons comprises
aromatic compounds; and non-condensable hydrocarbons comprising
H.sub.2, wherein greater than about 15% by weight of the
non-condensable hydrocarbons comprises H.sub.2.
4383. The mixture of claim 4382, wherein the non-condensable
hydrocarbons further comprises hydrocarbons having carbon numbers
of less than 5, and wherein a weight ratio of hydrocarbons having
carbon numbers from 2 through 4, to methane, is greater than
approximately 1.
4384. The mixture of claim 4382, wherein the non-condensable
hydrocarbons comprise ethene and ethane, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
4385. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise nitrogen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is nitrogen.
4386. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise oxygen, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is oxygen.
4387. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise sulfur, and wherein less than about
1% by weight, when calculated on an atomic basis, of the
condensable hydrocarbons is sulfur.
4388. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise oxygen containing compounds, wherein
about 5% by weight to about 30% by weight of the condensable
hydrocarbons comprise oxygen containing compounds, and wherein the
oxygen containing compounds comprise phenols.
4389. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise multi-ring aromatics, and wherein
less than about 5% by weight of the condensable hydrocarbons
comprises multi-ring aromatics with more than two rings.
4390. The mixture of claim 4382, wherein the condensable
hydrocarbons further comprise asphaltenes, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4391. The mixture of claim 4382, wherein the condensable
hydrocarbons comprise cycloalkanes, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4392. The mixture of claim 4382, wherein greater than about 10% by
volume and less than about 80% by volume of the non-condensable
hydrocarbons is hydrogen.
4393. The mixture of claim 4382, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4394. The mixture of claim 4382, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4395. The mixture of claim 4382, wherein about 0.1% to about 5% by
weight of the condensable hydrocarbons comprises olefins.
4396. The mixture of claim 4382, wherein about 0.1% to about 2% by
weight of the condensable hydrocarbons comprises olefins.
4397. The mixture of claim 4382, wherein the condensable
hydrocarbons comprises oxygenated hydrocarbons, and wherein greater
than about 15% by weight of the condensable hydrocarbons comprises
oxygenated hydrocarbons.
4398. The mixture of claim 4382, wherein the mixture comprises
hydrocarbons having greater than about 2 carbon atoms, and wherein
the weight ratio of hydrocarbons having greater than about 2 carbon
atoms to methane is greater than about 0.3.
4399. A condensable mixture produced from a portion of a coal
formation, comprising: olefins, wherein about 0.1% by weight to
about 15% by weight of the condensable mixture comprises olefins;
oxygenated hydrocarbons, wherein less than about 15% by weight of
the condensable mixture comprises oxygenated hydrocarbons; and
asphaltenes, wherein less than about 0.1% by weight of the
condensable mixture comprises asphaltenes.
4400. The mixture of claim 4399, wherein the condensable mixture
further comprises hydrocarbons having a carbon number of greater
than approximately 25, and wherein less than about 15 weight % of
the hydrocarbons in the mixture have a carbon number greater than
approximately 25.
4401. The mixture of claim 4399, wherein about 0.1% by weight to
about 5% by weight of the condensable mixture comprises
olefins.
4402. The mixture of claim 4399, wherein the condensable mixture
further comprises non-condensable hydrocarbons, wherein the
non-condensable hydrocarbons comprise ethene and ethane, and
wherein a molar ratio of ethene to ethane in the non-condensable
hydrocarbons ranges from about 0.001 to about 0.15.
4403. The mixture of claim 4399, wherein the condensable mixture
further comprises nitrogen, and wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
mixture is nitrogen.
4404. The mixture of claim 4399, wherein the condensable mixture
further comprises oxygen, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable mixture is
oxygen.
4405. The mixture of claim 4399, wherein the condensable mixture
further comprises sulfur, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable mixture is
sulfur.
4406. The mixture of claim 4399, wherein the condensable mixture
further comprises oxygen containing compounds, wherein about 5% by
weight to about 30% by weight of the condensable mixture comprise
oxygen containing compounds, and wherein the oxygen containing
compounds comprise phenols.
4407. The mixture of claim 4399, wherein the condensable mixture
further comprises aromatic compounds, and wherein greater than
about 20% by weight of the condensable mixture are aromatic
compounds.
4408. The mixture of claim 4399, wherein the condensable mixture
further comprises multi-ring aromatics, and wherein less than about
5% by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4409. The mixture of claim 4399, wherein the condensable mixture
further comprises cycloalkanes, and wherein about 5% by weight to
about 30% by weight of the condensable mixture are
cycloalkanes.
4410. The mixture of claim 4399, wherein the condensable mixture
comprises non-condensable hydrocarbons, and wherein the
non-condensable hydrocarbons comprise hydrogen, and wherein the
hydrogen is greater than about 10% by volume of the non-condensable
hydrocarbons and wherein the hydrogen is less than about 80% by
volume of the non-condensable hydrocarbons.
4411. The mixture of claim 4399, further comprising ammonia, and
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4412. The mixture of claim 4399, further comprising ammonia, and
wherein the ammonia is used to produce fertilizer.
4413. The mixture of claim 4399, wherein about 0.1% by weight to
about 2% by weight of the condensable mixture comprises
olefins.
4414. A condensable mixture produced from a portion of a coal
formation, comprising: olefins, wherein about 0.1% by weight to
about 2% by weight of the condensable mixture comprises olefins;
multi-ring aromatics, wherein less than about 2% by weight of the
condensable mixture comprises multi-ring aromatics with more than
two rings; and oxygenated hydrocarbons, wherein greater than about
25% by weight of the condensable mixture comprises oxygenated
hydrocarbons.
4415. The mixture of claim 4414, further comprising hydrocarbons
having a carbon number of greater than approximately 25, wherein
less than about 5 weight % of the hydrocarbons in the mixture have
a carbon number greater than approximately 25.
4416. The mixture of claim 4414, wherein the condensable mixture
further comprises nitrogen, and wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
4417. The mixture of claim 4414, wherein the condensable mixture
further comprises oxygen, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is oxygen.
4418. The mixture of claim 4414, wherein the condensable mixture
further comprises sulfur, and wherein less than about 1% by weight,
when calculated on an atomic basis, of the condensable hydrocarbons
is sulfur.
4419. The mixture of claim 4414, wherein the condensable mixture
further comprises oxygen containing compounds, wherein about 5% by
weight to about 30% by weight of the condensable hydrocarbons
comprise oxygen containing compounds, and wherein the oxygen
containing compounds comprise phenols.
4420. The mixture of claim 4414, wherein the condensable mixture
further comprises aromatic compounds, and wherein greater than
about 20% by weight of the condensable mixture are aromatic
compounds.
4421. The mixture of claim 4414, wherein the condensable mixture
further comprises condensable hydrocarbons, and wherein less than
about 0.3% by weight of the condensable hydrocarbons are
asphaltenes.
4422. The mixture of claim 4414, wherein the condensable mixture
further comprises cycloalkanes, and wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4423. The mixture of claim 4414, further comprising ammonia,
wherein greater than about 0.05% by weight of the produced mixture
is ammonia.
4424. The mixture of claim 4414, further comprising ammonia,
wherein the ammonia is used to produce fertilizer.
4425. A mixture produced from a portion of a coal formation,
comprising: non-condensable hydrocarbons and H.sub.2, wherein
greater than about 10% by volume of the non-condensable
hydrocarbons and H.sub.2 comprises H.sub.2; ammonia and water,
wherein greater than about 0.5% by weight of the mixture comprises
ammonia; and condensable hydrocarbons.
4426. The mixture of claim 4425, wherein the non-condensable
hydrocarbons further comprise hydrocarbons having carbon numbers of
less than 5, and wherein a weight ratio of the hydrocarbons having
carbon numbers from 2 through 4, to methane, in the mixture is
greater than approximately 1.
4427. The mixture of claim 4425, wherein greater than about 0.1% by
weight of the condensable hydrocarbons, and wherein less than about
15% by weight of the condensable hydrocarbons are olefins.
4428. The mixture of claim 4425, wherein the non-condensable
hydrocarbons further comprise ethene and ethane, wherein a molar
ratio of ethene to ethane in the non-condensable hydrocarbons is
greater than about 0.001, and wherein a molar ratio of ethene to
ethane in the non-condensable hydrocarbons is less than about
0.15.
4429. The mixture of claim 4425, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is nitrogen.
4430. The mixture of claim 4425, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
4431. The mixture of claim 4425, wherein less than about 1% by
weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
4432. The mixture of claim 4425, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
4433. The mixture of claim 4425, wherein greater than about 20% by
weight of the condensable hydrocarbons are aromatic compounds.
4434. The mixture of claim 4425, wherein less than about 5% by
weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4435. The mixture of claim 4425, wherein less than about 0.3% by
weight of the condensable hydrocarbons are asphaltenes.
4436. The mixture of claim 4425, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4437. The mixture of claim 4425, wherein the H.sub.2 is less than
about 80% by volume of the non-condensable hydrocarbons and
H.sub.2.
4438. The mixture of claim 4425, wherein the condensable
hydrocarbons further comprise sulfur containing compounds.
4439. The mixture of claim 4425, wherein the ammonia is used to
produce fertilizer.
4440. The mixture of claim 4425, wherein less than about 5% of the
condensable hydrocarbons have carbon numbers greater than 25.
4441. The mixture of claim 4425, wherein the condensable
hydrocarbons comprise olefins, and wherein about 0.001% by weight
of the condensable hydrocarbons comprise olefins, and wherein less
than about 15% by weight of the condensable hydrocarbons comprise
olefins.
4442. The mixture of claim 4425, wherein the condensable
hydrocarbons comprise olefins, and wherein about 0.001% by weight
of the condensable hydrocarbons comprise olefins, and wherein less
than about 10% by weight of the condensable hydrocarbons comprise
olefins.
4443. The mixture of claim 4425, wherein the condensable
hydrocarbons comprise oxygenated hydrocarbons, and wherein greater
than about 1.5% by weight of the condensable hydrocarbons comprises
oxygenated hydrocarbons.
4444. The mixture of claim 4425, wherein the condensable
hydrocarbons further comprise nitrogen containing compounds.
4445. A method of treating a coal formation in situ comprising
providing heat from three or more heat sources to at least a
portion of the formation, wherein three or more of the heat sources
are located in the formation in a unit of heat sources, and wherein
the unit of heat sources comprises a triangular pattern.
4446. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
and wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units.
4447. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units, and wherein a
ratio of heat sources in the repetitive pattern of units to
production wells in the repetitive pattern is less than
approximately 5.
4448. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units, wherein three or
more production wells are located within an area defined by the
plurality of units, wherein the three or more production wells are
located in the formation in a unit of production wells, and wherein
the unit of production wells comprises a triangular pattern.
4449. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units, wherein three or
more injection wells are located within an area defined by the
plurality of units, wherein the three or more injection wells are
located in the formation in a unit of injection wells, and wherein
the unit of injection wells comprises a triangular pattern.
4450. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units, wherein three or
more production wells and three or more injection wells are located
within an area defined by the plurality of units, wherein the three
or more production wells are located in the formation in a unit of
production wells, wherein the unit of production wells comprises a
first triangular pattern, wherein the three or more injection wells
are located in the formation in a unit of injection wells, wherein
the unit of injection wells comprises a second triangular pattern,
and wherein the first triangular pattern is substantially different
than the second triangular pattern.
4451. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a plurality of the units,
wherein the plurality of units are repeated over an area of the
formation to form a repetitive pattern of units, wherein three or
more monitoring wells are located within an area defined by the
plurality of units, wherein the three or more monitoring wells are
located in the formation in a unit of monitoring wells, and wherein
the unit of monitoring wells comprises a triangular pattern.
4452. The method of claim 4445, wherein a production well is
located in an area defined by the unit of heat sources.
4453. The method of claim 4445, wherein three or more of the heat
sources are located in the formation in a first unit and a second
unit, wherein the first unit is adjacent to the second unit, and
wherein the first unit is inverted with respect to the second
unit.
4454. The method of claim 4445, wherein a distance between each of
the heat sources in the unit of heat sources varies by less than
about 20%.
4455. The method of claim 4445, wherein a distance between each of
the heat sources in the unit of heat sources is approximately
equal.
4456. The method of claim 4445, wherein providing heat from three
or more heat sources comprises substantially uniformly providing
heat to at least the portion of the formation.
4457. The method of claim 4445, wherein the heated portion
comprises a substantially uniform temperature distribution.
4458. The method of claim 4445, wherein the heated portion
comprises a substantially uniform temperature distribution, and
wherein a difference between a highest temperature in the heated
portion and a lowest temperature in the heated portion comprises
less than about 200.degree. C.
4459. The method of claim 4445, wherein a temperature at an outer
lateral boundary of the triangular pattern and a temperature at a
center of the triangular pattern are approximately equal.
4460. The method of claim 4445, wherein a temperature at an outer
lateral boundary of the triangular pattern and a temperature at a
center of the triangular pattern increase substantially linearly
after an initial period of time, and wherein the initial period of
time comprises less than approximately 3 months.
4461. The method of claim 4445, wherein a time required to increase
an average temperature of the heated portion to a selected
temperature with the triangular pattern of heat sources is
substantially less than a time required to increase the average
temperature of the heated portion to the selected temperature with
a hexagonal pattern of heat sources, and wherein a space between
each of the heat sources in the triangular pattern is approximately
equal to a space between each of the heat sources in the hexagonal
pattern.
4462. The method of claim 4445, wherein a time required to increase
a temperature at a coldest point within the heated portion to a
selected temperature with the triangular pattern of heat sources is
substantially less than a time required to increase a temperature
at the coldest point within the heated portion to the selected
temperature with a hexagonal pattern of heat sources, and wherein a
space between each of the heat sources in the triangular pattern is
approximately equal to a space between each of the heat sources in
the hexagonal pattern.
4463. The method of claim 4445, wherein a time required to increase
a temperature at a coldest point within the heated portion to a
selected temperature with the triangular pattern of heat sources is
substantially less than a time required to increase a temperature
at the coldest point within the heated portion to the selected
temperature with a hexagonal pattern of heat sources, and wherein a
number of heat sources per unit area in the triangular pattern is
equal to the number of heat sources per unit are in the hexagonal
pattern of heat sources.
4464. The method of claim 4445, wherein a time required to increase
a temperature at a coldest point within the heated portion to a
selected temperature with the triangular pattern of heat sources is
substantially equal to a time required to increase a temperature at
the coldest point within the heated portion to the selected
temperature with a hexagonal pattern of heat sources, and wherein a
space between each of the heat sources in the triangular pattern is
approximately 5 m greater than a space between each of the heat
sources in the hexagonal pattern.
4465. The method of claim 4445, wherein providing heat from three
or more heat sources to at least the portion of formation
comprises: heating a selected volume (V) of the coal formation from
three or more of the heat sources, wherein the formation has an
average heat capacity (C.sub.v), and wherein heat from three or
more of the heat sources pyrolyzes at least some hydrocarbons
within the selected volume of the formation; and wherein heating
energy/day provided to the volume is equal to or less than Pwr,
wherein Pwr is calculated by the equation:
Pwr=h*V*C.sub.v*.rho..sub.B wherein Pwr is the heating energy/day,
h is an average heating rate of the formation, .rho..sub.B is
formation bulk density, and wherein the heating rate is less than
about 10.degree. C./day.
4466. The method of claim 4445, wherein three or more of the heat
sources comprise electrical heaters.
4467. The method of claim 4445, wherein three or more of the heat
sources comprise surface burners.
4468. The method of claim 4445, wherein three or more of the heat
sources comprise flameless distributed combustors.
4469. The method of claim 4445, wherein three or more of the heat
sources comprise natural distributed combustors.
4470. The method of claim 4445, further comprising: allowing the
heat to transfer from three or more of the heat sources to a
selected section of the formation such that heat from three or more
of the heat sources pyrolyzes at least some hydrocarbons within the
selected section of the formation; and producing a mixture of
fluids from the formation.
4471. The method of claim 4470, further comprising controlling a
temperature within at least a majority of the selected section of
the formation, wherein the pressure is controlled as a function of
temperature, or the temperature is controlled as a function of
pressure.
4472. The method of claim 4470, further comprising controlling the
heat such that an average heating rate of the selected section is
less than about 1.0.degree. C. per day during pyrolysis.
4473. The method of claim 4470, wherein allowing the heat to
transfer from three or more of the heat sources to the selected
section comprises transferring heat substantially by
conduction.
4474. The method of claim 4470, wherein providing heat from three
or more of the heat sources to at least the portion of the
formation comprises heating the selected section such that a
thermal conductivity of at least a portion of the selected section
is greater than about 0.5 W/m.degree. C.
4475. The method of claim 4470, wherein the produced mixture
comprises an API gravity of at least 25.degree..
4476. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 0.1% by
weight to about 15% by weight of the condensable hydrocarbons are
olefins.
4477. The method of claim 4470, wherein the produced mixture
comprises non-condensable hydrocarbons, and wherein a molar ratio
of ethene to ethane in the non-condensable hydrocarbons ranges from
about 0.001 to about 0.15.
4478. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic, basis, of the condensable
hydrocarbons is nitrogen.
4479. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is oxygen.
4480. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 1%
by weight, when calculated on an atomic basis, of the condensable
hydrocarbons is sulfur.
4481. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, wherein about 5% by weight to
about 30% by weight of the condensable hydrocarbons comprise oxygen
containing compounds, and wherein the oxygen containing compounds
comprise phenols.
4482. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein greater than about
20% by weight of the condensable hydrocarbons are aromatic
compounds.
4483. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about 5%
by weight of the condensable hydrocarbons comprises multi-ring
aromatics with more than two rings.
4484. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein less than about
0.1% by weight of the condensable hydrocarbons are asphaltenes.
4485. The method of claim 4470, wherein the produced mixture
comprises condensable hydrocarbons, and wherein about 5% by weight
to about 30% by weight of the condensable hydrocarbons are
cycloalkanes.
4486. The method of claim 4470, wherein the produced mixture
comprises a non-condensable component, wherein the non-condensable
component comprises hydrogen, wherein the hydrogen is greater than
about 10% by volume of the non-condensable component, and wherein
the hydrogen is less than about 80% by volume of the
non-condensable component.
4487. The method of claim 4470, wherein the produced mixture
comprises ammonia, and wherein greater than about 0.05% by weight
of the produced mixture is ammonia.
4488. The method of claim 4470, wherein the produced mixture
comprises ammonia, and wherein the ammonia is used to produce
fertilizer.
4489. The method of claim 4470, further comprising controlling
formation conditions to produce a mixture of hydrocarbon fluids and
H.sub.2, wherein a partial pressure of H.sub.2 within the mixture
is greater than about 2.0 bar absolute.
4490. The method of claim 4470, further comprising altering a
pressure within the formation to inhibit production of hydrocarbons
from the formation having carbon numbers greater than about 25.
4491. The method of claim 4470, further comprising controlling
formation conditions by recirculating a portion of hydrogen from
the mixture into the formation.
4492. The method of claim 4470, further comprising: providing
hydrogen (H.sub.2) to the heated section to hydrogenate
hydrocarbons within the section; and heating a portion of the
section with heat from hydrogenation.
4493. The method of claim 4470, further comprising: producing
hydrogen from the formation; and hydrogenating a portion of the
produced condensable hydrocarbons with at least a portion of the
produced hydrogen.
4494. The method of claim 4470, wherein allowing the heat to
transfer from three or more of the heat sources to the selected
section of the formation comprises increasing a permeability of a
majority of the selected section to greater than about 100
millidarcy.
4495. The method of claim 4470, wherein allowing the heat to
transfer from three or more of the heat sources to the selected
section of the formation comprises substantially uniformly
increasing a permeability of a majority of the selected
section.
4496. The method of claim 4470, further comprising controlling the
heat from three of more heat sources to yield greater than about
60% by weight of condensable hydrocarbons, as measured by Fischer
Assay.
4497. The method of claim 4470, wherein producing the mixture
comprises producing the mixture in a production well, and wherein
at least about 7 heat sources are disposed in the formation for
each production well.
4498. The method of claim 4470, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4499. The method of claim 4470, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4500. A method for in situ production of synthesis gas from a coal
formation, comprising: heating a section of the formation to a
temperature sufficient to allow synthesis gas generation, wherein a
permeability of the section is substantially uniform and greater
than a permeability of an unheated section of the formation when
the temperature sufficient to allow synthesis gas generation within
the formation is achieved; providing a synthesis gas generating
fluid to the section to generate synthesis gas; and removing
synthesis gas from the formation.
4501. The method of claim 4500, wherein the permeability of the
section is greater than about 100 millidarcy when the temperature
sufficient to allow synthesis gas generation within the formation
is achieved.
4502. The method of claim 4500, wherein the temperature sufficient
to allow synthesis gas generation ranges from approximately
400.degree. C. to approximately 1200.degree. C.
4503. The method of claim 4500, further comprising heating the
section when providing the synthesis gas generating fluid to
inhibit temperature decrease in the section due to synthesis gas
generation.
4504. The method of claim 4500, wherein heating the section
comprises convecting an oxidizing fluid into a portion of the
section, wherein the temperature within the section is above a
temperature sufficient to support oxidation of carbon within the
section with the oxidizing fluid, and reacting the oxidizing fluid
with carbon in the section to generate heat within the section.
4505. The method of claim 4504, wherein the oxidizing fluid
comprises air.
4506. The method of claim 4505, wherein an amount of the oxidizing
fluid convected into the section is configured to inhibit formation
of oxides of nitrogen by maintaining a reaction temperature below a
temperature sufficient to produce oxides of nitrogen compounds.
4507. The method of claim 4500, wherein heating the section
comprises diffusing an oxidizing fluid to reaction zones adjacent
to wellbores within the formation, oxidizing carbon within the
reaction zone to generate heat, and transferring the heat to the
section.
4508. The method of claim 4500, wherein heating the section
comprises heating the section by transfer of heat from one or more
of electrical heaters.
4509. The method of claim 4500, wherein heating the section to a
temperature sufficient to allow synthesis gas generation and
providing a synthesis gas generating fluid to the section comprises
introducing steam into the section to heat the formation and to
generate synthesis gas.
4510. The method of claim 4500, further comprising controlling the
heating of the section and provision of the synthesis gas
generating fluid to maintain a temperature within the section above
the temperature sufficient to generate synthesis gas.
4511. The method of claim 4500, further comprising: monitoring a
composition of the produced synthesis gas; and controlling heating
of the section and provision of the synthesis gas generating fluid
to maintain the composition of the produced synthesis gas within a
selected range.
4512. The method of claim 4511, wherein the selected range
comprises a ratio of H.sub.2 to CO of about 2:1.
4513. The method of claim 4500, wherein the synthesis gas
generating fluid comprises liquid water.
4514. The method of claim 4500, wherein the synthesis gas
generating fluid comprises steam.
4515. The method of claim 4500, wherein the synthesis gas
generating fluid comprises water and carbon dioxide, and wherein
the carbon dioxide inhibits production of carbon dioxide from
carbon containing material within the section.
4516. The method of claim 4515, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4517. The method of claim 4500, wherein the synthesis gas
generating fluid comprises carbon dioxide and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4518. The method of claim 4517, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4519. The method of claim 4500, wherein providing the synthesis gas
generating fluid to the section comprises raising a water table of
the formation to allow water to flow into the section.
4520. The method of claim 4500, wherein the synthesis gas is
removed from a producer well equipped with a heating source, and
wherein a portion of the heating source adjacent to a synthesis gas
producing zone operates at a substantially constant temperature to
promote production of the synthesis gas wherein the synthesis gas
has a selected composition.
4521. The method of claim 4520, wherein the substantially constant
temperature is about 700.degree. C., and wherein the selected
composition has a H.sub.2 to CO ratio of about 2:1.
4522. The method of claim 4500, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within the section to
increase a H.sub.2 concentration of the generated synthesis
gas.
4523. The method of claim 4500, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within the section to increase an energy content
of the synthesis gas removed from the formation.
4524. The method of claim 4500, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4525. The method of claim 4500, further comprising generating
electricity from the synthesis gas using a fuel cell.
4526. The method of claim 4500, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent section of
the formation.
4527. The method of claim 4500, further comprising using a portion
of the synthesis gas as a combustion fuel to heat the
formation.
4528. The method of claim 4500, further comprising converting at
least a portion of the produced synthesis gas to condensable
hydrocarbons using a Fischer-Tropsch synthesis process.
4529. The method of claim 4500, further comprising converting at
least a portion of the produced synthesis gas to methanol.
4530. The method of claim 4500, further comprising converting at
least a portion of the produced synthesis gas to gasoline.
4531. The method of claim 4500, further comprising converting at
least a portion of the synthesis gas to methane using a catalytic
methanation process.
4532. The method of claim 4500, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4533. The method of claim 4500, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4534. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to substantially uniformly increase a
permeability of the portion and to increase a temperature of the
portion to a temperature sufficient to allow synthesis gas
generation; providing a synthesis gas generating fluid to at least
the portion of the selected section, wherein the synthesis gas
generating fluid comprises carbon dioxide; obtaining a portion of
the carbon dioxide of the synthesis gas generating fluid from the
formation; and producing synthesis gas from the formation.
4535. The method of claim 4534, wherein the temperature sufficient
to allow synthesis gas generation is within a range from about
400.degree. C. to about 1200.degree. C.
4536. The method of claim 4534, further comprising using a second
portion of the separated carbon dioxide as a flooding agent to
produce hydrocarbon bed methane from a coal formation.
4537. The method of claim 4536, wherein the coal formation is a
deep coal formation over 760 m below ground surface.
4538. The method of claim 4536, wherein the coal formation adsorbs
some of the carbon dioxide to sequester the carbon dioxide.
4539. The method of claim 4534, further comprising using a second
portion of the separated carbon dioxide as a flooding agent for
enhanced oil recovery.
4540. The method of claim 4534, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons undergo a reaction within the selected section to
increase a H.sub.2 concentration within the produced synthesis
gas.
4541. The method of claim 4534, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within the selected section to increase an
energy content of the produced synthesis gas.
4542. The method of claim 4534, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4543. The method of claim 4534, further comprising generating
electricity from the synthesis gas using a fuel cell.
4544. The method of claim 4534, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent portion of
the formation.
4545. The method of claim 4534, further comprising using a portion
of the synthesis gas as a combustion fuel for heating the
formation.
4546. The method of claim 4534, further comprising converting at
least a portion of the produced synthesis gas to condensable
hydrocarbons using a Fischer-Tropsch synthesis process.
4547. The method of claim 4534, further comprising converting at
least a portion of the produced synthesis gas to methanol.
4548. The method of claim 4534, further comprising converting at
least a portion of the produced synthesis gas to gasoline.
4549. The method of claim 4534, further comprising converting at
least a portion of the synthesis gas to methane using a catalytic
methanation process.
4550. The method of claim 4534, wherein a temperature of the one or
more heat sources wellbore is maintained at a temperature of less
than approximately 700.degree. C. to produce a synthesis gas having
a ratio of H.sub.2 to carbon monoxide of greater than about 2.
4551. The method of claim 4534, wherein a temperature of the one or
more heat sources wellbore is maintained at a temperature of
greater than approximately 700.degree. C. to produce a synthesis
gas having a ratio of H.sub.2 to carbon monoxide of less than about
2.
4552. The method of claim 4534, wherein a temperature of the one or
more heat sources wellbore is maintained at a temperature of
approximately 700.degree. C. to produce a synthesis gas having a
ratio of H.sub.2 to carbon monoxide of approximately 2.
4553. The method of claim 4534, wherein a heat source of the one or
more of heat sources comprises an electrical heater.
4554. The method of claim 4534, wherein a heat source of the one or
more heat sources comprises a natural distributor heater.
4555. The method of claim 4534, wherein a heat source of the one or
more heat sources comprises a flameless distributor combustor (FDC)
heater, and wherein fluids are produced from the wellbore of the
FDC heater through a conduit positioned within the wellbore.
4556. The method of claim 4534, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4557. The method of claim 4534, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4558. A method of in situ synthesis gas production, comprising:
providing heat from one or more flameless distributed combustor
heaters to at least a first portion of a coal formation; allowing
the heat to transfer from the one or more heaters to a selected
section of the formation such that the heat from the one or more
heaters substantially uniformly increases a permeability of the
selected section, and to raise a temperature of the selected
section to a temperature sufficient to generate synthesis gas;
introducing a synthesis gas producing fluid into the selected
section to generate synthesis gas; and removing synthesis gas from
the formation.
4559. The method of claim 4558, wherein the one or more heaters
comprise at least two heaters, and wherein superposition of heat
from at least the two heaters substantially uniformly increases a
permeability of the selected section, and raises a temperature of
the selected section to a temperature sufficient to generate
synthesis gas.
4560. The method of claim 4558, further comprising producing the
synthesis gas from the formation under pressure, and generating
electricity from the produced synthesis gas by passing the produced
synthesis gas through a turbine.
4561. The method of claim 4558, further comprising producing
pyrolyzation products from the formation when raising the
temperature of the selected section to the temperature sufficient
to generate synthesis gas.
4562. The method of claim 4558, further comprising separating a
portion of carbon dioxide from the removed synthesis gas, and
storing the carbon dioxide within a spent portion of the
formation.
4563. The method of claim 4558, further comprising storing carbon
dioxide within a spent portion of the formation, wherein an amount
of carbon dioxide stored within the spent portion of the formation
is equal to or greater than an amount of carbon dioxide within the
removed synthesis gas.
4564. The method of claim 4558, further comprising separating a
portion of H.sub.2 from the removed synthesis gas; and using a
portion of the separated H.sub.2 as fuel for the one or more
heaters.
4565. The method of claim 4564, further comprising using a portion
of exhaust products from one or more heaters as a portion of the
synthesis gas producing fluid
4566. The method of claim 4558, further comprising using a portion
of the removed synthesis gas with a fuel cell to generate
electricity.
4567. The method of claim 4566, wherein the fuel cell produces
steam, and wherein a portion of the steam is used as a portion of
the synthesis gas producing fluid.
4568. The method of claim 4566, wherein the fuel cell produces
carbon dioxide, and wherein a portion of the carbon dioxide is
introduced into the formation to react with carbon within the
formation to produce carbon monoxide.
4569. The method of claim 4566, wherein the fuel cell produces
carbon dioxide, and storing an amount of carbon dioxide within a
spent portion of the formation equal or greater to an amount of the
carbon dioxide produced by the fuel cell.
4570. The method of claim 4558, further comprising using a portion
of the removed synthesis gas as a feed product for formation of
hydrocarbons.
4571. The method of claim 4558, wherein the synthesis gas producing
fluid comprises hydrocarbons having carbon numbers less than 5, and
wherein the hydrocarbons crack within the formation to increase an
amount of H.sub.2 within the generated synthesis gas.
4572. The method of claim 4558, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4573. The method of claim 4558, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4574. A method of treating a coal formation, comprising: heating a
portion of the formation with one or more electrical heaters to a
temperature sufficient to pyrolyze hydrocarbons within the portion;
producing pyrolyzation fluid from the formation; separating a fuel
cell feed stream from the pyrolyzation fluid; and directing the
fuel cell feed stream to a fuel cell to produce electricity;
4575. The method of claim 4574, wherein the fuel cell is a molten
carbonate fuel cell.
4576. The method of claim 4574, wherein the fuel cell is a solid
oxide fuel cell.
4577. The method of claim 4574, further comprising using a portion
of the produced electricity to power the electrical heaters.
4578. The method of claim 4574, wherein heating the portion of the
formation is performed at a rate sufficient to increase a
permeability of the portion and to produce a substantially uniform
permeability within the portion.
4579. The method of claim 4574, wherein the fuel cell feed stream
comprises H.sub.2 and hydrocarbons having a carbon number of less
than 5.
4580. The method of claim 4574, wherein the fuel cell feed stream
comprises H.sub.2 and hydrocarbons having a carbon number of less
than 3.
4581. The method of claim 4574, further comprising hydrogenating
the pyrolyzation fluid with a portion of H.sub.2 from the
pyrolyzation fluid.
4582. The method of claim 4574, wherein the hydrogenation is done
in situ by directing the H.sub.2 into the formation.
4583. The method of claim 4574, wherein the hydrogenation is done
in a surface unit.
4584. The method of claim 4574, further comprising directing
hydrocarbon fluid having carbon numbers less than 5 adjacent to at
least one of the electrical heaters, cracking a portion of the
hydrocarbons to produce H.sub.2, and producing a portion of the
hydrogen from the formation.
4585. The method of claim 4584, further comprising directing an
oxidizing fluid adjacent to at least the one of the electrical
heaters, oxidizing coke deposited on or near the at least one of
the electrical heaters with the oxidizing fluid.
4586. The method of claim 4574, further comprising storing CO.sub.2
from the fuel cell within the formation.
4587. The method of claim 4586, wherein the CO.sub.2 is adsorbed to
carbon material within a spent portion of the formation.
4588. The method of claim 4574, further comprising cooling the
portion to form a spent portion of formation.
4589. The method of claim 4588, wherein cooling the portion
comprises introducing water into the portion to produce steam, and
removing steam from the formation.
4590. The method of claim 4589, further comprising using a portion
of the removed steam to heat a second portion of the formation.
4591. The method of claim 4589, further comprising using a portion
of the removed steam as a synthesis gas producing fluid in a second
portion of the formation.
4592. The method of claim 4574, further comprising: heating the
portion to a temperature sufficient to support generation of
synthesis gas after production of the pyrolyzation fluids;
introducing a synthesis gas producing fluid into the portion to
generate synthesis gas; and removing a portion of the synthesis gas
from the formation.
4593. The method of claim 4592, further comprising producing the
synthesis gas from the formation under pressure, and generating
electricity from the produced synthesis gas by passing the produced
synthesis gas through a turbine.
4594. The method of claim 4592, further comprising using a first
portion of the removed synthesis gas as fuel cell feed.
4595. The method of claim 4592, further comprising producing steam
from operation of the fuel cell, and using the steam as part of the
synthesis gas producing fluid.
4596. The method of claim 4592, further comprising using carbon
dioxide from the fuel cell as a part of the synthesis gas producing
fluid.
4597. The method of claim 4592, further comprising using a portion
of the synthesis gas to produce hydrocarbon product.
4598. The method of claim 4592, further comprising cooling the
portion to form a spent portion of formation.
4599. The method of claim 4598, wherein cooling the portion
comprises introducing water into the portion to produce steam, and
removing steam from the formation.
4600. The method of claim 4599, further comprising using a portion
of the removed steam to heat a second portion of the formation.
4601. The method of claim 4599, further comprising using a portion
of the removed steam as a synthesis gas producing fluid in a second
portion of the formation.
4602. The method of claim 4574, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4603. The method of claim 4574, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4604. A method for in situ production of synthesis gas from a coal
formation, comprising: providing heat from one or more heat sources
to at least a portion of the formation; allowing the heat to
transfer from the one or more heat sources to a selected section of
the formation such that the heat from the one or more heat sources
pyrolyzes at least some of the hydrocarbons within the selected
section of the formation; producing pyrolysis products from the
formation; heating at least a portion of the selected section to a
temperature sufficient to generate synthesis gas; providing a
synthesis gas generating fluid to at least the portion of the
selected section to generate synthesis gas; and producing a portion
of the synthesis gas from the formation.
4605. The method of claim 4604, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4606. The method of claim 4604, further comprising allowing the
heat to transfer from the one or more heat sources to the selected
section to substantially uniformly increase a permeability of the
selected section.
4607. The method of claim 4604, further comprising controlling heat
transfer from the one or more heat sources to produce a
permeability within the selected section of greater than about 100
millidarcy.
4608. The method of claim 4604, further comprising heating at least
the portion of the selected section when providing the synthesis
gas generating fluid to inhibit temperature decrease within the
selected section during synthesis gas generation.
4609. The method of claim 4604, wherein the temperature sufficient
to allow synthesis gas generation is within a range from
approximately 400.degree. C. to approximately 1200.degree. C.
4610. The method of claim 4604, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4611. The method of claim 4604, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: introducing an oxidizing
fluid into the formation through a wellbore; transporting the
oxidizing fluid substantially be convection into the portion of the
selected section, wherein the portion of the selected section is at
a temperature sufficient to support an oxidization reaction with
the oxidizing fluid; and reacting the oxidizing fluid within the
portion of the selected section to generate heat and raise the
temperature of the portion.
4612. The method of claim 4604, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4613. The method of claim 4604, wherein one or more heat sources
comprise one or more heater wells, wherein at least one heater well
comprises a conduit disposed within the formation, and further
comprising heating the conduit by flowing a hot fluid through the
conduit.
4614. The method of claim 4604, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation and providing a synthesis gas
generating fluid to at least the portion of the selected section
comprises introducing steam into the portion.
4615. The method of claim 4604, further comprising controlling the
heating of at least the portion of selected section and provision
of the synthesis gas generating fluid to maintain a temperature
within at least the portion of the selected section above the
temperature sufficient to generate synthesis gas.
4616. The method of claim 4604, further comprising: monitoring a
composition of the produced synthesis gas; and controlling heating
of at least the portion of selected section and provision of the
synthesis gas generating fluid to maintain the composition of the
produced synthesis gas within a desired range.
4617. The method of claim 4604, wherein the synthesis gas
generating fluid comprises liquid water.
4618. The method of claim 4604, wherein the synthesis gas
generating fluid comprises steam.
4619. The method of claim 4604, wherein the synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
4620. The method of claim 4619, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4621. The method of claim 4604, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4622. The method of claim 4621, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4623. The method of claim 4604, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
4624. The method of claim 4604, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within at least the
portion of the selected section to increase a H.sub.2 concentration
within the produced synthesis gas.
4625. The method of claim 4604, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within at least the portion of the selected
section to increase an energy content of the produced synthesis
gas.
4626. The method of claim 4604, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4627. The method of claim 4604, further comprising generating
electricity from the synthesis gas using a fuel cell.
4628. The method of claim 4604, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent section of
the formation.
4629. The method of claim 4604, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4630. The method of claim 4604, further comprising converting at
least a portion of the produced synthesis gas to condensable
hydrocarbons using a Fischer-Tropsch synthesis process.
4631. The method of claim 4604, further comprising converting at
least a portion of the produced synthesis gas to methanol.
4632. The method of claim 4604, further comprising converting at
least a portion of the produced synthesis gas to gasoline.
4633. The method of claim 4604, further comprising converting at
least a portion of the synthesis gas to methane using a catalytic
methanation process.
4634. The method of claim 4604, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4635. The method of claim 4604, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4636. A method for in situ production of synthesis gas from a coal
formation, comprising: heating a first portion of the formation to
pyrolyze some hydrocarbons within the first portion; allowing the
heat to transfer from one or more heat sources to a selected
section of the formation, pyrolyzing hydrocarbons within the
selected section; producing fluid from the first portion, wherein
the fluid comprises an aqueous fluid and a hydrocarbon fluid;
heating a second portion of the formation to a temperature
sufficient to allow synthesis gas generation; introducing at least
a portion of the aqueous fluid to the second section after the
section reaches the temperature sufficient to allow synthesis gas
generation; and producing synthesis gas from the formation.
4637. The method of claim 4636, wherein the temperature sufficient
to allow synthesis gas generation ranges from approximately
400.degree. C. to approximately 1200.degree. C.
4638. The method of claim 4636, further comprising separating
ammonia within the aqueous phase from the aqueous phase prior to
introduction of at least the portion of the aqueous fluid to the
second section.
4639. The method of claim 4636, wherein a permeability of the
second portion of the formation is substantially uniform and
greater than about 100 millidarcy when the temperature sufficient
to allow synthesis gas generation is achieved.
4640. The method of claim 4636, further comprising heating the
second portion of the formation during introduction of at least the
portion of the aqueous fluid to the second section to inhibit
temperature decrease in the second section due to synthesis gas
generation.
4641. The method of claim 4636, wherein heating the second portion
of the formation comprises convecting an oxidizing fluid into a
portion of the second portion that is above a temperature
sufficient to support oxidation of carbon within the portion with
the oxidizing fluid, and reacting the oxidizing fluid with carbon
in the portion to generate heat within the portion.
4642. The method of claim 4636, wherein heating the second portion
of the formation comprises diffusing an oxidizing fluid to reaction
zones adjacent to wellbores within the formation, oxidizing carbon
within the reaction zones to generate heat, and transferring the
heat to the second portion.
4643. The method of claim 4636, wherein heating the second portion
of the formation comprises heating the second section by transfer
of heat from one or more electrical heaters.
4644. The method of claim 4636, wherein heating the second portion
of the formation comprises heating the second section with a
flameless distributor combustor.
4645. The method of claim 4636, wherein heating the second portion
of the formation comprises injecting steam into at least the
portion of the formation.
4646. The method of claim 4636, wherein at least a portion of the
aqueous fluid comprises a liquid phase.
4647. The method of claim 4636, wherein the aqueous fluid comprises
a vapor phase.
4648. The method of claim 4636, further comprising adding carbon
dioxide to at least the portion of aqueous fluid to inhibit
production of carbon dioxide from carbon within the formation.
4649. The method of claim 4648, wherein a portion of the carbon
dioxide comprises carbon dioxide removed from the formation.
4650. The method of claim 4636, further comprising adding
hydrocarbons with carbon numbers less than 5 to at least the
portion of the aqueous fluid to increase a H.sub.2 concentration
within the produced synthesis gas.
4651. The method of claim 4636, further comprising adding
hydrocarbons with carbon numbers less than 5 to at least the
portion of the aqueous fluid to increase a H.sub.2 concentration
within the produced synthesis gas, wherein the hydrocarbons are
obtained from the produced fluid.
4652. The method of claim 4636, further comprising adding
hydrocarbons greater than 4 to at least the portion of the aqueous
fluid to increase energy content of the produced synthesis gas.
4653. The method of claim 4636, further comprising adding
hydrocarbons greater than 4 to at least the portion of the aqueous
fluid to increase energy content of the produced synthesis gas,
wherein the hydrocarbons are obtained from the produced fluid.
4654. The method of claim 4636, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4655. The method of claim 4636, further comprising generating
electricity from the synthesis gas using a fuel cell.
4656. The method of claim 4636, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent portion of
the formation.
4657. The method of claim 4636, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4658. The method of claim 4636, further comprising converting at
least a portion of the produced synthesis gas to condensable
hydrocarbons using a Fischer-Tropsch synthesis process.
4659. The method of claim 4636, further comprising converting at
least a portion of the produced synthesis gas to methanol.
4660. The method of claim 4636, further comprising converting at
least a portion of the produced synthesis gas to gasoline.
4661. The method of claim 4636, further comprising converting at
least a portion of the synthesis gas to methane using a catalytic
methanation process.
4662. The method of claim 4636, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4663. The method of claim 4636, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4664. A method for in situ production of synthesis gas from a coal
formation, comprising: heating a portion of the formation with one
or more heat sources to create increased and substantially uniform
permeability within a portion of the formation and to raise a
temperature within the portion to a temperature sufficient to allow
synthesis gas generation; providing a synthesis gas generating
fluid into the portion through at least one injection wellbore to
generate synthesis gas from hydrocarbons and the synthesis gas
generating fluid; and producing synthesis gas from at least one
heat source wellbore in which is positioned proximate to a heat
source of the one or more heat sources.
4665. The method of claim 4664, wherein the temperature sufficient
to allow synthesis gas generation is within a range from about
400.degree. C. to about 1200.degree. C.
4666. The method of claim 4664, wherein creating a substantially
uniform permeability comprises heating the portion to a temperature
within a range sufficient to pyrolyze hydrocarbons within the
portion, raising the temperature within the portion at a rate of
less than about 5.degree. C. per day during pyrolyzation and
removing a portion of pyrolyzed fluid from the formation.
4667. The method of claim 4664, further comprising removing fluid
from the formation through at least the one injection wellbore
prior to heating the selected section to the temperature sufficient
to allow synthesis gas generation.
4668. The method of claim 4664, wherein the injection wellbore
comprises a wellbore of a heat source in which is positioned a heat
source of the one or more heat sources.
4669. The method of claim 4664, further comprising heating the
selected portion during providing the synthesis gas generating
fluid to inhibit temperature decrease in at least the portion of
the selected section due to synthesis gas generation.
4670. The method of claim 4664, further comprising providing a
portion of the heat needed to raise the temperature sufficient to
allow synthesis gas generation by convecting an oxidizing fluid to
hydrocarbons within the selected section to oxidize a portion of
the hydrocarbons and generate heat.
4671. The method of claim 4664, further comprising controlling the
heating of the selected section and provision of the synthesis gas
generating fluid to maintain a temperature within the selected
section above the temperature sufficient to generate synthesis
gas.
4672. The method of claim 4664, further comprising: monitoring a
composition of the produced synthesis gas; and controlling heating
of the selected section and provision of the synthesis gas
generating fluid to maintain the composition of the produced
synthesis gas within a desired range.
4673. The method of claim 4664, wherein the synthesis gas
generating fluid comprises liquid water.
4674. The method of claim 4664, wherein the synthesis gas
generating fluid comprises steam.
4675. The method of claim 4664, wherein the synthesis gas
generating fluid comprises steam to heat the selected section and
to generate synthesis gas.
4676. The method of claim 4664, wherein the synthesis gas
generating fluid comprises water and carbon dioxide.
4677. The method of claim 4676, wherein a portion of the carbon
dioxide comprises carbon dioxide removed from the formation.
4678. The method of claim 4664, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4679. The method of claim 4678, wherein a portion of the carbon
dioxide comprises carbon dioxide removed from the formation.
4680. The method of claim 4664, wherein providing the synthesis gas
generating fluid to the selected section comprises raising a water
table of the formation to allow water to enter the selected
section.
4681. The method of claim 4664, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons undergo a reaction within the selected section to
increase a H.sub.2 concentration within the produced synthesis
gas.
4682. The method of claim 4664, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within the selected section to increase an
energy content of the produced synthesis gas.
4683. The method of claim 4664, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4684. The method of claim 4664, further comprising generating
electricity from the synthesis gas using a fuel cell.
4685. The method of claim 4664, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent portion of
the formation.
4686. The method of claim 4664, further comprising using a portion
of the synthesis gas as a combustion fuel for heating the
formation.
4687. The method of claim 4664, further comprising converting at
least a portion of the produced synthesis gas to condensable
hydrocarbons using a Fischer-Tropsch synthesis process.
4688. The method of claim 4664, further comprising converting at
least a portion of the produced synthesis gas to methanol.
4689. The method of claim 4664, further comprising converting at
least a portion of the produced synthesis gas to gasoline.
4690. The method of claim 4664, further comprising converting at
least a portion of the synthesis gas to methane using a catalytic
methanation process.
4691. The method of claim 4664, wherein a temperature of at least
the one heat source wellbore is maintained at a temperature of less
than approximately 700.degree. C. to produce a synthesis gas having
a ratio of H.sub.2 to carbon monoxide of greater than about 2.
4692. The method of claim 4664, wherein a temperature of at least
the one heat source wellbore is maintained at a temperature of
greater than approximately 700.degree. C. to produce a synthesis
gas having a ratio of H.sub.2 to carbon monoxide of less than about
2.
4693. The method of claim 4664, wherein a temperature of at least
the one heat source wellbore is maintained at a temperature of
approximately 700.degree. C. to produce a synthesis gas having a
ratio of H.sub.2 to carbon monoxide of approximately 2.
4694. The method of claim 4664, wherein a heat source of the one or
more heat sources comprises an electrical heater.
4695. The method of claim 4664, wherein a heat source of the one or
more heat sources comprises a natural distributor heater.
4696. The method of claim 4664, wherein a heat source of the one or
more heat sources comprises a flameless distributor combustor (FDC)
heater, and wherein fluids are produced from the wellbore of the
FDC heater through a conduit positioned within the wellbore.
4697. The method of claim 4664, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4698. The method of claim 4664, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4699. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
the heat from the one or more heat sources pyrolyzes at least a
portion of hydrocarbon material within the selected section of the
formation; producing pyrolysis products from the formation; heating
a first portion of a formation with one or more heat sources to a
temperature sufficient to allow generation of synthesis gas;
providing a first synthesis gas generating fluid to the first
portion to generate a first synthesis gas; removing a portion of
the first synthesis gas from the formation; heating a second
portion of a formation with one more heat sources to a temperature
sufficient to allow generation of synthesis gas having a H.sub.2 to
CO ratio greater than a H.sub.2 to CO ratio of the first synthesis
gas; providing a second synthesis gas generating component to the
second portion to generate a second synthesis gas; removing a
portion of the second synthesis gas from the formation; and
blending a portion of the first synthesis gas with a portion of the
second synthesis gas to produce a blended synthesis gas having a
selected H.sub.2 to CO ratio.
4700. The method of claim 4699, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4701. The method of claim 4699, wherein the first synthesis gas
generating fluid and second synthesis gas generating fluid are the
same component.
4702. The method of claim 4699, further comprising controlling the
temperature in the first portion to control a composition of the
first synthesis gas.
4703. The method of claim 4699, further comprising controlling the
temperature in the second portion to control a composition of the
second synthesis gas.
4704. The method of claim 4699, wherein the selected ratio is
controlled to be approximately 2:1 H.sub.2 to CO.
4705. The method of claim 4699, wherein the selected ratio is
controlled to range from approximately 1.8:1 to approximately 2.2:1
H.sub.2 to CO.
4706. The method of claim 4699, wherein the selected ratio is
controlled to be approximately 3:1 H.sub.2 to CO.
4707. The method of claim 4699, wherein the selected ratio is
controlled to range from approximately 2.8:1 to approximately 3.2:1
H.sub.2 to CO.
4708. The method of claim 4699, further comprising providing at
least a portion of the produced blended synthesis gas to a
condensable hydrocarbon synthesis process to produce condensable
hydrocarbons.
4709. The method of claim 4708, wherein the condensable hydrocarbon
synthesis process comprises a Fischer-Tropsch process.
4710. The method of claim 4709, further comprising cracking at
least a portion of the condensable hydrocarbons to form middle
distillates.
4711. The method of claim 4699, further comprising providing at
least a portion of the produced blended synthesis gas to a
catalytic methanation process to produce methane.
4712. The method of claim 4699, further comprising providing at
least a portion of the produced blended synthesis gas to a
methanol-synthesis process to produce methanol.
4713. The method of claim 4699, further comprising providing at
least a portion of the produced blended synthesis gas to a
gasoline-synthesis process to produce gasoline.
4714. The method of claim 4699, wherein removing a portion of the
second synthesis gas comprises withdrawing second synthesis gas
through a production well, wherein a temperature of the production
well adjacent to a second syntheses gas production zone is
maintained at a substantially constant temperature configured to
produce second synthesis gas having the H.sub.2 to CO ratio greater
the first synthesis gas.
4715. The method of claim 4699, wherein the first synthesis gas
producing fluid comprises CO.sub.2 and wherein the temperature of
the first portion is at a temperature that will result in
conversion of CO.sub.2 and carbon from the first portion to CO to
generate a CO rich first synthesis gas.
4716. The method of claim 4699, wherein the second synthesis gas
producing fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons react within the formation to increase a H.sub.2
concentration within the produced second synthesis gas.
4717. The method of claim 4699, wherein blending a portion of the
first synthesis gas with a portion of the second synthesis gas
comprises producing an intermediate mixture having a H.sub.2 to CO
mixture of less than the selected ratio, and subjecting the
intermediate mixture to a shift reaction to reduce an amount of CO
and increase an amount of H.sub.2 to produce the selected ratio of
H.sub.2 to CO.
4718. The method of claim 4699, further comprising removing an
excess of first synthesis gas from the first portion to have an
excess of CO, subjecting the first synthesis gas to a shift
reaction to reduce an amount of CO and increase an amount of
H.sub.2 before blending the first synthesis gas with the second
synthesis gas.
4719. The method of claim 4699, further comprising removing the
first synthesis gas from the formation under pressure, and passing
removed first synthesis gas through a turbine to generate
electricity.
4720. The method of claim 4699, further comprising removing the
second synthesis gas from the formation under pressure, and passing
removed second synthesis gas through a turbine to generate
electricity.
4721. The method of claim 4699, further comprising generating
electricity from the blended synthesis gas using a fuel cell.
4722. The method of claim 4699, further comprising generating
electricity from the blended synthesis gas using a fuel cell,
separating carbon dioxide from a fluid exiting the fuel cell, and
storing a portion of the separated carbon dioxide within a spent
portion of the formation.
4723. The method of claim 4699, further comprising using at least a
portion of the blended synthesis gas as a combustion fuel for
heating the formation.
4724. The method of claim 4699, further comprising allowing the
heat to transfer from the one or more heat sources to the selected
section to substantially uniformly increase a permeability of the
selected section.
4725. The method of claim 4699, further comprising controlling heat
transfer from the one or more heat sources to produce a
permeability within the selected section of greater than about 100
millidarcy.
4726. The method of claim 4699, further comprising heating at least
the portion of the selected section when providing the synthesis
gas generating fluid to inhibit temperature decrease within the
selected section during synthesis gas generation.
4727. The method of claim 4699, wherein the temperature sufficient
to allow synthesis gas generation is within a range from
approximately 400.degree. C. to approximately 1200.degree. C.
4728. The method of claim 4699, wherein heating the first a portion
of the selected section to a temperature sufficient to allow
synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4729. The method of claim 4699, wherein heating the second portion
of the selected section to a temperature sufficient to allow
synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4730. The method of claim 4699, wherein heating the first portion
of the selected section to a temperature sufficient to allow
synthesis gas generation comprises: introducing an oxidizing fluid
into the formation through a wellbore; transporting the oxidizing
fluid substantially by convection into the first portion of the
selected section, wherein the first portion of the selected section
is at a temperature sufficient to support an oxidization reaction
with the oxidizing fluid; and reacting the oxidizing fluid within
the first portion of the selected section to generate heat and
raise the temperature of the first portion.
4731. The method of claim 4699, wherein heating the second portion
of the selected section to a temperature sufficient to allow
synthesis gas generation comprises: introducing an oxidizing fluid
into the formation through a wellbore; transporting the oxidizing
fluid substantially by convection into the second portion of the
selected section, wherein the second portion of the selected
section is at a temperature sufficient to support an oxidization
reaction with the oxidizing fluid; and reacting the oxidizing fluid
within the second portion of the selected section to generate heat
and raise the temperature of the second portion.
4732. The method of claim 4699, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4733. The method of claim 4699, wherein the one or more heat
sources comprises one or more natural distributor combustors.
4734. The method of claim 4699, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
4735. The method of claim 4699, wherein heating the first portion
of the selected section to a temperature sufficient to allow
synthesis gas generation and providing a first synthesis gas
generating fluid to the first portion of the selected section
comprises introducing steam into the first portion.
4736. The method of claim 4699, wherein heating the second portion
of the selected section to a temperature sufficient to allow
synthesis gas generation and providing a second synthesis gas
generating fluid to the second portion of the selected section
comprises introducing steam into the second portion.
4737. The method of claim 4699, further comprising controlling the
heating of the first portion of selected section and provision of
the first synthesis gas generating fluid to maintain a temperature
within the first portion of the selected section above the
temperature sufficient to generate synthesis gas.
4738. The method of claim 4699, further comprising controlling the
heating of the second portion of selected section and provision of
the second synthesis gas generating fluid to maintain a temperature
within the second portion of the selected section above the
temperature sufficient to generate synthesis gas.
4739. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises liquid water.
4740. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises liquid water.
4741. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises steam.
4742. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises steam.
4743. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
4744. The method of claim 4743, wherein a portion of the carbon
dioxide within the first synthesis gas generating fluid comprises
carbon dioxide removed from the formation.
4745. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
4746. The method of claim 4745, wherein a portion of the carbon
dioxide within the second synthesis gas generating fluid comprises
carbon dioxide removed from the formation.
4747. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4748. The method of claim 4747, wherein a portion of the carbon
dioxide within the first synthesis gas generating fluid comprises
carbon dioxide removed from the formation.
4749. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4750. The method of claim 4749, wherein a portion of the carbon
dioxide within the second synthesis gas generating fluid comprises
carbon dioxide removed from the formation.
4751. The method of claim 4699, wherein providing the first
synthesis gas generating fluid to the first portion of the selected
section comprises raising a water table of the formation to allow
water to flow into the first portion of the selected section.
4752. The method of claim 4699, wherein providing the second
synthesis gas generating fluid to the second portion of the
selected section comprises raising a water table of the formation
to allow water to flow into the second portion of the selected
section.
4753. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within the first portion
of the selected section to increase a H.sub.2 concentration within
the produced first synthesis gas.
4754. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within the second portion
of the selected section to increase a H.sub.2 concentration within
the produced second synthesis gas.
4755. The method of claim 4699, wherein the first synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within the first portion of the selected section
to increase an energy content of the produced first synthesis
gas.
4756. The method of claim 4699, wherein the second synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within at least the second portion of the
selected section to increase an energy content of the second
produced synthesis gas.
4757. The method of claim 4699, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced blended synthesis gas through a turbine to
generate electricity.
4758. The method of claim 4699, further comprising generating
electricity from the blended synthesis gas using a fuel cell.
4759. The method of claim 4699, further comprising generating
electricity from the blended synthesis gas using a fuel cell,
separating carbon dioxide from a fluid exiting the fuel cell, and
storing a portion of the separated carbon dioxide within a spent
section of the formation.
4760. The method of claim 4699, further comprising using a portion
of the blended synthesis gas as a combustion fuel for the one or
more heat sources.
4761. The method of claim 4699, further comprising using a portion
of the first synthesis gas as a combustion fuel for the one or more
heat sources.
4762. The method of claim 4699, further comprising using a portion
of the second synthesis gas as a combustion fuel for the one or
more heat sources.
4763. The method of claim 4699, further comprising using a portion
of the blended synthesis gas as a combustion fuel for the one or
more heat sources.
4764. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
the heat from the one or more heat sources pyrolyzes at least some
of the hydrocarbons within the selected section of the formation;
producing pyrolysis products from the formation; heating at least a
portion of the selected section to a temperature sufficient to
generate synthesis gas; controlling a temperature of at least a
portion of the selected section to generate synthesis gas having a
selected H.sub.2 to CO ratio; providing a synthesis gas generating
fluid to at least the portion of the selected section to generate
synthesis gas; and producing a portion of the synthesis gas from
the formation.
4765. The method of claim 4764, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4766. The method of claim 4764, wherein the selected ratio is
controlled to be approximately 2:1 H.sub.2 to CO.
4767. The method of claim 4764, wherein the selected ratio is
controlled to range from approximately 1.8:1 to approximately 2.2:1
H.sub.2 to CO.
4768. The method of claim 4764, wherein the selected ratio is
controlled to be approximately 3:1 H.sub.2 to CO.
4769. The method of claim 4764, wherein the selected ratio is
controlled to range from approximately 2.8:1 to approximately 3.2:1
H.sub.2 to CO.
4770. The method of claim 4764, further comprising providing at
least a portion of the produced synthesis gas to a condensable
hydrocarbon synthesis process to produce condensable
hydrocarbons.
4771. The method of claim 4770, wherein the condensable hydrocarbon
synthesis process comprises a Fischer-Tropsch process.
4772. The method of claim 4771, further comprising cracking at
least a portion of the condensable hydrocarbons to form middle
distillates.
4773. The method of claim 4764, further comprising providing at
least a portion of the produced synthesis gas to a catalytic
methanation process to produce methane.
4774. The method of claim 4764, further comprising providing at
least a portion of the produced synthesis gas to a
methanol-synthesis process to produce methanol.
4775. The method of claim 4764, further comprising providing at
least a portion of the produced synthesis gas to a
gasoline-synthesis process to produce gasoline.
4776. The method of claim 4764, further comprising allowing the
heat to transfer from the one or more heat sources to the selected
section to substantially uniformly increase a permeability of the
selected section.
4777. The method of claim 4764, further comprising controlling heat
transfer from the one or more heat sources to produce a
permeability within the selected section of greater than about 100
millidarcy.
4778. The method of claim 4764, further comprising heating at least
the portion of the selected section when providing the synthesis
gas generating fluid to inhibit temperature decrease within the
selected section during synthesis gas generation.
4779. The method of claim 4764, wherein the temperature sufficient
to allow synthesis gas generation is within a range from
approximately 400.degree. C. to approximately 1200.degree. C.
4780. The method of claim 4764, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4781. The method of claim 4764, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: introducing an oxidizing
fluid into the formation through a wellbore; transporting the
oxidizing fluid substantially by convection into the portion of the
selected section, wherein the portion of the selected section is at
a temperature sufficient to support an oxidization reaction with
the oxidizing fluid; and reacting the oxidizing fluid within the
portion of the selected section to generate heat and raise the
temperature of the portion.
4782. The method of claim 4764, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4783. The method of claim 4764, wherein the one or more heat
sources comprises one or more natural distributor combustors.
4784. The method of claim 4764, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
4785. The method of claim 4764, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation and providing a synthesis gas
generating fluid to at least the portion of the selected section
comprises introducing steam into the portion.
4786. The method of claim 4764, further comprising controlling the
heating of at least the portion of selected section and provision
of the synthesis gas generating fluid to maintain a temperature
within at least the portion of the selected section above the
temperature sufficient to generate synthesis gas.
4787. The method of claim 4764, wherein the synthesis gas
generating fluid comprises liquid water.
4788. The method of claim 4764, wherein the synthesis gas
generating fluid comprises steam.
4789. The method of claim 4764, wherein the synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
4790. The method of claim 4789, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4791. The method of claim 4764, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4792. The method of claim 4791, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4793. The method of claim 4764, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
4794. The method of claim 4764, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within at least the
portion of the selected section to increase a H.sub.2 concentration
within the produced synthesis gas.
4795. The method of claim 4764, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within at least the portion of the selected
section to increase an energy content of the produced synthesis
gas.
4796. The method of claim 4764, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4797. The method of claim 4764, further comprising generating
electricity from the synthesis gas using a fuel cell.
4798. The method of claim 4764, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent section of
the formation.
4799. The method of claim 4764, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4800. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
the heat from the one or more heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation;
producing pyrolysis products from the formation; heating at least a
portion of the selected section to a temperature sufficient to
generate synthesis gas; controlling a temperature in or proximate
to a synthesis gas production well to generate synthesis gas having
a selected H.sub.2 to CO ratio; providing a synthesis gas
generating fluid to at least the portion of the selected section to
generate synthesis gas; and producing synthesis gas from the
formation.
4801. The method of claim 4800, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4802. The method of claim 4800, wherein the selected ratio is
controlled to be approximately 2:1 H.sub.2 to CO.
4803. The method of claim 4800, wherein the selected ratio is
controlled to range from approximately 1.8:1 to approximately 2.2:1
H.sub.2 to CO.
4804. The method of claim 4800, wherein the selected ratio is
controlled to be approximately 3:1 H.sub.2 to CO.
4805. The method of claim 4800, wherein the selected ratio is
controlled to range from approximately 2.8:1 to approximately 3.2:1
H.sub.2 to CO.
4806. The method of claim 4800, further comprising providing at
least a portion of the produced synthesis gas to a condensable
hydrocarbon synthesis process to produce condensable
hydrocarbons.
4807. The method of claim 4806, wherein the condensable hydrocarbon
synthesis process comprises a Fischer-Tropsch process.
4808. The method of claim 4807, further comprising cracking at
least a portion of the condensable hydrocarbons to form middle
distillates.
4809. The method of claim 4800, further comprising providing at
least a portion of the produced synthesis gas to a catalytic
methanation process to produce methane.
4810. The method of claim 4800, further comprising providing at
least a portion of the produced synthesis gas to a
methanol-synthesis process to produce methanol.
4811. The method of claim 4800, further comprising providing at
least a portion of the produced synthesis gas to a
gasoline-synthesis process to produce gasoline.
4812. The method of claim 4800, further comprising allowing the
heat to transfer from the one or more heat sources to the selected
section to substantially uniformly increase a permeability of the
selected section.
4813. The method of claim 4800, further comprising controlling heat
transfer from the one or more heat sources to produce a
permeability within the selected section of greater than about 100
millidarcy.
4814. The method of claim 4800, further comprising heating at least
the portion of the selected section when providing the synthesis
gas generating fluid to inhibit temperature decrease within the
selected section during synthesis gas generation.
4815. The method of claim 4800, wherein the temperature sufficient
to allow synthesis gas generation is within a range from
approximately 400.degree. C. to approximately 1200.degree. C.
4816. The method of claim 4800, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4817. The method of claim 4800, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: introducing an oxidizing
fluid into the formation through a wellbore; transporting the
oxidizing fluid substantially by convection into the portion of the
selected section, wherein the portion of the selected section is at
a temperature sufficient, to support an oxidization reaction with
the oxidizing fluid; and reacting the oxidizing fluid within the
portion of the selected section to generate heat and raise the
temperature of the portion.
4818. The method of claim 4800, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4819. The method of claim 4800, wherein the one or more heat
sources comprises one or more natural distributor combustors.
4820. The method of claim 4800, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
4821. The method of claim 4800, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation and providing a synthesis gas
generating fluid to at least the portion of the selected section
comprises introducing steam into the portion.
4822. The method of claim 4800, further comprising controlling the
heating of at least the portion of selected section and provision
of the synthesis gas generating fluid to maintain a temperature
within at least the portion of the selected section above the
temperature sufficient to generate synthesis gas.
4823. The method of claim 4800, wherein the synthesis gas
generating fluid comprises liquid water.
4824. The method of claim 4800, wherein the synthesis gas
generating fluid comprises steam.
4825. The method of claim 4800, wherein the synthesis gas
generating fluid comprises water and carbon dioxide.
4826. The method of claim 4825, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4827. The method of claim 4800, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4828. The method of claim 4827, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4829. The method of claim 4800, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
4830. The method of claim 4800, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within at least the
portion of the selected section to increase a H.sub.2 concentration
within the produced synthesis gas.
4831. The method of claim 4800, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within at least the portion of the selected
section to increase an energy content of the produced synthesis
gas.
4832. The method of claim 4800, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4833. The method of claim 4800, further comprising generating
electricity from the synthesis gas using a fuel cell.
4834. The method of claim 4800, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent section of
the formation.
4835. The method of claim 4800, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4836. A method of treating a coal formation in situ, comprising:
providing heat from one or more heat sources to at least a portion
of the formation; allowing the heat to transfer from the one or
more heat sources to a selected section of the formation such that
the heat from the one or more heat sources pyrolyzes at least some
of the hydrocarbons within the selected section of the formation;
producing pyrolysis products from the formation; heating at least a
portion of the selected section to a temperature sufficient to
generate synthesis gas; controlling a temperature of at least a
portion of the selected section to generate synthesis gas having a
H.sub.2 to CO ratio different than a selected H.sub.2 to CO ratio;
providing a synthesis gas generating fluid to at least the portion
of the selected section to generate synthesis gas; and producing
synthesis gas from the formation; providing at least a portion of
the produced synthesis gas to a shift process wherein an amount of
carbon monoxide is converted to carbon dioxide; separating at least
a portion of the carbon dioxide to obtain a gas having a selected
H.sub.2 to CO ratio.
4837. The method of claim 4836, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4838. The method of claim 4836, wherein the selected ratio is
controlled to be approximately 2:1 H.sub.2 to CO.
4839. The method of claim 4836, wherein the selected ratio is
controlled to range from approximately 1.8:1 to 2.2:1 H.sub.2 to
CO.
4840. The method of claim 4836, wherein the selected ratio is
controlled to be approximately 3:1 H.sub.2 to CO.
4841. The method of claim 4836, wherein the selected ratio is
controlled to range from approximately 2.8:1 to 3.2:1 H.sub.2 to
CO.
4842. The method of claim 4836, further comprising providing at
least a portion of the produced synthesis gas to a condensable
hydrocarbon synthesis process to produce condensable
hydrocarbons.
4843. The method of claim 4842, wherein the condensable hydrocarbon
synthesis process comprises a Fischer-Tropsch process.
4844. The method of claim 4843, further comprising cracking at
least a portion of the condensable hydrocarbons to form middle
distillates.
4845. The method of claim 4836, further comprising providing at
least a portion of the produced synthesis gas to a catalytic
methanation process to produce methane.
4846. The method of claim 4836, further comprising providing at
least a portion of the produced synthesis gas to a
methanol-synthesis process to produce methanol.
4847. The method of claim 4836, further comprising providing at
least a portion of the produced synthesis gas to a
gasoline-synthesis process to produce gasoline.
4848. The method of claim 4836, further comprising allowing the
heat to transfer from the one or more heat sources to the selected
section to substantially uniformly increase a permeability of the
selected section.
4849. The method of claim 4836, further comprising controlling heat
transfer from the one or more heat sources to produce a
permeability within the selected section of greater than about 100
millidarcy.
4850. The method of claim 4836, further comprising heating at least
the portion of the selected section when providing the synthesis
gas generating fluid to inhibit temperature decrease within the
selected section during synthesis gas generation.
4851. The method of claim 4836, wherein the temperature sufficient
to allow synthesis gas generation is within a range from
approximately 400.degree. C. to approximately 1200.degree. C.
4852. The method of claim 4836, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: heating zones adjacent to
wellbores of one or more heat sources with heaters disposed in the
wellbores, wherein the heaters are configured to raise temperatures
of the zones to temperatures sufficient to support reaction of
hydrocarbon material within the zones with an oxidizing fluid;
introducing the oxidizing fluid to the zones substantially by
diffusion; allowing the oxidizing fluid to react with at least a
portion of the hydrocarbon material within the zones to produce
heat in the zones; and transferring heat from the zones to the
selected section.
4853. The method of claim 4836, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation comprises: introducing an oxidizing
fluid into the formation through a wellbore; transporting the
oxidizing fluid substantially by convection into the portion of the
selected section, wherein the portion of the selected section is at
a temperature sufficient to support an oxidization reaction with
the oxidizing fluid; and reacting the oxidizing fluid within the
portion of the selected section to generate heat and raise the
temperature of the portion.
4854. The method of claim 4836, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4855. The method of claim 4836, wherein the one or more heat
sources comprises one or more natural distributor combustors.
4856. The method of claim 4836, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
4857. The method of claim 4836, wherein heating at least the
portion of the selected section to a temperature sufficient to
allow synthesis gas generation and providing a synthesis gas
generating fluid to at least the portion of the selected section
comprises introducing steam into the portion.
4858. The method of claim 4836, further comprising controlling the
heating of at least the portion of selected section and provision
of the synthesis gas generating fluid to maintain a temperature
within at least the portion of the selected section above the
temperature sufficient to generate synthesis gas.
4859. The method of claim 4836, wherein the synthesis gas
generating fluid comprises liquid water.
4860. The method of claim 4836, wherein the synthesis gas
generating fluid comprises steam.
4861. The method of claim 4836, wherein the synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
4862. The method of claim 4861, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4863. The method of claim 4836, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
4864. The method of claim 4863, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
4865. The method of claim 4836, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
4866. The method of claim 4836, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers less than 5, and wherein at least a portion of the
hydrocarbons are subjected to a reaction within at least the
portion of the selected section to increase a H.sub.2 concentration
within the produced synthesis gas.
4867. The method of claim 4836, wherein the synthesis gas
generating fluid comprises water and hydrocarbons having carbon
numbers greater than 4, and wherein at least a portion of the
hydrocarbons react within at least the portion of the selected
section to increase an energy content of the produced synthesis
gas.
4868. The method of claim 4836, further comprising maintaining a
pressure within the formation during synthesis gas generation, and
passing produced synthesis gas through a turbine to generate
electricity.
4869. The method of claim 4836, further comprising generating
electricity from the synthesis gas using a fuel cell.
4870. The method of claim 4836, further comprising generating
electricity from the synthesis gas using a fuel cell, separating
carbon dioxide from a fluid exiting the fuel cell, and storing a
portion of the separated carbon dioxide within a spent section of
the formation.
4871. The method of claim 4836, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4872. A method of forming a spent portion of formation within a
coal formation, comprising: heating a first portion of the
formation to pyrolyze hydrocarbons within the first portion and to
establish a substantially uniform permeability within the first
portion; and cooling the first portion.
4873. The method of claim 4872, wherein heating the first portion
comprises transferring heat to the first portion from one or more
electrical heaters.
4874. The method of claim 4872, wherein heating the first portion
comprises transferring heat to the first portion from one or more
natural distributor combustors.
4875. The method of claim 4872, wherein heating the first portion
comprises transferring heat to the first portion from one or more
flameless distributor combustors.
4876. The method of claim 4872, wherein heating the first portion
comprises transferring heat to the first portion from heat transfer
fluid flowing within one or more wellbores within the
formation.
4877. The method of claim 4876, wherein the heat transfer fluid
comprises steam.
4878. The method of claim 4876, wherein the heat transfer fluid
comprises combustion products from a burner.
4879. The method of claim 4872, wherein heating the first portion
comprises transferring heat to the first portion from at least two
heater wells positioned within the formation, wherein the at least
two heater wells are placed in a substantially regular pattern,
wherein the substantially regular pattern comprises repetition of a
base heater unit, and wherein the base heater unit is formed of a
number of heater wells.
4880. The method of claim 4879, wherein a spacing between a pair of
adjacent heater wells is within a range from about 6 m to about 15
m.
4881. The method of claim 4879, further comprising removing fluid
from the formation through one or more production wells.
4882. The method of claim 4881, wherein the one or more production
wells are located in a pattern, and wherein the one or more
production wells are positioned substantially at centers of base
heater units.
4883. The method of claim 4879, wherein the heater unit comprises
three heater wells positioned substantially at apexes of an
equilateral triangle.
4884. The method of claim 4879, wherein the heater unit comprises
four heater wells positioned substantially at apexes of a
rectangle.
4885. The method of claim 4879, wherein the heater unit comprises
five heater wells positioned substantially at apexes of a regular
pentagon.
4886. The method of claim 4879, wherein the heater unit comprises
six heater wells positioned substantially at apexes of a regular
hexagon.
4887. The method of claim 4872, further comprising introducing
water to the first portion to cool the formation.
4888. The method of claim 4872, further comprising removing steam
from the formation.
4889. The method of claim 4888, further comprising using a portion
of the removed steam to heat a second portion of the formation.
4890. The method of claim 4872, further comprising removing
pyrolyzation products from the formation.
4891. The method of claim 4872, further comprising generating
synthesis gas within the portion by introducing a synthesis gas
generating fluid into the portion, and removing synthesis gas from
the formation.
4892. The method of claim 4872, further comprising heating a second
section of the formation to pyrolyze hydrocarbons within the second
portion, removing pyrolyzation fluid from the second portion, and
storing a portion of the removed pyrolyzation fluid within the
first portion.
4893. The method of claim 4892, wherein the portion of the removed
pyrolyzation fluid is stored within the first portion when surface
facilities that process the removed pyrolyzation fluid are not able
to process the portion of the removed pyrolyzation fluid.
4894. The method of claim 4892, further comprising heating the
first portion to facilitate removal of the stored pyrolyzation
fluid from the first portion.
4895. The method of claim 4872, further comprising generating
synthesis gas within a second portion of the formation, removing
synthesis gas from the second portion, and storing a portion of the
removed synthesis gas within the first portion.
4896. The method of claim 4895, wherein the portion of the removed
synthesis gas from the second portion are stored within the first
portion when surface facilities that process the removed synthesis
gas are not able to process the portion of the removed synthesis
gas.
4897. The method of claim 4895, further comprising heating the
first portion to facilitate removal of the stored synthesis gas
from the first portion.
4898. The method of claim 4872, further comprising removing at
least a portion of carbon containing material in the first
portion.
4899. The method of claim 4898, further comprising using at least a
portion of the carbon containing material removed from the
formation in a metallurgical application.
4900. The method of claim 4899, wherein the metallurgical
application comprises steel manufacturing.
4901. A method of sequestering carbon dioxide within a coal
formation, comprising: heating a portion of the formation to
increase permeability and form a substantially uniform permeability
within the portion; allowing the portion to cool; and storing
carbon dioxide within the portion.
4902. The method of claim 4901, wherein the permeability of the
portion is increased to over 100 millidarcy.
4903. The method of claim 4901, further comprising raising a water
level within the portion to inhibit migration of the carbon dioxide
from the portion.
4904. The method of claim 4901, further comprising heating the
portion to release carbon dioxide, and removing carbon dioxide from
the portion.
4905. The method of claim 4901, further comprising pyrolyzing
hydrocarbons within the portion during heating of the portion, and
removing pyrolyzation product from the formation.
4906. The method of claim 4901, further comprising producing
synthesis gas from the portion during the heating of the portion,
and removing synthesis gas from the formation.
4907. The method of claim 4901, wherein heating the portion
comprises: heating hydrocarbon material adjacent to one or more
wellbores to a temperature sufficient to support oxidation of the
hydrocarbon material with an oxidizing fluid; introducing the
oxidizing fluid to hydrocarbon material adjacent to the one or more
wellbores to oxidize hydrocarbons and produce heat; and conveying
produced heat to the portion.
4908. The method of claim 4907, wherein heating hydrocarbon
material adjacent to the one or more wells comprises electrically
heating the hydrocarbon material.
4909. The method of claim 4907, wherein the temperature sufficient
to support oxidation is in a range between approximately
200.degree. C. to approximately 1200.degree. C.
4910. The method of claim 4901, wherein heating the portion
comprises circulating heat transfer fluid through one or more
heating wells within the formation.
4911. The method of claim 4910, wherein the heat transfer fluid
comprises combustion products from a burner.
4912. The method of claim 4910, wherein the heat transfer fluid
comprises steam.
4913. The method of claim 4901, further comprising removing fluid
from the formation during heating of the formation, and combusting
a portion of the removed fluid to generate heat to heat the
formation.
4914. The method of claim 4901, further comprising using at least a
portion of the carbon dioxide for hydrocarbon bed demethanation
prior to storing the carbon dioxide within the portion.
4915. The method of claim 4901, further comprising using a portion
of the carbon dioxide for enhanced oil recovery prior to storing
the carbon dioxide within the portion.
4916. The method of claim 4901, wherein at least a portion of the
carbon dioxide comprises carbon dioxide generated in a fuel
cell.
4917. The method of claim 4901, wherein at least a portion of the
carbon dioxide comprises carbon dioxide formed as a combustion
product.
4918. The method of claim 4901, further comprising allowing the
portion to cool by introducing water to the portion; and removing
the water from the formation as steam.
4919. The method of claim 4918, further comprising using the steam
as a heat transfer fluid to heat a second portion of the
formation.
4920. The method of claim 4901, wherein storing carbon dioxide in
the portion comprises adsorbing carbon dioxide to carbon containing
material within the formation.
4921. The method of claim 4901, wherein storing carbon dioxide
comprises passing a first fluid stream comprising the carbon
dioxide and other fluid through the portion; adsorbing carbon
dioxide onto carbon containing material within the formation; and
removing a second fluid stream from the formation, wherein a
concentration of the other fluid in the second fluid stream is
greater than concentration of other fluid in the first stream due
to the absence of the adsorbed carbon dioxide in the second
stream.
4922. The method of claim 4901, wherein an amount of carbon dioxide
stored within the portion is equal to or greater than an amount of
carbon dioxide generated within the portion and removed from the
formation during heating of the portion.
4923. The method of claim 4901, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4924. The method of claim 4901, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4925. A method of in situ sequestration of carbon dioxide within a
coal formation in situ, comprising: providing heat from one or more
heat sources to at least a first portion of the formation; allowing
the heat to transfer from one or more sources to a selected section
of the formation such that the heat from the one or more heat
sources pyrolyzes at least some hydrocarbons within the selected
section of the formation; producing pyrolyzation fluids, wherein
the pyrolyzation fluids comprise carbon dioxide; and storing an
amount of carbon dioxide in the formation, wherein the amount of
stored carbon dioxide is equal to or greater than an amount of
carbon dioxide within the pyrolyzation fluids.
4926. The method of claim 4925, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4927. The method of claim 4925, wherein the carbon dioxide is
stored within a spent portion of the formation.
4928. The method of claim 4925, wherein a portion of the carbon
dioxide stored within the formation is carbon dioxide separated
from the pyrolyzation fluids.
4929. The method of claim 4925, further comprising separating a
portion of carbon dioxide from the pyrolyzation fluids, and using
the carbon dioxide as a flooding agent in enhanced oil
recovery.
4930. The method of claim 4925, further comprising separating a
portion of carbon dioxide from the pyrolyzation fluids, and using
the carbon dioxide as a synthesis gas generating fluid for the
generation of synthesis gas from a section of the formation that is
heated to a temperature sufficient to generate synthesis gas upon
introduction of the synthesis gas generating fluid.
4931. The method of claim 4925, further comprising separating a
portion of carbon dioxide from the pyrolyzation fluids, and using
the carbon dioxide to displace hydrocarbon bed methane.
4932. The method of claim 4931, wherein the hydrocarbon bed is a
deep hydrocarbon bed located over 760 m below ground surface.
4933. The method of claim 4931, further comprising adsorbing a
portion of the carbon dioxide within the hydrocarbon bed.
4934. The method of claim 4925, further comprising using at least a
portion of the pyrolyzation fluids as a feed stream for a fuel
cell.
4935. The method of claim 4934, wherein the fuel cell generates
carbon dioxide, and further comprising storing an amount of carbon
dioxide equal to or greater than an amount of carbon dioxide
generated by the fuel cell within the formation.
4936. The method of claim 4925, wherein a spent portion of the
formation comprises carbon containing material within a section of
the formation that has been heated and from which hydrocarbons have
been produced, and wherein the spent portion of the formation is at
a temperature at which carbon dioxide adsorbs onto the carbon
containing material.
4937. The method of claim 4925, further comprising raising a water
level within the spent portion to inhibit migration of the carbon
dioxide from the portion.
4938. The method of claim 4925, wherein producing fluids from the
formation comprises removing pyrolyzation products from the
formation.
4939. The method of claim 4925, wherein producing fluids from the
formation comprises heating the selected section to a temperature
sufficient to generate synthesis gas; introducing a synthesis gas
generating fluid into the selected section; and removing synthesis
gas from the formation.
4940. The method of claim 4939, wherein the temperature sufficient
to generate synthesis gas ranges from about 400.degree. C. to about
1200.degree. C.
4941. The method of claim 4939, wherein heating the selected
section comprises introducing an oxidizing fluid into the selected
section, reacting the oxidizing fluid within the selected section
to heat the selected section.
4942. The method of claim 4939, wherein heating the selected
section comprises: heating hydrocarbon material adjacent to one or
more wellbores to a temperature sufficient to support oxidation of
the hydrocarbon material with an oxidant; introducing the oxidant
to hydrocarbon material adjacent to the one or more wellbores to
oxidize hydrocarbons and produce heat; and conveying produced heat
to the portion.
4943. The method of claim 4925, wherein the spent portion of the
formation comprises a substantially uniform permeability created by
heating the spent formation and removing fluid during formation of
the spent portion.
4944. The method of claim 4925, wherein the one or more heat
sources comprise electrical heaters.
4945. The method of claim 4925, wherein the one or more heat
sources comprise flameless distributor combustors.
4946. The method of claim 4945, wherein a portion of fuel for the
one or more flameless distributor combustors is obtained from the
formation.
4947. The method of claim 4925, wherein the one or more heat
sources comprise heater wells in the formation through which heat
transfer fluid is circulated.
4948. The method of claim 4947, wherein the heat transfer fluid
comprises combustion products.
4949. The method of claim 4947, wherein the heat transfer fluid
comprises steam.
4950. The method of claim 4925, wherein condensable hydrocarbons
are produced under pressure, and further comprising generating
electricity by passing a portion of the produced fluids through a
turbine.
4951. The method of claim 4925, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, and wherein the unit of
heat sources comprises a triangular pattern.
4952. The method of claim 4925, further comprising providing heat
from three or more heat sources to at least a portion of the
formation, wherein three or more of the heat sources are located in
the formation in a unit of heat sources, wherein the unit of heat
sources comprises a triangular pattern, and wherein a plurality of
the units are repeated over an area of the formation to form a
repetitive pattern of units.
4953. A method for in situ production of energy from a coal
formation, comprising: providing heat from one or more heat sources
to at least a portion of the formation; allowing the heat to
transfer from the one or more heat sources to a selected section of
the formation such that the heat from the one or more heat sources
pyrolyzes at least a portion of hydrocarbons within the selected
section of the formation; producing pyrolysis products from the
formation; providing at least a portion of the pyrolysis products
to a reformer to generate synthesis gas; producing the synthesis
gas from the reformer; providing at least a portion of the produced
synthesis gas to a fuel cell to produce electricity, wherein the
fuel cell produces a carbon dioxide containing exit stream; and
storing at least a portion of the carbon dioxide in the carbon
dioxide containing exit stream in a subsurface formation.
4954. The method of claim 4953, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
4955. The method of claim 4953, wherein at least a portion of the
pyrolysis products are used as fuel in the reformer.
4956. The method of claim 4953, wherein the synthesis gas comprises
carbon dioxide and H.sub.2.
4957. The method of claim 4953, wherein the subsurface formation is
a spent portion of the formation.
4958. The method of claim 4953, wherein the subsurface formation is
an oil reservoir.
4959. The method of claim 4958, wherein at least a portion of the
carbon dioxide is used as a drive fluid for enhanced oil recovery
in the oil reservoir.
4960. The method of claim 4953, wherein the subsurface formation is
a second coal formation.
4961. The method of claim 4960, wherein the second coal formation
is located greater than about 760 m below ground surface.
4962. The method of claim 4960, wherein at least a portion of the
carbon dioxide is used to produce methane from the second coal
formation.
4963. The method of claim 4962, further comprising sequestering at
least a portion of the carbon dioxide within the second coal
formation.
4964. The method of claim 4953, wherein the reformer produces a
reformer carbon dioxide containing exit stream.
4965. The method of claim 4963, further comprising storing at least
a portion of the carbon dioxide in the reformer carbon dioxide
containing exit stream in the subsurface formation.
4966. The method of claim 4965, wherein the subsurface formation is
a spent portion of the formation.
4967. The method of claim 4965, wherein the subsurface formation is
an oil reservoir.
4968. The method of claim 4967, wherein at least a portion of the
carbon dioxide in the reformer carbon dioxide containing exit
stream is used as a drive fluid for enhanced oil recovery in the
oil reservoir.
4969. The method of claim 4965, wherein the subsurface formation is
a second coal formation.
4970. The method of claim 4868, wherein at least a portion of the
carbon dioxide in the reformer carbon dioxide containing exit
stream is used to produce methane from the second coal
formation.
4971. The method of claim 4970, further comprising sequestering at
least a portion of the carbon dioxide in the reformer carbon
dioxide containing exit stream within the second coal
formation.
4972. The method of claim 4969, wherein the second coal formation
is located greater than about 760 m below ground surface.
4973. The method of claim 4953, wherein the fuel cell is a molten
carbonate fuel cell.
4974. The method of claim 4953, wherein the fuel cell is a solid
oxide fuel cell.
4975. The method of claim 4953, further comprising using a portion
of the produced electricity to power electrical heaters within the
formation.
4976. The method of claim 4953, further comprising using a portion
of the produced pyrolysis products as a feed stream for the fuel
cell.
4977. The method of claim 4953, wherein the one or more heat
sources comprise one or more electrical heaters disposed in the
formation.
4978. The method of claim 4953, wherein the one or more heat
sources comprise one or more flameless distributor combustors
disposed in the formation.
4979. The method of claim 4978, wherein a portion of fuel for the
flameless distributor combustors is obtained from the
formation.
4980. The method of claim 4953, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
4981. The method of claim 4953, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
4982. A method for producing ammonia using a coal formation,
comprising: separating air to produce an O.sub.2 rich stream and a
N.sub.2 rich stream; heating a selected section of the formation to
a temperature sufficient to support reaction of hydrocarbon
material in the formation to form synthesis gas; providing
synthesis gas generating fluid and at least a portion of the
O.sub.2 rich stream to the selected section; allowing the synthesis
gas generating fluid and O.sub.2 in the O.sub.2 rich stream to
react with at least a portion of the hydrocarbon material in the
formation to generate synthesis gas; producing synthesis gas from
the formation, wherein the synthesis gas comprises H.sub.2 and CO;
providing at least a portion of the H.sub.2 in the synthesis gas to
an ammonia synthesis process; providing N.sub.2 to the ammonia
synthesis process; and using the ammonia synthesis process to
generate ammonia.
4983. The method of claim 4982, wherein the ratio of the H.sub.2 to
N.sub.2 provided to the ammonia synthesis process is approximately
3:1.
4984. The method of claim 4982, wherein the ratio of the H.sub.2 to
N.sub.2 provided to the ammonia synthesis process ranges from
approximately 2.8:1 to approximately 3.2:1.
4985. The method of claim 4982, wherein the temperature sufficient
to support reaction of hydrocarbon material in the formation to
form synthesis gas ranges from approximately 400.degree. C. to
approximately 1200.degree. C.
4986. The method of claim 4982, further comprising separating at
least a portion of carbon dioxide in the synthesis gas from at
least a portion of the synthesis gas.
4987. The method of claim 4986, wherein the carbon dioxide is
separated from the synthesis gas by an amine separator.
4988. The method of claim 4987, further comprising providing at
least a portion of the carbon dioxide to a urea synthesis process
to produce urea.
4989. The method of claim 4982, wherein at least a portion of the
N.sub.2 stream is used to condense hydrocarbons with 4 or more
carbon atoms from a pyrolyzation fluid.
4990. The method of claim 4982, wherein at least a portion of the
N.sub.2 rich stream is provided to the ammonia synthesis
process.
4991. The method of claim 4982, wherein the air is separated by
cryogenic distillation.
4992. The method of claim 4982, wherein the air is separated by
membrane separation.
4993. The method of claim 4982, wherein fluids produced during
pyrolysis of a coal formation comprise ammonia and, further
comprising adding at least a portion of such ammonia to the ammonia
generated from the ammonia synthesis process.
4994. The method of claim 4982, wherein fluids produced during
pyrolysis of a coal formation are hydrotreated and at least some
ammonia is produced during hydrotreating, and, further comprising
adding at least a portion of such ammonia to the ammonia generated
from the ammonia synthesis process.
4995. The method of claim 4982, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea.
4996. The method of claim 4982, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and, further comprising providing carbon dioxide from
the formation to the urea synthesis process.
4997. The method of claim 4982, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and, further comprising shifting at least a portion of
the carbon monoxide to carbon dioxide in a shift process, and
further comprising providing at least a portion of the carbon
dioxide from the shift process to the urea synthesis process.
4998. The method of claim 4982, wherein heating the selected
section of the formation to a temperature to support reaction of
hydrocarbon material in the formation to form synthesis gas
comprises: heating zones adjacent to wellbores of one or more heat
sources with heaters disposed in the wellbores, wherein the heaters
are configured to raise temperatures of the zones to temperatures
sufficient to support reaction of hydrocarbon material within the
zones with O.sub.2 in the O.sub.2 rich stream; introducing the
O.sub.2 to the zones substantially by diffusion; allowing O.sub.2
in the O.sub.2 rich stream to react with at least a portion of the
hydrocarbon material within the zones to produce heat in the zones;
and transferring heat from the zones to the selected section.
4999. The method of claim 4998, wherein temperatures sufficient to
support reaction of hydrocarbon within the zones with O.sub.2 range
from approximately 200.degree. C. to approximately 1200.degree.
C.
5000. The method of claim 4998, wherein the one or more heat
sources comprises one or more electrical heaters disposed in the
formation.
5001. The method of claim 4998, wherein the one or more heat
sources comprises one or more natural distributor combustors.
5002. The method of claim 4998, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
5003. The method of claim 4998, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
5004. The method of claim 4982, wherein heating the selected
section of the formation to a temperature to support reaction of
hydrocarbon material in the formation to form synthesis gas
comprises: introducing the O.sub.2 rich stream into the formation
through a wellbore; transporting O.sub.2 in the O.sub.2 rich stream
substantially by convection into the portion of the selected
section, wherein the portion of the selected section is at a
temperature sufficient to support an oxidization reaction with
O.sub.2 in the O.sub.2 rich stream; and reacting the O.sub.2 within
the portion of the selected section to generate heat and raise the
temperature of the portion.
5005. The method of claim 5005, wherein the temperature sufficient
to support an oxidization reaction with O.sub.2 ranges from
approximately 200.degree. C. to approximately 1200.degree. C.
5006. The method of claim 5005, wherein the one or more heat
sources comprises one or more electrical heaters disposed in the
formation.
5007. The method of claim 5005, wherein the one or more heat
sources comprises one or more natural distributor combustors.
5008. The method of claim 5005, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
5009. The method of claim 5005, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
5010. The method of claim 4982, further comprising controlling the
heating of at least the portion of the selected section and
provision of the synthesis gas generating fluid to maintain a
temperature within at least the portion of the selected section
above the temperature sufficient to generate synthesis gas.
5011. The method of claim 4982, wherein the synthesis gas
generating fluid comprises liquid water.
5012. The method of claim 4982, wherein the synthesis gas
generating fluid comprises steam.
5013. The method of claim 4982, wherein the synthesis gas
generating fluid comprises water and carbon dioxide wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
5014. The method of claim 5013, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
5015. The method of claim 4982, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
5016. The method of claim 5015, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
5017. The method of claim 4982, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
5018. A method for producing ammonia using a coal formation,
comprising: generating a first ammonia feed stream from a first
portion of the formation; generating a second ammonia feed stream
from a second portion of the formation, wherein the second ammonia
feed stream has a H.sub.2 to N.sub.2 ratio greater than a H.sub.2
to N.sub.2 ratio of the first ammonia feed stream; blending at
least a portion of the first ammonia feed stream with at least a
portion of the second ammonia feed stream to produce a blended
ammonia feed stream having a selected H.sub.2 to N.sub.2 ratio;
providing the blended ammonia feed stream to an ammonia synthesis
process; and using the ammonia synthesis process to generate
ammonia.
5019. The method of claim 5018, wherein the selected ratio is
approximately 3:1.
5020. The method of claim 5018, wherein the selected ratio ranges
from approximately 2.8:1 to approximately 3.2:1.
5021. The method of claim 5018, further comprising separating at
least a portion of carbon dioxide in the first ammonia feed stream
from at least a portion of the first ammonia feed stream.
5022. The method of claim 5021, wherein the carbon dioxide is
separated from the first ammonia feed stream by an amine
separator.
5023. The method of claim 5022, further comprising providing at
least a portion of the carbon dioxide to a urea synthesis
process.
5024. The method of claim 5018, further comprising separating at
least a portion of carbon dioxide in the blended ammonia feed
stream from at least a portion of the blended ammonia feed
stream.
5025. The method of claim 5024, wherein the carbon dioxide is
separated from the blended ammonia feed stream by an amine
separator.
5026. The method of claim 5025, further comprising providing at
least a portion of the carbon dioxide to a urea synthesis
process
5027. The method of claim 5018, further comprising separating at
least a portion of carbon dioxide in the second ammonia feed stream
from at least a portion of the second ammonia feed stream.
5028. The method of claim 5027, wherein the carbon dioxide is
separated from the second ammonia feed stream by an amine
separator.
5029. The method of claim 5028, further comprising providing at
least a portion of the carbon dioxide to a urea synthesis
process.
5030. The method of claim 5018, wherein fluids produced during
pyrolysis of a coal formation comprise ammonia and, further
comprising adding at least a portion of such ammonia to the ammonia
generated from the ammonia synthesis process.
5031. The method of claim 5018, wherein fluids produced during
pyrolysis of a coal formation are hydrotreated and at least some
ammonia is produced during hydrotreating, and further comprising
adding at least a portion of such ammonia to the ammonia generated
from the ammonia synthesis process.
5032. The method of claim 5018, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea.
5033. The method of claim 5018, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and, further comprising providing carbon dioxide from
the formation to the urea synthesis process.
5034. The method of claim 5018, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and further comprising shifting at least a portion of
carbon monoxide in the blended ammonia feed stream to carbon
dioxide in a shift process, and further comprising providing at
least a portion of the carbon dioxide from the shift process to the
urea synthesis process.
5035. A method for producing ammonia using a coal formation,
comprising: heating a selected section of the formation to a
temperature sufficient to support reaction of hydrocarbon material
in the formation to form synthesis gas; providing a synthesis gas
generating fluid and an O.sub.2 rich stream to the selected
section, wherein the amount of N.sub.2 in the O.sub.2 rich stream
is sufficient to generate synthesis gas having a selected ratio of
H.sub.2 to N.sub.2; allowing the synthesis gas generating fluid and
O.sub.2 in the O.sub.2 rich stream to react with at least a portion
of the hydrocarbon material in the formation to generate synthesis
gas having a selected ratio of H.sub.2 to N.sub.2; producing the
synthesis gas from the formation; providing at least a portion of
the H.sub.2 and N.sub.2 in the synthesis gas to an ammonia
synthesis process; using the ammonia synthesis process to generate
ammonia.
5036. The method of claim 5035, further comprising controlling a
temperature of at least a portion of the selected section to
generate synthesis gas having the selected H.sub.2 to N.sub.2
ratio.
5037. The method of claim 5035, wherein the selected ratio is
approximately 3:1.
5038. The method of claim 5035, wherein the selected ratio ranges
from approximately 2.8:1 to 3.2:1.
5039. The method of claim 5035, wherein the temperature sufficient
to support reaction of hydrocarbon material in the formation to
form synthesis gas ranges from approximately 400.degree. C. to
approximately 1200.degree. C.
5040. The method of claim 5035, wherein the O.sub.2 stream and
N.sub.2 stream are obtained by cryogenic separation of air.
5041. The method of claim 5035, wherein the O.sub.2 stream and
N.sub.2 stream are obtained by membrane separation of air.
5042. The method of claim 5035, further comprising separating at
least a portion of carbon dioxide in the synthesis gas from at
least a portion of the synthesis gas.
5043. The method of claim 5042, wherein the carbon dioxide is
separated from the synthesis gas by an amine separator.
5044. The method of claim 5043, further comprising providing at
least a portion of the carbon dioxide to a urea synthesis
process.
5045. The method of claim 5035, wherein fluids produced during
pyrolysis of a coal formation comprise ammonia and, further
comprising adding at least a portion of such ammonia to the ammonia
generated from the ammonia synthesis process.
5046. The method of claim 5035, wherein fluids produced during
pyrolysis of a coal formation are hydrotreated and at least some
ammonia is produced during hydrotreating, and further comprising
adding at least a portion of such ammonia to the ammonia generated
from the ammonia synthesis process.
5047. The method of claim 5035, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea.
5048. The method of claim 5035, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and, further comprising providing carbon dioxide from
the formation to the urea synthesis process.
5049. The method of claim 5035, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and further comprising shifting at least a portion of
carbon monoxide in the synthesis gas to carbon dioxide in a shift
process, and further comprising providing at least a portion of the
carbon dioxide from the shift process to the urea synthesis
process.
5050. The method of claim 5035, wherein heating a selected section
of the formation to a temperature to support reaction of
hydrocarbon material in the formation to form synthesis gas
comprises: heating zones adjacent to wellbores of one or more heat
sources with heaters disposed in the wellbores, wherein the heaters
are configured to raise temperatures of the zones to temperatures
sufficient to support reaction of hydrocarbon material within the
zones with O.sub.2 in the O.sub.2 rich stream; introducing the
O.sub.2 to the zones substantially by diffusion; allowing O.sub.2
in the O.sub.2 rich stream to react with at least a portion of the
hydrocarbon material within the zones to produce heat in the zones;
and transferring heat from the zones to the selected section.
5051. The method of claim 5050, wherein temperatures sufficient to
support reaction of hydrocarbon material within the zones with
O.sub.2 range from approximately 200.degree. C. to approximately
1200.degree. C.
5052. The method of claim 5050, wherein the one or more heat
sources comprises one or more electrical heaters disposed in the
formation.
5053. The method of claim 5050, wherein the one or more heat
sources comprises one or more natural distributor combustors.
5054. The method of claim 5050, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
5055. The method of claim 5050, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
5056. The method of claim 5035, wherein heating the selected
section of the formation to a temperature to support reaction of
hydrocarbon material in the formation to form synthesis gas
comprises: introducing the O.sub.2 rich stream into the formation
through a wellbore; transporting O.sub.2 in the O.sub.2 rich stream
substantially by convection into the portion of the selected
section, wherein the portion of the selected section is at a
temperature sufficient to support an oxidization reaction with
O.sub.2 in the O.sub.2 rich stream; and reacting the O.sub.2 within
the portion of the selected section to generate heat and raise the
temperature of the portion.
5057. The method of claim 5056, wherein the temperature sufficient
to support an oxidization reaction with O.sub.2 ranges from
approximately 200.degree. C. to approximately 1200.degree. C.
5058. The method of claim 5056, wherein the one or more heat
sources comprises one or more electrical heaters disposed in the
formation.
5059. The method of claim 5056, wherein the one or more heat
sources comprises one or more natural distributor combustors.
5060. The method of claim 5056, wherein the one or more heat
sources comprise one or more heater wells, wherein at least one
heater well comprises a conduit disposed within the formation, and
further comprising heating the conduit by flowing a hot fluid
through the conduit.
5061. The method of claim 5056, further comprising using a portion
of the synthesis gas as a combustion fuel for the one or more heat
sources.
5062. The method of claim 5035, further comprising controlling the
heating of at least the portion of the selected section and
provision of the synthesis gas generating fluid to maintain a
temperature within at least the portion of the selected section
above the temperature sufficient to generate synthesis gas.
5063. The method of claim 5035, wherein the synthesis gas
generating fluid comprises liquid water.
5064. The method of claim 5035, wherein the synthesis gas
generating fluid comprises steam.
5065. The method of claim 5035, wherein the synthesis gas
generating fluid comprises water and carbon dioxide, wherein the
carbon dioxide inhibits production of carbon dioxide from the
selected section.
5066. The method of claim 5065, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
5067. The method of claim 5035, wherein the synthesis gas
generating fluid comprises carbon dioxide, and wherein a portion of
the carbon dioxide reacts with carbon in the formation to generate
carbon monoxide.
5068. The method of claim 5067, wherein a portion of the carbon
dioxide within the synthesis gas generating fluid comprises carbon
dioxide removed from the formation.
5069. The method of claim 5035, wherein providing the synthesis gas
generating fluid to at least the portion of the selected section
comprises raising a water table of the formation to allow water to
flow into the at least the portion of the selected section.
5070. A method for producing ammonia using a coal formation,
comprising: providing a first stream comprising N.sub.2 and carbon
dioxide to the formation; allowing at least a portion of the carbon
dioxide in the first stream to adsorb in the formation; producing a
second stream from the formation, wherein the second stream
comprises a lower percentage of carbon dioxide than the first
stream; providing at least a portion of the N.sub.2 in the second
stream to an ammonia synthesis process.
5071. The method of claim 5070, wherein the second stream comprises
H.sub.2 from the formation.
5072. The method of claim 5070, wherein the first stream is
produced from the coal formation.
5073. The method of claim 5072, wherein the first stream is
generated by reacting a oxidizing fluid with hydrocarbon material
in the formation.
5074. The method of claim 5070, wherein the second stream comprises
H.sub.2 from the formation and, further comprising providing such
H.sub.2 to the ammonia synthesis process.
5075. The method of claim 5070, further comprising using the
ammonia synthesis process to generate ammonia.
5076. The method of claim 5075, wherein fluids produced during
pyrolysis of a coal formation comprise ammonia and, further
comprising adding at least a portion of such ammonia to the ammonia
generated from the ammonia synthesis process.
5077. The method of claim 5075, wherein fluids produced during
pyrolysis of a coal formation are hydrotreated and at least some
ammonia is produced during hydrotreating, and further comprising
adding at least a portion of such ammonia to the ammonia generated
from the ammonia synthesis process.
5078. The method of claim 5075, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea.
5079. The method of claim 5075, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and, further comprising providing carbon dioxide from
the formation to the urea synthesis process.
5080. The method of claim 5075, further comprising providing at
least a portion of the ammonia to a urea synthesis process to
produce urea and further comprising shifting at least a portion of
carbon monoxide in the synthesis gas to carbon dioxide in a shift
process, and further comprising providing at least a portion of the
carbon dioxide from the shift process to the urea synthesis
process.
5081. A method for treating hydrocarbons in at least a portion of a
coal formation, wherein the portion has an average permeability of
less than about 10 millidarcy, comprising: providing heat from one
or more heat sources to the formation; allowing the heat to
transfer from the one or more heat sources to a selected section of
the formation such that heat from the heat sources pyrolyzes at
least some hydrocarbons within the selected section, and wherein
heat from the heat sources increases the permeability of at least a
portion of the selected section; and producing a mixture comprising
hydrocarbons from the formation.
5082. The method of claim 5081, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation, and wherein superposition of heat from at least the two
heat sources increases the permeability of at least the portion of
the selected section.
5083. The method of claim 5081, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected section to create thermal fractures in the formation
wherein the thermal fractures substantially increase the
permeability of the selected section.
5084. The method of claim 5081, wherein the heat is provided such
that an average temperature in the selected section ranges from
approximately about 270.degree. C. to about 400.degree. C.
5085. The method of claim 5081, wherein at least one of the one or
more heat sources comprises an electrical heater located in the
formation.
5086. The method of claim 5081, wherein at least one of the one or
more heat sources is located in a heater well, and wherein at least
one of the heater wells comprises a conduit located in the
formation, and further comprising heating the conduit by flowing a
hot fluid through the conduit.
5087. The method of claim 5081, wherein at least some of the heat
sources are arranged in a triangular pattern.
5088. The method of claim 5081, further comprising: monitoring a
composition of the produced mixture; and controlling a pressure in
at least a portion of the formation to control the composition of
the produced mixture.
5089. The method of claim 5088, wherein the pressure is controlled
by a valve proximate to a location where the mixture is
produced.
5090. The method of claim 5088, wherein the pressure is controlled
such that pressure proximate to the one or more heat sources is
greater than a pressure proximate to a location where the fluid is
produced.
5091. A method for treating hydrocarbons in at least a portion of a
coal formation, wherein the portion has an average permeability of
less than about 10 millidarcy, comprising: providing heat from one
or more heat sources to the formation; allowing the heat to
transfer from the one or more heat sources to a selected section of
the formation such that heat from the one or more heat sources
pyrolyzes at least some hydrocarbons within the selected section,
and wherein heat from the one or more heat sources vaporizes at
least a portion of the hydrocarbons in the selected section; and
producing a mixture comprising hydrocarbons from the formation.
5092. The method of claim 5091, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation, and wherein superposition of heat from at least the two
heat sources vaporizes at least the portion of the hydrocarbons in
the selected section.
5093. The method of claim 5091, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected section to create thermal fractures in the formation,
wherein the thermal fractures substantially increase the
permeability of the selected section.
5094. The method of claim 5091, wherein the heat is provided such
that an average temperature in the selected section ranges from
approximately about 270.degree. C. to about 400.degree. C.
5095. The method of claim 5091, wherein at least one of the one or
more heat sources comprises an electrical heater located in the
formation.
5096. The method of claim 5091, wherein at least one of the one or
more heat sources is located in a heater well, and wherein at least
one of the heater wells comprises a conduit located in the
formation, and further comprising heating the conduit by flowing a
hot fluid through the conduit.
5097. The method of claim 5091, wherein at least some of the heat
sources are arranged in a triangular pattern.
5098. The method of claim 5091, further comprising: monitoring a
composition of the produced mixture; and controlling a pressure in
at least a portion of the formation to control the composition of
the produced mixture.
5099. The method of claim 5098, wherein the pressure is controlled
by a valve proximate to a location where the mixture is
produced.
5100. The method of claim 5098, wherein the pressure is controlled
such that pressure proximate to the one or more heat sources is
greater than a pressure proximate to a location where the mixture
is produced.
5101. A method for treating hydrocarbons in at least a portion of a
coal formation, wherein the portion has an average permeability of
less than about 10 millidarcy, comprising: providing heat from one
or more heat sources to the formation, wherein at least one of the
one or more heat sources is located in a heater well; allowing the
heat to transfer from the one or more heat sources to a selected
section of the formation such that heat from the heat sources
pyrolyzes at least some hydrocarbons within the selected section,
and wherein heat from the heat sources pressurizes at least a
portion of the selected section; and producing a mixture comprising
hydrocarbons from the formation, wherein the mixture is produced
from one or more of the heater sources.
5102. The method of claim 5101, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from at least the two heat sources pyrolyzes
at least some hydrocarbons within the selected section of the
formation.
5103. The method of claim 5101, further comprising producing fluid
from at least one of the one or more heat sources.
5104. The method of claim 5101, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected section to create thermal fractures in the formation,
wherein the thermal fractures substantially increase the
permeability of the selected section.
5105. The method of claim 5101, wherein the heat is provided such
that an average temperature in the selected section ranges from
approximately about 270.degree. C. to about 400.degree. C.
5106. The method of claim 5101, wherein at least one of the one or
more heat sources comprises an electrical heater located in the
formation.
5107. The method of claim 5101, wherein at least one of the one or
more heat sources is located in a heater well, and wherein at least
one of the heater wells comprises a conduit located in the
formation, and further comprising heating the conduit by flowing a
hot fluid through the conduit.
5108. The method of claim 5101, wherein at least some of the heat
sources are arranged in a triangular pattern.
5109. The method of claim 5101, further comprising: monitoring a
composition of the produced mixture; and controlling a pressure in
at least a portion of the formation to control the composition of
the produced mixture.
5110. The method of claim 5109, wherein the pressure is controlled
by a valve proximate to a location where the mixture is
produced.
5111. The method of claim 5109, wherein the pressure is controlled
such that pressure proximate to the one or more heat sources is
greater than a pressure proximate to a location where the mixture
is produced. Low Heat Zone and Pyrolysis Zone
5112. A method for treating hydrocarbons in at least a portion of a
coal formation, wherein the portion has an average permeability of
less than about 10 millidarcy, comprising: providing heat from one
or more heat sources to the formation; allowing the heat to
transfer from the one or more heat sources to a selected first
section of the formation such that heat from the heat sources
creates a pyrolysis zone wherein at least some hydrocarbons are
pyrolyzed within the first selected section, and allowing the heat
to transfer from the one or more heat sources to a selected second
section of the formation such that heat from the heat sources heats
at least some hydrocarbons within the selected second section to a
temperature less than the average temperature within the pyrolysis
zone; and producing a mixture comprising hydrocarbons from the
formation.
5113. The method of claim 5112, wherein the one or more heat
sources comprise at least two heat sources, and wherein
superposition of heat from the at least two heat sources pyrolyzes
at least some hydrocarbons within the selected first section of the
formation, and wherein superposition of heat from the at least two
heat sources heats at least some hydrocarbons within the selected
second section to a temperature less than the average temperature
within the pyrolysis zone.
5114. The method of claim 5112, wherein at least some heated
hydrocarbons within the selected second section flow into the
pyrolysis zone.
5115. The method of claim 5112, wherein the heat decreases the
viscosity of at least some of the hydrocarbons in the selected
second section.
5116. The method of claim 5112, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected first section to create thermal fractures in the
formation, wherein the thermal fractures substantially increase the
permeability of the selected first section.
5117. The method of claim 5112, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected second section to create thermal fractures in the
formation, wherein the thermal fractures substantially increase the
permeability of the selected second section.
5118. The method of claim 5112, wherein the heat is provided such
that an average temperature in the selected first section ranges
from approximately about 270.degree. C. to about 400.degree.C.
5119. The method of claim 5112, wherein the heat is provided such
that an average temperature in the selected second section ranges
from approximately about 180.degree. C. to about 250.degree. C.
5120. The method of claim 5112, wherein a viscosity of at least
some of the hydrocarbons in the selected second section ranges from
approximately about 20 centipoise to about 1000 centipoise.
5121. The method of claim 5112, wherein at least one of the one or
more heat sources comprises an electrical heater located in the
formation.
5122. The method of claim 5112, wherein at least one of the one or
more heat sources is located in a heater well, and wherein at least
one of the heater wells comprises a conduit located in the
formation, and further comprising heating the conduit by flowing a
hot fluid through the conduit.
5123. The method of claim 5112, further comprising: monitoring a
composition of the produced mixture; and controlling a pressure in
at least a portion of the formation to control the composition of
the produced mixture.
5124. The method of claim 5123, wherein the pressure is controlled
by a valve proximate to a location where the mixture is
produced.
5125. The method of claim 5123, wherein the pressure is controlled
such that pressure proximate to the one or more heat sources is
greater than a pressure proximate to a location where the fluid is
produced.
5126. The method of claim 5122, wherein the pressure in the
selected second section is substantially greater than the pressure
in the selected first section.
5127. The method of claim 5112, wherein at least some of the heat
sources are arranged in a triangular pattern.
5128. The method of claim 5112, wherein an average distance between
heat sources in the selected first section is less than an average
distance between heat sources in the selected second section.
5129. The method of claim 5112, wherein the heat is provided to the
selected first section before heat is provided to the selected
second section.
5130. The method of claim 5112, wherein the selected first section
comprises at least one production well.
5131. The method of claim 5112, wherein the selected first section
comprises a planar region.
5132. The method of claim 5112, wherein at least one row of the
heat sources provides heat to the planar region.
5133. The method of claim 5112, wherein at least one ring
comprising the heat sources provides heat to the selected first
section.
5134. The method of claim 5133, wherein at least one ring
comprising the heat sources provides heat to the selected second
section.
5135. The method of claim 5133, wherein the ring comprises a
polygon.
5136. The method of claim 5133, wherein the ring comprises a
regular polygon.
5137. The method of claim 5133, wherein the ring comprises a
hexagon.
5138. The method of claim 5133, wherein the ring comprises a
triangle.
5139. A method for treating hydrocarbons in at least a portion of a
coal formation, wherein the portion has an average permeability of
less than about 10 millidarcy, comprising: providing heat from
three or more heat sources to the formation; allowing the heat to
transfer from three or more of the heat sources to a selected
section of the formation such that heat from the heat sources
pyrolyzes at least some hydrocarbons within the selected section,
and at least three of the heat sources are arranged in a
substantially triangular pattern; and producing a mixture
comprising hydrocarbons from the formation.
5140. The method of claim 5139, wherein superposition of heat from
at least the three heat sources pyrolyzes at least some
hydrocarbons within the selected section of the formation.
5141. The method of claim 5139, wherein the mixture is produced
from a production well located in a triangular region created by at
least three heat sources.
5142. The method of claim 5139, further comprising allowing heat to
transfer from at least one of the one or more heat sources to the
selected section to create thermal fractures in the formation,
wherein the thermal fractures substantially increase the
permeability of the selected section.
5143. The method of claim 5139, wherein the heat is provided such
that an average temperature in the selected section ranges from
approximately about 270.degree. C. to about 400.degree. C.
5144. The method of claim 5139, wherein at least one of the one or
more heat sources comprises a electrical heater located in the
formation.
5145. The method of claim 5139, wherein at least one of the one or
more heat sources is located in a heater well, and wherein at least
one of the heater wells comprises a conduit located in the
formation, and further comprising heating the conduit by flowing a
hot fluid through the conduit.
5146. The method of claim 5139, wherein at least some of the heat
sources are arranged in a triangular pattern.
5147. The method of claim 5139, further comprising: monitoring a
composition of the produced mixture; and controlling a pressure in
at least a portion of the formation to control the composition of
the produced mixture.
5148. The method of claim 5147, wherein the pressure is controlled
by a valve proximate to a location where the mixture is
produced.
5149. The method of claim 5147, wherein the pressure is controlled
such that pressure proximate to the one or more heat sources is
greater than a pressure proximate to a location where the fluid is
produced.
Description
PRIORITY CLAIM
[0001] This application claims priority to U.S. Provisional
Application No. 60/199,215 entitled "In Situ Energy Recovery,"
filed Apr. 24, 2000, U.S. Provisional Application No. 60/199,214
entitled "In Situ Energy Recovery From Coal," filed Apr. 24, 2000,
and U.S. Provisional Application No. 60/199, 213 entitled
"Emissionless Energy Recovery From Coal," filed Apr. 24, 2000. The
above-referenced provisional applications are hereby incorporated
by reference as if fully set forth herein.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates generally to methods and
systems for production of hydrocarbons, hydrogen, and/or other
products from coal formations. Certain embodiments relate to in
situ conversion of hydrocarbons to produce hydrocarbons, hydrogen,
and/or novel product streams from underground coal formations.
[0004] 2. Description of Related Art
[0005] Hydrocarbons obtained from subterranean (e.g., sedimentary)
formations are often used as energy resources, as feedstocks, and
as consumer products. Concerns over depletion of available
hydrocarbon resources have led to development of processes for more
efficient recovery, processing and/or use of available hydrocarbon
resources, for example coal. In situ processes for coal formations
may be used to remove hydrocarbon materials from subterranean
formations. Chemical and/or physical properties of coal within a
subterranean formation may need to be changed to allow coal to be
more easily removed from the subterranean formation. The chemical
and physical changes may include in situ reactions that produce
removable fluids, composition changes, solubility changes, phase
changes, and/or viscosity changes of the hydrocarbon material
within the formation. A fluid may be, but is not limited to, a gas,
a liquid, an emulsion, a slurry and/or a stream of solid particles
that has flow characteristics similar to liquid flow.
[0006] Examples of in situ processes utilizing downhole heaters are
illustrated in U.S. Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No.
2,732,195 to Ljungstrom, U.S. Pat. No. 2,780,450 to Ljungstrom,
U.S. Pat. No. 2,789,805 to Ljungstrom, U.S. Pat. No. 2,923,535
issued to Ljungstrom, and U.S. Pat. No. 4,886,118 to Van Meurs et
al., each of which is incorporated by reference as if fully set
forth herein.
[0007] A heat source may be used to heat a subterranean formation.
Electrical heaters may be used to heat the subterranean formation
by radiation and/or conduction. An electrical heater may
resistively heat an element. U.S. Pat. No. 2,548,360 to Germain,
which is incorporated by reference as if fully set forth herein,
describes an electrical heating element placed within a viscous oil
within a wellbore. The heater element heats and thins the oil to
allow the oil to be pumped from the wellbore. U.S. Pat. No.
4,716,960 to Eastlund et al., which is incorporated by reference as
if fully set forth herein, describes electrically heating tubing of
a petroleum well by passing a relatively low voltage current
through the tubing to prevent formation of solids. U.S. Pat. No.
5,065,818 to Van Egmond, which is incorporated by reference as if
fully set forth herein, describes an electrical heating element
that is cemented into a well borehole without a casing surrounding
the heating element.
[0008] U.S. Pat. No. 6,023,554 to Vinegar et al., which is
incorporated by reference as if fully set forth herein, describes
an electrical heating element that is positioned within a casing.
The heating element generates radiant energy that heats the casing.
A granular solid fill material may be placed between the casing and
the formation. The casing may conductively heat the fill material,
which in turn conductively heats the formation. U.S. Pat. No.
4,570,715 to Van Meurs et al., which is incorporated by reference
as if fully set forth herein, describes an electrical heating
element. The heating element has an electrically conductive core, a
surrounding layer of insulating material, and a surrounding
metallic sheath. The conductive core may have a relatively low
resistance at high temperatures. The insulating material may have
electrical resistance, compressive strength and heat conductivity
properties that are relatively high at high temperatures. The
insulating layer may inhibit arcing from the core to the metallic
sheath. The metallic sheath may have tensile strength and creep
resistance properties that are relatively high at high
temperatures.
[0009] U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated
by reference as if fully set forth herein, describes an electrical
heating element having a copper-nickel alloy core.
[0010] Combustion of a fuel may be used to heat a formation.
Combusting a fuel to heat a formation may be more economical than
using electricity to heat a formation. Several different types of
heaters may use fuel combustion as a heat source that heats a
formation. The combustion may take place in the formation, in a
well and/or near the surface. Combustion in the formation may be a
fireflood. An oxidizer may be pumped into the formation. The
oxidizer may be ignited to advance a fire front towards a
production well. Oxidizer pumped into the formation may flow
through the formation along fracture lines in the formation.
Ignition of the oxidizer may not result in the fire front flowing
uniformly through the formation.
[0011] A flameless combustor may be used to combust a fuel within a
well. U.S. Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 to
Vinegar et al., U.S. Pat. No. 5,862,858 to Wellington et al., and
U.S. Pat. No. 5,899,269 to Wellington et al., which are
incorporated by reference as if fully set forth herein, describe
flameless combustors. Flameless combustion may be accomplished by
preheating a fuel and combustion air to a temperature above an
auto-ignition temperature of the mixture. The fuel and combustion
air may be mixed in a heating zone to combust. In the heating zone
of the Blameless combustor, a catalytic surface may be provided to
lower the auto-ignition temperature of the fuel and air
mixture.
[0012] Heat may be supplied to a formation from a surface heater.
The surface heater may produce combustion gases that are circulated
through wellbores to heat the formation. Alternately, a surface
burner may be used to heat a heat transfer fluid that is passed
through a wellbore to heat the formation. Examples of fired
heaters, or surface burners that may be used to heat a subterranean
formation, are illustrated in U.S. Pat. No. 6,056,057 to Vinegar et
al. and U.S. Pat. No. 6,079,499 to Mikus et al., which are both
incorporated by reference as if fully set forth herein.
[0013] Coal is often mined and used as a fuel within an electricity
generating power plant. Most coal that is used as a fuel to
generate electricity is mined. A significant number of coal
formations are, however, not suitable for economical mining. For
example, mining coal from steeply dipping coal seams, from
relatively thin coal seams (e.g., less than about 1 meter thick),
and/or from deep coal seams may not be economically feasible. Deep
coal seams include coal seams that are at, or extend to, depths of
greater than about 3000 feet (about 914 m) below surface level. The
energy conversion efficiency of burning coal to generate
electricity is relatively low, as compared to fuels such as natural
gas. Also, burning coal to generate electricity often generates
significant amounts of carbon dioxide, oxides of sulfur, and oxides
of nitrogen that are released into the atmosphere.
[0014] Synthesis gas may be produced in reactors or in situ within
a subterranean formation. Synthesis gas may be produced within a
reactor by partially oxidizing methane with oxygen. In situ
production of synthesis gas may be economically desirable to avoid
the expense of building, operating, and maintaining a surface
synthesis gas production facility. U.S. Pat. No. 4,250,230 to
Terry, which is incorporated by reference as if fully set forth
herein, describes a system for in situ gasification of coal. A
subterranean coal seam is burned from a first well towards a
production well. Methane, hydrocarbons, H.sub.2, CO, and other
fluids may be removed from the formation through the production
well. The H.sub.2 and CO may be separated from the remaining fluid.
The H.sub.2 and CO may be sent to fuel cells to generate
electricity.
[0015] U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by
reference as if fully set forth herein, discloses a process for
producing synthesis gas. A portion of a rubble pile is burned to
heat the rubble pile to a temperature that generates liquid and
gaseous hydrocarbons by pyrolysis. After pyrolysis, the rubble is
further heated, and steam or steam and air are introduced to the
rubble pile to generate synthesis gas.
[0016] U.S. Pat. No. 5,554,453 to Steinfeld et al., which is
incorporated by reference as if fully set forth herein, describes
an ex situ coal gasifier that supplies fuel gas to a fuel cell. The
fuel cell produces electricity. A catalytic burner is used to bum
exhaust gas from the fuel cell with an oxidant gas to generate heat
in the gasifier.
[0017] Carbon dioxide may be produced from combustion of fuel and
from many chemical processes. Carbon dioxide may be used for
various purposes, such as, but not limited to, a feed stream for a
dry ice production facility, supercritical fluid in a low
temperature supercritical fluid process, a flooding agent for coal
bed demethanation, and a flooding agent for enhanced oil recovery.
Although some carbon dioxide is productively used, many tons of
carbon dioxide are vented to the atmosphere.
[0018] As outlined above, there has been a significant amount of
effort to develop methods and systems to economically produce
hydrocarbons, hydrogen, and/or other products from coal formations.
At present, however, there are still many coal formations from
which hydrocarbons, hydrogen, and/or other products cannot be
economically produced. Thus, there is still a need for improved
methods and systems for production of hydrocarbons, hydrogen,
and/or other products from various coal formations.
SUMMARY OF TH INVENTION
[0019] In an embodiment, hydrocarbons within a coal formation may
be converted in situ within the formation to yield a mixture of
relatively high quality hydrocarbon products, hydrogen, and other
products. One or more heat sources may be used to heat a portion of
the coal formation to temperatures that allow pyrolysis of the
hydrocarbons. Hydrocarbons, hydrogen, and other formation fluids
may be removed from the formation through one or more production
wells. The formation fluids may be removed in a vapor phase.
Temperature and pressure in at least a portion of the formation may
be controlled during pyrolysis to yield improved products from the
formation.
[0020] A heated formation may also be used to produce synthesis
gas. In certain embodiments synthesis gas is produced after
production of pyrolysis fluids.
[0021] A formation may be heated to a temperature greater than
400.degree. C. prior to contacting a synthesis gas generating fluid
with the formation. Contacting a synthesis gas generating fluid,
such as water, steam, and/or carbon dioxide, with carbon and/or
hydrocarbons within the formation results in generation of
synthesis gas if the temperature of the carbon is sufficiently
high. Synthesis gas generation is, in some embodiments, an
endothermic process. Additional heat may be added to the formation
during synthesis gas generation to maintain a high temperature
within the formation. The heat may be added from heater wells
and/or from oxidizing carbon and/or hydrocarbons within the
formation. The generated synthesis gas may be removed from the
formation through one or more production wells.
[0022] After production of pyrolysis fluids and/or synthesis gas,
fluid may be sequestered within the formation. To store a
significant amount of fluid within the formation, a temperature of
the formation will often need to be less than about 100.degree. C.
Water may be introduced into at least a portion of the formation to
generate steam and reduce a temperature of the formation. The steam
may be removed from the formation. The steam may be utilized for
various purposes, including, but not limited to, heating another
portion of the formation, generating synthesis gas in an adjacent
portion of the formation, generating electricity, and/or as a steam
flood in a oil reservoir. After the formation is cooled, fluid
(e.g., carbon dioxide) may be pressurized and sequestered in the
formation. Sequestering fluid within the formation may result in a
significant reduction or elimination of fluid that is released to
the environment due to operation of the in situ conversion
process.
[0023] In an embodiment, one or more heat sources may be installed
into a formation to heat the formation. Heat sources may be
installed by drilling openings (well bores) into the formation. In
some embodiments openings may be formed in the formation using a
drill with a steerable motor and an accelerometer. Alternatively,
an opening may be formed into the formation by geosteered drilling.
Alternately, an opening may be formed into the formation by sonic
drilling.
[0024] One or more heat sources may be disposed within the opening
such that the heat source may be configured to transfer heat to the
formation. For example, a heat source may be placed in an open
wellbore in the formation. In this manner, heat may conductively
and radiatively transfer from the heat source to the formation.
Alternatively, a heat source may be placed within a heater well
that may be packed with gravel, sand, and/or cement. The cement may
be a refractory cement.
[0025] In some embodiments one or more heat sources may be placed
in a pattern within the formation. For example, in one embodiment,
an in situ conversion process for coal may include heating at least
a portion of a coal formation with an array of heat sources
disposed within the formation. In some embodiments, the array of
heat sources can be positioned substantially equidistant from a
production well. Certain patterns (e.g., triangular arrays,
hexagonal arrays, or other array patterns) may be more desirable
for specific applications. In addition, the array of heat sources
may be disposed such that a distance between each heat source may
be less than about 70 feet (21 m). In addition, the in situ
conversion process for hydrocarbons may include heating at least a
portion of the formation with heat sources disposed substantially
parallel to a boundary of the hydrocarbons. Regardless of the
arrangement of or distance between the heat sources, in certain
embodiments, a ratio of heat sources to production wells disposed
within a formation may be greater than about 5, 8, 10, 20, or
more.
[0026] Certain embodiments may also include allowing heat to
transfer from one or more of the heat sources to a selected section
of the heated portion. In an embodiment, the selected section may
be disposed between one or more heat sources. For example, the in
situ conversion process may also include allowing heat to transfer
from one or more heat sources to a selected section of the
formation such that heat from one or more of the heat sources
pyrolyzes at least some hydrocarbons within the selected section.
In this manner, the in situ conversion process may include heating
at least a portion of a coal formation above a pyrolyzation
temperature of hydrocarbons in the formation. For example, a
pyrolyzation temperature may include a temperature of at least
about 270.degree. C. Heat may be allowed to transfer from one or
more of the heat sources to the selected section substantially by
conduction.
[0027] One or more heat sources may be located within the formation
such that superposition of heat produced from one or more heat
sources may occur. Superposition of heat may increase a temperature
of the selected section to a temperature sufficient for pyrolysis
of at least some of the hydrocarbons within the selected section.
Superposition of heat may vary depending on, for example, a spacing
between heat sources. The spacing between heat sources may be
selected to optimize heating of the section selected for treatment.
Therefore, hydrocarbons may be pyrolyzed within a larger area of
the portion. In this manner, spacing between heat sources may be
selected to increase the effectiveness of the heat sources, thereby
increasing the economic viability of a selected in situ conversion
process for hydrocarbons. Superposition of heat tends to increase
the uniformity of heat distribution in the section of the formation
selected for treatment.
[0028] Various systems and methods may be used to provide heat
sources. In an embodiment, a natural distributed combustor system
and method may be configured to heat at least a portion of a coal
formation. The system and method may first include heating a first
portion of the formation to a temperature sufficient to support
oxidation of at least some of the hydrocarbons therein. One or more
conduits may be disposed within one or more openings. One or more
of the conduits may be configured to provide an oxidizing fluid
from an oxidizing fluid source into an opening in the formation.
The oxidizing fluid may oxidize at least a portion of the
hydrocarbons at a reaction zone within the formation. Oxidation may
generate heat at the reaction zone. The generated heat may transfer
from the reaction zone to a pyrolysis zone in the formation. The
heat may transfer by conduction, radiation, and/or convection. In
this manner, a heated portion of the formation may include the
reaction zone and the pyrolysis zone. The heated portion may also
be located substantially adjacent to the opening. One or more of
the conduits may also be configured to remove one or more oxidation
products from the reaction zone and/or formation. Alternatively,
additional conduits may be configured to remove one or more
oxidation products from the reaction zone and/or formation.
[0029] In an embodiment, a system and method configured to heat a
coal formation may include one or more insulated conductors
disposed in one or more openings in the formation. The openings may
be uncased. Alternatively, the openings may include a casing. As
such, the insulated conductors may provide conductive, radiant, or
convective heat to at least a portion of the formation. In
addition, the system and method may be configured to allow heat to
transfer from the insulated conductor to a section of the
formation. In some embodiments, the insulated conductor may include
a copper-nickel alloy. In some embodiments, the insulated conductor
may be electrically coupled to two additional insulated conductors
in a 3-phase Y configuration.
[0030] In an embodiment, a system and method may include one or
more elongated members disposed in an opening in the formation.
Each of the elongated members may be configured to provide heat to
at least a portion of the formation. One or more conduits may be
disposed in the opening. One or more of the conduits may be
configured to provide an oxidizing fluid from an oxidizing fluid
source into the opening. In certain embodiments, the oxidizing
fluid may be configured to substantially inhibit carbon deposition
on or proximate to the elongated member.
[0031] In an embodiment, a system and method for heating a coal
formation may include oxidizing a fuel fluid in a heater. The
method may further include providing at least a portion of the
oxidized fuel fluid into a conduit disposed in an opening in the
formation. In addition, additional heat may be transferred from an
electric heater disposed in the opening to the section of the
formation. Heat may be allowed to transfer substantially uniformly
along a length of the opening.
[0032] Energy input costs may be reduced in some embodiments of
systems and methods described above. For example, an energy input
cost may be reduced by heating a portion of a coal formation by
oxidation in combination with heating the portion of the formation
by an electric heater. The electric heater may be turned down
and/or off when the oxidation reaction begins to provide sufficient
heat to the formation. In this manner, electrical energy costs
associated with heating at least a portion of a formation with an
electric heater may be reduced. Thus, a more economical process may
be provided for heating a coal formation in comparison to heating
by a conventional method. In addition, the oxidation reaction may
be propagated slowly through a greater portion of the formation
such that fewer heat sources may be required to heat such a greater
portion in comparison to heating by a conventional method.
[0033] Certain embodiments as described herein may provide a lower
cost system and method for heating a coal formation. For example,
certain embodiments may provide substantially uniform heat transfer
along a length of a heater. Such a length of a heater may be
greater than about 300 m or possibly greater than about 600 m. In
addition, in certain embodiments, heat may be provided to the
formation more efficiently by radiation. Furthermore, certain
embodiments of systems as described herein may have a substantially
longer lifetime than presently available systems.
[0034] In an embodiment, an in situ conversion system and method
for hydrocarbons may include maintaining a portion of the formation
in a substantially unheated condition. In this manner, the portion
may provide structural strength to the formation and/or
confinement/isolation to certain regions of the formation. A
processed coal formation may have alternating heated and
substantially unheated portions arranged in a pattern that may, in
some embodiments, resemble a checkerboard pattern, or a pattern of
alternating areas (e.g., strips) of heated and unheated
portions.
[0035] In an embodiment, a heat source may advantageously heat only
along a selected portion or selected portions of a length of the
heater. For example, a formation may include several coal layers.
One or more of the coal layers may be separated by layers
containing little and/or no coal. A heat source may include several
discrete high heating zones that may be separated by low heating
zones. The high heating zones may be disposed proximate coal layers
such that the layers may be heated. The low heating zones may be
disposed proximate to layers containing little or no hydrocarbons
such that the layers may not be substantially heated. For example,
an electrical heater may include one or more low resistance heater
sections and one or more high resistance heater sections. In this
manner, low resistance heater sections of the electrical heater may
be disposed in and/or proximate to layers containing little or no
hydrocarbons. In addition, high resistance heater sections of the
electrical heater may be disposed proximate coal layers. In an
additional example, a fueled heater (e.g., surface burner) may
include insulated sections. In this manner, insulated sections of
the fueled heater may be placed proximate to or adjacent to layers
containing little or no hydrocarbons. Alternately, a heater with
distributed air and/or fuel may be configured such that little
and/or no fuel may be combusted proximate to or adjacent to layers
containing little or no hydrocarbons. Such a fueled heater may
include flameless combustors and natural distributed
combustors.
[0036] In an embodiment, a heating rate of the formation may be
slowly raised through the pyrolysis temperature range. For example,
an in situ conversion process for coal may include heating at least
a portion of a coal formation to raise an average temperature of
the portion above about 270.degree. C. by a rate less than a
selected amount (e.g., about 10.degree. C., 5.degree. C., 3.degree.
C., 1.degree. C., 0.5.degree. C., or 0.1.degree. C.) per day. In a
further embodiment, the portion may be heated such that an average
temperature of the selected section may be less than about
375.degree. C. or, in some embodiments, less than about 400.degree.
C.
[0037] In an embodiment, a temperature of the portion may be
monitored through a test well disposed in a formation. For example,
the test well may be positioned in a formation between a first heat
source and a second heat source. Certain systems and methods may
include controlling the heat from the first heat source and/or the
second heat source to raise the monitored temperature at the test
well at a rate of less than about a selected amount per day. In
addition or alternatively, a temperature of the portion may be
monitored at a production well. In this manner, an in situ
conversion process for coal may include controlling the heat from
the first heat source and/or the second heat source to raise the
monitored temperature at the production well at a rate of less than
a selected amount per day.
[0038] Certain embodiments may include heating a selected volume of
a coal formation. Heat may be provided to the selected volume by
providing power to one or more heat sources. Power may be defined
as heating energy per day provided to the selected volume. A power
(Pwr) required to generate a heating rate (h, in units of, for
example, .degree. C./day) in a selected volume (V) of a coal
formation may be determined by the following equation:
Pwr=h*V*C.sub.v*.rho..sub.B. In this equation, an average heat
capacity of the formation (C.sub.v) and an average bulk density of
the formation (.rho..sub.B) may be estimated or determined using
one or more samples taken from the coal formation.
[0039] Certain embodiments may include raising and maintaining a
pressure in a coal formation. Pressure may be, for example,
controlled within a range of about 2 bars absolute to about 20 bars
absolute. For example, the process may include controlling a
pressure within a majority of a selected section of a heated
portion of the formation. The controlled pressure may be above
about 2 bars absolute during pyrolysis. In an alternate embodiment,
an in situ conversion process for coal may include raising and
maintaining the pressure in the formation within a range of about
20 bars absolute to about 36 bars absolute.
[0040] In an embodiment, compositions and properties of formation
fluids produced by an in situ conversion process for coal may vary
depending on, for example, conditions within a coal formation.
[0041] Certain embodiments may include controlling the heat
provided to at least a portion of the formation such that
production of less desirable products in the portion may be
substantially inhibited. Controlling the heat provided to at least
a portion of the formation may also increase the uniformity of
permeability within the formation. For example, controlling the
heating of the formation to inhibit production of less desirable
products may, in some embodiments, include controlling the heating
rate to less than a selected amount (e.g., 10.degree. C., 5.degree.
C., 3.degree. C., 1.degree. C., 0.5.degree. C., or 0.1.degree. C.)
per day.
[0042] Controlling pressure, heat and/or heating rates of a
selected section in a formation may increase production of selected
formation fluids. For example, the amount and/or rate of heating
may be controlled to produce formation fluids having an American
Petroleum Institute ("API") gravity greater than about 25. Heat
and/or pressure may be controlled to inhibit production of olefins
in the produced fluids.
[0043] Controlling formation conditions to control the pressure of
hydrogen in the produced fluid may result in improved qualities of
the produced fluids. In some embodiments it may be desirable to
control formation conditions so that the partial pressure of
hydrogen in a produced fluid is greater than about 0.5 bar
absolute, as measured at a production well.
[0044] In an embodiment, operating conditions may be determined by
measuring at least one property of the formation. At least the
measured properties may be input into a computer executable
program. At least one property of formation fluids selected to be
produced from the formation may also be input into the computer
executable program. The program may be operable to determine a set
of operating conditions from at least the one or more measured
properties. The program may also be configured to determine the set
of operating conditions from at least one property of the selected
formation fluids. In this manner, the determined set of operating
conditions may be configured to increase production of selected
formation fluids from the formation.
[0045] Certain embodiments may include altering a composition of
formation fluids produced from a coal formation by altering a
location of a production well with respect to a heater well. For
example, a production well may be located with respect to a heater
well such that a non-condensable gas fraction of produced
hydrocarbon fluids may be larger than a condensable gas fraction of
the produced hydrocarbon fluids.
[0046] Condensable hydrocarbons produced from the formation will
typically include paraffins, cycloalkanes, mono-aromatics, and
di-aromatics as major components. Such condensable hydrocarbons may
also include other components such as tri-aromatics, etc.
[0047] In certain embodiments, a majority of the hydrocarbons in
produced fluid may have a carbon number of less than approximately
25. Alternatively, less than about 15 weight % of the hydrocarbons
in the fluid may have a carbon number greater than approximately
25. In other embodiments fluid produced may have a weight ratio of
hydrocarbons having carbon numbers from 2 through 4, to methane, of
greater than approximately 0.3. The non-condensable hydrocarbons
may include, but is not limited to, hydrocarbons having carbon
numbers less than 5.
[0048] In certain embodiments, the API gravity of the hydrocarbons
in produced fluid may be approximately 20 or above (e.g., 25, 30,
35, 40, 50, etc.). In certain embodiments, the hydrogen to carbon
atomic ratio in produced fluid may be at least approximately 1.7
(e.g., 1.8, 1.9, etc.).
[0049] In certain embodiments, fluid produced from a formation may
include oxygenated hydrocarbons. In an example, the condensable
hydrocarbons may include an amount of oxygenated hydrocarbons
greater than about 5% by weight of the condensable
hydrocarbons.
[0050] Condensable hydrocarbons of a produced fluid may also
include olefins. For example, the olefin content of the condensable
hydrocarbons may be from about 0.1% by weight to about 15% by
weight. Alternatively, the olefin content of the condensable
hydrocarbons may be from about 0.1% by weight to about 2.5% by
weight or, in some embodiments less than about 5% by weight.
[0051] Non-condensable hydrocarbons of a produced fluid may also
include olefins. For example, the olefin content of the
non-condensable hydrocarbons may be gauged using the ethene/ethane
molar ratio. In certain embodiments the ethene/ethane molar ratio
may range from about 0.001 to about 0.15.
[0052] Fluid produced from the formation may include aromatic
compounds. For example, the condensable hydrocarbons may include an
amount of aromatic compounds greater than about 20% or about 25% by
weight of the condensable hydrocarbons. The condensable
hydrocarbons may also include relatively low amounts of compounds
with more than two rings in them (e.g., tri-aromatics or above).
For example, the condensable hydrocarbons may include less than
about 1%, 2%, or about 5% by weight of tri-aromatics or above in
the condensable hydrocarbons.
[0053] In particular, in certain embodiments asphaltenes (i.e.,
large multi-ring aromatics that are substantially insoluble in
hydrocarbons) make up less than about 0.1% by weight of the
condensable hydrocarbons. For example, the condensable hydrocarbons
may include an asphaltene component of from about 0.0% by weight to
about 0.1% by weight or, in some embodiments, less than about 0.3%
by weight.
[0054] Condensable hydrocarbons of a produced fluid may also
include relatively large amounts of cycloalkanes. For example, the
condensable hydrocarbons may include a cycloalkane component of up
to 30% by weight (e.g., from about 5% by weight to about 30% by
weight) of the condensable hydrocarbons.
[0055] In certain embodiments, the condensable hydrocarbons of the
fluid produced from a formation may include compounds containing
nitrogen. For example, less than about 1% by weight (when
calculated on an elemental basis) of the condensable hydrocarbons
is nitrogen (e.g., typically the nitrogen is in nitrogen containing
compounds such as pyridines, amines, amides, etc.).
[0056] In certain embodiments, the condensable hydrocarbons of the
fluid produced from a formation may include compounds containing
oxygen. In certain embodiments between about 5% and about 30% by
weight of the condensable hydrocarbons are typically oxygen
containing compounds such as phenols, substituted phenols, ketones,
etc. In some instances certain compounds containing oxygen (e.g.,
phenols) may be valuable and, as such, may be economically
separated from the produced fluid.
[0057] In certain embodiments, the condensable hydrocarbons of the
fluid produced from a formation may include compounds containing
sulfur. For example, less than about 1% by weight (when calculated
on an elemental basis) of the condensable hydrocarbons is sulfur
(e.g., typically the sulfur is in sulfur containing compounds such
as thiophenes, mercaptans, etc.).
[0058] Furthermore, the fluid produced from the formation may
include ammonia (typically the ammonia condenses with the water, if
any, produced from the formation). For example, the fluid produced
from the formation may in certain embodiments include about 0.05%
or more by weight of ammonia. Certain formations may produce larger
amounts of ammonia (e.g., up to about 10% by weight of the total
fluid produced may be ammonia).
[0059] Furthermore, a produced fluid from the formation may also
include molecular hydrogen (H.sub.2), water, carbon dioxide,
hydrogen sulfide, etc. For example, the fluid may include a H.sub.2
content between about 10% to about 80% by volume of the
non-condensable hydrocarbons.
[0060] Certain embodiments may include heating to yield at least
about 15% by weight of a total organic carbon content of at least
some of the coal formation into formation fluids.
[0061] In an embodiment, an in situ conversion process for treating
a coal formation may include providing heat to a section of the
formation to yield greater than about 60% by weight of the
potential hydrocarbon products and hydrogen, as measured by the
Fischer Assay.
[0062] In certain embodiments, heating of the selected section of
the formation may be controlled to pyrolyze at least about 20% by
weight (or in some embodiments about 25% by weight) of the
hydrocarbons within the selected section of the formation.
[0063] Certain embodiments may include providing a reducing agent
to at least a portion of the formation. A reducing agent provided
to a portion of the formation during heating may increase
production of selected formation fluids. A reducing agent may
include, but is not limited to, molecular hydrogen. For example,
pyrolyzing at least some hydrocarbons in a coal formation may
include forming hydrocarbon fragments. Such hydrocarbon fragments
may react with each other and other compounds present in the
formation. Reaction of these hydrocarbon fragments may increase
production of olefin and aromatic compounds from the formation.
Therefore, a reducing agent provided to the formation may react
with hydrocarbon fragments to form selected products and/or inhibit
the production of non-selected products.
[0064] In an embodiment, a hydrogenation reaction between a
reducing agent provided to a coal formation and at least some of
the hydrocarbons within the formation may generate heat. The
generated heat may be allowed to transfer such that at least a
portion of the formation may be heated. A reducing agent such as
molecular hydrogen may also be autogenously generated within a
portion of a coal formation during an in situ conversion process
for coal. In this manner, the autogenously generated molecular
hydrogen may hydrogenate formation fluids within the formation.
Allowing formation waters to contact hot carbon in the spent
formation may generate molecular hydrogen. Cracking an injected
hydrocarbon fluid may also generate molecular hydrogen.
[0065] Certain embodiments may also include providing a fluid
produced in a first portion of a coal formation to a second portion
of the formation. In this manner, a fluid produced in a first
portion of a coal formation may be used to produce a reducing
environment in a second portion of the formation. For example,
molecular hydrogen generated in a first portion of a formation may
be provided to a second portion of the formation. Alternatively, at
least a portion of formation fluids produced from a first portion
of the formation may be provided to a second portion of the
formation to provide a reducing environment within the second
portion. The second portion of the formation may be treated
according to any of the embodiments described herein.
[0066] Certain embodiments may include controlling heat provided to
at least a portion of the formation such that a thermal
conductivity of the portion may be increased to greater than about
0.5 W/(m.degree. C.) or, in some embodiments, greater than about
0.6 W/(m.degree. C.).
[0067] In certain embodiments a mass of at least a portion of the
formation may be reduced due, for example, to the production of
formation fluids from the formation. As such, a permeability and
porosity of at least a portion of the formation may increase. In
addition, removing water during the heating may also increase the
permeability and porosity of at least a portion of the
formation.
[0068] Certain embodiments may include increasing a permeability of
at least a portion of a coal formation to greater than about 0.01,
0.1, 1, 10, 20 and/or 50 Darcy. In addition, certain embodiments
may include substantially uniformly increasing a permeability of at
least a portion of a coal formation. Some embodiments may include
increasing a porosity of at least a portion of a coal formation
substantially uniformly.
[0069] In certain embodiments, after pyrolysis of a portion of a
formation, synthesis gas may be produced from carbon and/or
hydrocarbons remaining within the formation. Pyrolysis of the
portion may produce a relatively high, substantially uniform
permeability throughout the portion. Such a relatively high,
substantially uniform permeability may allow generation of
synthesis gas from a significant portion of the formation at
relatively low pressures. The portion may also have a large surface
area and/or surface area/volume. The large surface area may allow
synthesis gas producing reactions to be substantially at
equilibrium conditions during synthesis gas generation. The
relatively high, substantially uniform permeability may result in a
relatively high recovery efficiency of synthesis gas, as compared
to synthesis gas generation in a coal formation that has not been
so treated.
[0070] Synthesis gas may be produced from the formation prior to or
subsequent to producing a formation fluid from the formation. For
example, synthesis gas generation may be commenced before and/or
after formation fluid production decreases to an uneconomical
level. In this manner, heat provided to pyrolyze hydrocarbons
within the formation may also be used to generate synthesis gas.
For example, if a portion of the formation is at a temperature from
approximately 270.degree. C. to approximately 375.degree. C. (or
400.degree. C. in some embodiments) after pyrolyzation, then less
additional heat is generally required to heat such portion to a
temperature sufficient to support synthesis gas generation.
[0071] Pyrolysis of at least some hydrocarbons may in some
embodiments convert about 15% by weight or more of the carbon
initially available. Synthesis gas generation may convert
approximately up to an additional 80% by weight or more of carbon
initially available within the portion. In this manner, in situ
production of synthesis gas from a coal formation may allow
conversion of larger amounts of carbon initially available within
the portion. The amount of conversion achieved may, in some
embodiments, be limited by subsidence concerns.
[0072] Certain embodiments may include providing heat from one or
more heat sources to heat the formation to a temperature sufficient
to allow synthesis gas generation (e.g., in a range of
approximately 400.degree. C. to approximately 1200.degree. C. or
higher). At a lower end of the temperature range, generated
synthesis gas may have a high hydrogen (H.sub.2) to carbon monoxide
(CO) ratio. At an upper end of the temperature range, generated
synthesis gas may include mostly H.sub.2 and CO in lower ratios
(e.g., approximately a 1:1 ratio).
[0073] Heat sources for synthesis gas production may include any of
the heat sources as described in any of the embodiments set forth
herein. Alternatively, heating may include transferring heat from a
heat transfer fluid (e.g., steam or combustion products from a
burner) flowing within a plurality of wellbores within the
formation.
[0074] A synthesis gas generating fluid (e.g., liquid water, steam,
carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof)
may be provided to the formation. For example, the synthesis gas
generating fluid mixture may include steam and oxygen. In an
embodiment, a synthesis gas generating fluid may include aqueous
fluid produced by pyrolysis of at least some hydrocarbons within
one or more other portions of the formation. Providing the
synthesis gas generating fluid may alternatively include raising a
water table of the formation to allow water to flow into it.
Synthesis gas generating fluid may also be provided through at
least one injection wellbore. The synthesis gas generating fluid
will generally react with carbon in the formation to form H.sub.2,
water, methane, CO.sub.2, and/or CO. A portion of the carbon
dioxide may react with carbon in the formation to generate carbon
monoxide. Hydrocarbons such as ethane may be added to a synthesis
gas generating fluid. When introduced into the formation, the
hydrocarbons may crack to form hydrogen and/or methane. The
presence of methane in produced synthesis gas may increase the
heating value of the produced synthesis gas.
[0075] Synthesis gas generating reactions are typically endothermic
reactions. In an embodiment, an oxidant may be added to a synthesis
gas generating fluid. The oxidant may include, but is not limited
to, air, oxygen enriched air, oxygen, hydrogen peroxide, other
oxidizing fluids, or combinations thereof. The oxidant may react
with carbon within the formation to exothermically generate heat.
Reaction of an oxidant with carbon in the formation may result in
production of CO.sub.2 and/or CO. Introduction of an oxidant to
react with carbon in the formation may economically allow raising
the formation temperature high enough to result in generation of
significant quantities of H.sub.2 and CO from hydrocarbons within
the formation.
[0076] Synthesis gas generation may be via a batch process or a
continuous process, as is further described herein.
[0077] Synthesis gas may be produced from one or more producer
wells that include one or more heat sources. Such heat sources may
operate to promote production of the synthesis gas with a desired
composition.
[0078] Certain embodiments may include monitoring a composition of
the produced synthesis gas, and then controlling heating and/or
controlling input of the synthesis gas generating fluid to maintain
the composition of the produced synthesis gas within a desired
range. For example, in some embodiments (e.g., such as when the
synthesis gas will be used as a feedstock for a Fischer-Tropsch
process) a desired composition of the produced synthesis gas may
have a ratio of hydrogen to carbon monoxide of about 1.8:1 to 2.2:1
(e.g., about 2:1 or about 2.1:1). In some embodiments (such as when
the synthesis gas will be used as a feedstock to make methanol)
such ratio may be about 3:1 (e.g., about 2.8:1 to 3.2:1).
[0079] Certain embodiments may include blending a first synthesis
gas with a second synthesis gas to produce synthesis gas of a
desired composition. The first and the second synthesis gases may
be produced from different portions of the formation.
[0080] Synthesis gases described herein may be converted to heavier
condensable hydrocarbons. For example, a Fischer-Tropsch
hydrocarbon synthesis process may be configured to convert
synthesis gas to branched and unbranched paraffins. Paraffins
produced from the Fischer-Tropsch process may be used to produce
other products such as diesel, jet fuel, and naphtha products. The
produced synthesis gas may also be used in a catalytic methanation
process to produce methane. Alternatively, the produced synthesis
gas may be used for production of methanol, gasoline and diesel
fuel, ammonia, and middle distillates. Produced synthesis gas may
be used to heat the formation as a combustion fuel. Hydrogen in
produced synthesis gas may be used to upgrade oil.
[0081] Synthesis gas may also be used for other purposes. Synthesis
gas may be combusted as fuel. Synthesis gas may also be used for
synthesizing a wide range of organic and/or inorganic compounds
such as hydrocarbons and ammonia. Synthesis gas may be used to
generate electricity, by combusting it as a fuel, by reducing the
pressure of the synthesis gas in turbines, and/or using the
temperature of the synthesis gas to make steam (and then run
turbines). Synthesis gas may also be used in an energy generation
unit such as a molten carbonate fuel cell, a solid oxide fuel cell,
or other type of fuel cell.
[0082] Certain embodiments may include separating a fuel cell feed
stream from fluids produced from pyrolysis of at least some of the
hydrocarbons within a formation. The fuel cell feed stream may
include H.sub.2 hydrocarbons, and/or carbon monoxide. In addition,
certain embodiments may include directing the fuel cell feed stream
to a fuel cell to produce electricity. The electricity generated
from the synthesis gas or the pyrolyzation fluids in the fuel cell
may be configured to power electrical heaters, which may be
configured to heat at least a portion of the formation. Certain
embodiments may include separating carbon dioxide from a fluid
exiting the fuel cell. Carbon dioxide produced from a fuel cell or
a formation may be used for a variety of purposes.
[0083] In an embodiment, a portion of a formation that has been
pyrolyzed and/or subjected to synthesis gas generation may be
allowed to cool or may be cooled to form a cooled, spent portion
within the formation. For example, a heated portion of a formation
may be allowed to cool by transference of heat to adjacent portion
of the formation. The transference of heat may occur naturally or
may be forced by the introduction of heat transfer fluids through
the heated portion and into a cooler portion of the formation.
Alternatively, introducing water to the first portion of the
formation may cool the first portion. Water introduced into the
first portion may be removed from the formation as steam. The
removed steam or hot water may be injected into a hot portion of
the formation to create synthesis gas.
[0084] Cooling the formation may provide certain benefits such as
increasing the strength of the rock in the formation (thereby
mitigating subsidence), increasing absorptive capacity of the
formation, etc.
[0085] In an embodiment, a cooled, spent portion of a coal
formation may be used to store and/or sequester other materials
such as carbon dioxide. Carbon dioxide may be injected under
pressure into the cooled, spent portion of the formation. The
injected carbon dioxide may adsorb onto hydrocarbons in the
formation and/or reside in void spaces such as pores in the
formation. The carbon dioxide may be generated during pyrolysis,
synthesis gas generation, and/or extraction of useful energy.
[0086] In an embodiment, produced formation fluids may be stored in
a cooled, spent portion of the formation. In some embodiments
carbon dioxide may be stored in relatively deep coal beds, and used
to desorb coal bed methane.
BRIEF DESCRIPTION OF THE DRAWINGS
[0087] Further advantages of the present invention may become
apparent to those skilled in the art with the benefit of the
following detailed description of the preferred embodiments and
upon reference to the accompanying drawings in which:
[0088] FIG. 1 depicts an illustration of stages of heating a coal
formation;
[0089] FIG. 2 depicts a diagram of properties of a coal
formation;
[0090] FIG. 3 depicts an embodiment of a heat source pattern;
[0091] FIGS. 3a-3c depict embodiments of heat sources;
[0092] FIG. 4 depicts an embodiment of heater wells located in a
coal formation;
[0093] FIG. 5 depicts an embodiment of a pattern of heater wells in
a coal formation;
[0094] FIG. 6 depicts an embodiment of a heated portion of a coal
formation;
[0095] FIG. 7 depicts an embodiment of superposition of heat in a
coal formation;
[0096] FIG. 8 and FIG. 9 depict embodiments of a pattern of heat
sources and production wells in a coal formation;
[0097] FIG. 10 depicts an embodiment of a natural distributed
combustor heat source;
[0098] FIG. 11 depicts a portion of an overburden of a formation
with a heat source;
[0099] FIG. 12 and FIG. 13 depict embodiments of a natural
distributed combustor heater;
[0100] FIG. 14 and FIG. 15 depict embodiments of a system for
heating a formation;
[0101] FIGS. 16-21 depict several embodiments of an insulated
conductor heat source;
[0102] FIG. 22 and FIGS. 23a-23b depict several embodiments of a
centralizer;
[0103] FIG. 24 depicts an embodiment of a conductor-in-conduit heat
source in a formation;
[0104] FIG. 25 depicts an embodiment of a heat source in a
formation;
[0105] FIG. 26 depicts an embodiment of a surface combustor heat
source;
[0106] FIG. 27 depicts an embodiment of a conduit for a heat
source;
[0107] FIG. 28 depicts an embodiment of a flameless combustor heat
source;
[0108] FIG. 29 depicts an embodiment of using pyrolysis water to
generate synthesis gas in a formation;
[0109] FIG. 30 depicts an embodiment of synthesis gas production in
a formation;
[0110] FIG. 31 depicts an embodiment of continuous synthesis gas
production in a formation;
[0111] FIG. 32 depicts an embodiment of batch synthesis gas
production in a formation;
[0112] FIG. 33 depicts an embodiment of producing energy with
synthesis gas produced from a coal formation;
[0113] FIG. 34 depicts an embodiment of producing energy with
pyrolyzation fluid produced from a coal formation;
[0114] FIG. 35 depicts an embodiment of synthesis gas production
from a formation;
[0115] FIG. 36 depicts an embodiment of sequestration of carbon
dioxide produced during pyrolysis in a coal formation;
[0116] FIG. 37 depicts an embodiment of producing energy with
synthesis gas produced from a coal formation;
[0117] FIG. 38 depicts an embodiment of a Fischer-Tropsch process
using synthesis gas produced from a coal formation;
[0118] FIG. 39 depicts an embodiment of a Shell Middle Distillates
process using synthesis gas produced from a coal formation;
[0119] FIG. 40 depicts an embodiment of a catalytic methanation
process using synthesis gas produced from a coal formation;
[0120] FIG. 41 depicts an embodiment of production of ammonia and
urea using synthesis gas produced from a coal formation;
[0121] FIG. 42 depicts an embodiment of production of ammonia using
synthesis gas produced from a coal formation;
[0122] FIG. 43 depicts an embodiment of preparation of a feed
stream for an ammonia process;
[0123] FIGS. 44-57 depict several embodiments of a heat source and
production well pattern;
[0124] FIG. 58 depicts an embodiment of surface facilities for
treating a formation fluid;
[0125] FIG. 59 depicts an embodiment of a catalytic flameless
distributed combustor;
[0126] FIG. 60 depicts an embodiment of surface facilities for
treating a formation fluid;
[0127] FIG. 61 depicts an embodiment of a square pattern of heat
sources and production wells;
[0128] FIG. 62 depicts an embodiment of a heat source and
production well pattern;
[0129] FIG. 63 depicts an embodiment of a triangular pattern of
heat sources;
[0130] FIG. 64 depicts an embodiment of a square pattern of heat
sources;
[0131] FIG. 65 depicts an embodiment of a hexagonal pattern of heat
sources;
[0132] FIG. 66 depicts an embodiment of a 12 to 1 pattern of heat
sources;
[0133] FIG. 67 depicts extension of a reaction zone in a heated
formation over time;
[0134] FIG. 68 and FIG. 69 depict the ratio of conductive heat
transfer to radiative heat transfer in a formation;
[0135] FIGS. 70-73 depict temperatures of a conductor, a conduit,
and an opening in a formation versus a temperature at the face of a
formation;
[0136] FIG. 74 depicts a retort and collection system;
[0137] FIG. 75 depicts an embodiment of an apparatus for a drum
experiment;
[0138] FIG. 76 depicts a plot of ethene to ethane ratio versus
hydrogen concentration;
[0139] FIG. 77 depicts weight percent of paraffins versus vitrinite
reflectance;
[0140] FIG. 78 depicts weight percent of cycloalkanes in produced
oil versus vitrinite reflectance;
[0141] FIG. 79 depicts weight percentages of paraffins and
cycloalkanes in produced oil versus vitrinite reflectance;
[0142] FIG. 80 depicts phenol weight percent in produced oil versus
vitrinite reflectance;
[0143] FIG. 81 depicts aromatic weight percent in produced oil
versus vitrinite reflectance;
[0144] FIG. 82 depicts ratio of paraffins and aliphatics to
aromatics versus vitrinite reflectance;
[0145] FIG. 83 depicts yields of paraffins versus vitrinite
reflectance;
[0146] FIG. 84 depicts yields of cycloalkanes versus vitrinite
reflectance;
[0147] FIG. 85 depicts yields of cycloalkanes and paraffins versus
vitrinite reflectance;
[0148] FIG. 86 depicts yields of phenol versus vitrinite
reflectance;
[0149] FIG. 87 depicts API gravity as a function of vitrinite
reflectance;
[0150] FIG. 88 depicts yield of oil from a coal formation as a
function of vitrinite reflectance;
[0151] FIG. 89 depicts CO.sub.2 yield from coal having various
vitrinite reflectances;
[0152] FIG. 90 depicts CO.sub.2 yield versus atomic O/C ratio for a
coal formation;
[0153] FIG. 91 depicts a schematic of a coal cube experiment;
[0154] FIG. 92 depicts in situ temperature profiles for electrical
resistance heaters, and natural distributed combustion heaters;
[0155] FIG. 93 depicts equilibrium gas phase compositions produced
from experiments on a coal cube;
[0156] FIG. 94 depicts cumulative production of gas as a function
of temperature produced by heating a coal cube;
[0157] FIG. 95 depicts cumulative condensable hydrocarbons and
water as a function of temperature produced by heating a coal
cube;
[0158] FIG. 96 depicts the compositions of condensable hydrocarbons
produced when various ranks of coal were treated;
[0159] FIG. 97 depicts thermal conductivity of coal versus
temperature;
[0160] FIG. 98 depicts a cross-sectional view of an in situ
experimental field test;
[0161] FIG. 99 depicts locations of heat sources and wells in an
experimental field test;
[0162] FIG. 100 and FIG. 101 depict temperature versus time in an
experimental field test;
[0163] FIG. 102 depicts volume of oil produced from an experimental
field test as a function of time;
[0164] FIG. 103 depicts carbon number distribution of fluids
produced from an experimental field test;
[0165] FIG. 104 depicts weight percent of a hydrocarbon produced
from two laboratory experiments on coal from the 1 field test site
versus carbon number distribution;
[0166] FIG. 105 depicts fractions from separation of coal oils
treated by Fischer assay and treated by slow heating in a coal cube
experiment;
[0167] FIG. 106 depicts percentage ethene to ethane produced from a
coal formation as a function of heating rate in an experimental
field test;
[0168] FIG. 107 depicts product quality of fluids produced from a
coal formation as a function of heating rate in an experimental
field test;
[0169] FIG. 108 depicts weight percentages of various fluids
produced from a coal formation for various heating rates in an
experimental field test;
[0170] FIG. 109 depicts CO.sub.2 produced at three different
locations versus time in an experimental field test;
[0171] FIG. 110 depicts volatiles produced from a coal formation in
an experimental field test versus cumulative energy content;
[0172] FIG. 111 depicts volume of gas produced from a coal
formation in an experimental field test as a function of time;
[0173] FIG. 112 depicts volume of oil produced from a coal
formation in an experimental field test as a function of energy
input;
[0174] FIG. 113 depicts synthesis gas production from the coal
formation in an experimental field test versus the total water
inflow;
[0175] FIG. 114 depicts additional synthesis gas production from
the coal formation in an experimental field test due to injected
steam;
[0176] FIG. 115 depicts the effect of methane injection into a
heated formation;
[0177] FIG. 116 depicts the effect of ethane injection into a
heated formation;
[0178] FIG. 117 depicts the effect of propane injection into a
heated formation;
[0179] FIG. 118 depicts the effect of butane injection into a
heated formation;
[0180] FIG. 119 depicts composition of gas produced from a
formation versus time;
[0181] FIG. 120 depicts synthesis gas conversion versus time;
[0182] FIG. 121 depicts calculated equilibrium gas dry mole
fractions for a reaction of coal with water;
[0183] FIG. 122 depicts calculated equilibrium gas wet mole
fractions for a reaction of coal with water;
[0184] FIG. 123 depicts an example of pyrolysis and synthesis gas
production stages in a coal formation;
[0185] FIG. 124 depicts an example of low temperature in situ
synthesis gas production;
[0186] FIG. 125 depicts an example of high temperature in situ
synthesis gas production;
[0187] FIG. 126 depicts an example of in situ synthesis gas
production in a coal formation;
[0188] FIG. 127 depicts a plot of cumulative adsorbed methane and
carbon dioxide versus pressure in a coal formation;
[0189] FIG. 128 depicts an embodiment of in situ synthesis gas
production integrated with a Fischer-Tropsch process;
[0190] FIG. 129 depicts a comparison between numerical simulation
data and experimental field test data of synthesis gas composition
produced as a function of time;
[0191] FIG. 130 depicts pressure at wellheads as a function of time
from a numerical simulation;
[0192] FIG. 131 depicts production rate of carbon dioxide and
methane as a function of time from a numerical simulation;
[0193] FIG. 132 depicts cumulative methane produced and net carbon
dioxide injected as a function of time from a numerical
simulation;
[0194] FIG. 133 depicts pressure at wellheads as a function of time
from a numerical simulation;
[0195] FIG. 134 depicts production rate of carbon dioxide as a
function of time from a numerical simulation; and
[0196] FIG. 135 depicts cumulative net carbon dioxide injected as a
function of time from a numerical simulation.
[0197] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings and may herein be described in
detail. The drawings may not be to scale. It should be understood,
however, that the drawings and detailed description thereto are not
intended to limit the invention to the particular form disclosed,
but on the contrary, the intention is to cover all modifications,
equivalents and alternatives falling within the spirit and scope of
the present invention as defined by the appended claims.
DETAILED DESCRIPTION OF THE INVENTION
[0198] The following description generally relates to systems and
methods for treating a coal formation, which may include, but is
not limited to, humic and/or sapropelic coal. Such formations may
be treated to yield relatively high quality hydrocarbon products,
hydrogen, and other products.
[0199] As used herein, the word "coal" is generally defined to
include naturally formed sedimentary rock or other rock that
contains at least about 70% by volume of organic matter.
[0200] As used herein, "a method of treating a coal formation" may
be used interchangeably with "an in situ conversion process for
coal."
[0201] "Hydrocarbons" are generally defined as organic material
that contains carbon and hydrogen in their molecular structures.
Hydrocarbons may also include other elements, such as, but not
limited to, halogens, metallic elements, nitrogen, oxygen, and/or
sulfur.
[0202] "Kerogen" is generally defined as a solid, insoluble
hydrocarbon that has been converted by natural degradation (e.g.,
by diagenesis) and that principally contains carbon, hydrogen,
nitrogen, oxygen, and sulfur. Coal is a typical example of a
material that contains kerogens. "Oil" is generally defined as a
fluid containing a complex mixture of condensable hydrocarbons.
[0203] The terms "formation fluids" and "produced fluids" generally
refer to fluids removed from a coal formation and may include
pyrolyzation fluid, synthesis gas, and water (steam). Formation
fluids may include hydrocarbon fluids as well as non-hydrocarbon
fluids. As used herein, "hydrocarbon fluids" generally refer to
compounds including primarily hydrogen and carbon. Hydrocarbon
fluids may include other elements in addition to hydrogen and
carbon such as, but not limited to, nitrogen, oxygen, and sulfur.
Non-hydrocarbon fluids may include, but are not limited to,
hydrogen ("H.sub.2"), nitrogen ("N.sub.2"), carbon monoxide, carbon
dioxide, hydrogen sulfide, water, and ammonia.
[0204] A "carbon number" generally refers to a number of carbon
atoms within a molecule. As described herein, carbon number
distributions are determined by true boiling point distribution and
gas liquid chromatography.
[0205] A "heat source" is generally defined as any system
configured to provide heat to at least a portion of a formation.
For example, a heat source may include electrical heaters such as
an insulated conductor, an elongated member, and a conductor
disposed within a conduit, as described in embodiments herein. A
heat source may also include heat sources that generate heat by
burning a fuel external to or within a formation such as surface
burners, flameless distributed combustors, and natural distributed
combustors, as described in embodiments herein. In addition, it is
envisioned that in some embodiments heat provided to or generated
in one or more heat sources may by supplied by other sources of
energy. The other sources of energy may directly heat a formation,
or the energy may be applied to a transfer media that directly or
indirectly heats the formation. It is to be understood that one or
more heat sources that are applying heat to a formation may use
different sources of energy. Thus, for example, for a given
formation some heat sources may supply heat from electric
resistance heaters, some heat sources may provide heat from
combustion, and some heat sources may provide heat from one or more
other energy sources (e.g., chemical reactions, solar energy, wind
energy, or other sources of renewable energy). A chemical reaction
may include an exothermic reaction such as, but not limited to, an
oxidation reaction that may take place in at least a portion of a
formation. A heat source may also include a heater that may be
configured to provide heat to a zone proximate to and/or
surrounding a heating location such as a heater well. Heaters may
be, but are not limited to, electric heaters, burners, and natural
distributed combustors.
[0206] A "heater" is generally defined as any system configured to
generate heat in a well or a near wellbore region. A "unit of heat
sources" refers to a minimal number of heat sources that form a
template that is repeated to create a pattern of heat sources
within a formation. For example, a heater may generate heat by
burning a fuel external to or within a formation such as surface
burners, flameless distributed combustors, and natural distributed
combustors, as described in embodiments herein.
[0207] The term "wellbore" generally refers to a hole in a
formation made by drilling. A wellbore may have a substantially
circular cross-section, or a cross-section in other shapes as well
(e.g., circles, ovals, squares, rectangles, triangles, slits, or
other regular or irregular shapes). As used herein, the terms
"well" and "opening," when referring to an opening in the
formation, may also be used interchangeably with the term
"wellbore."
[0208] As used herein, the phrase "natural distributed combustor"
generally refers to a heater that uses an oxidant to oxidize at
least a portion of the carbon in the formation to generate heat,
and wherein the oxidation takes place in a vicinity proximate to a
wellbore. Most of the combustion products produced in the natural
distributed combustor are removed through the wellbore.
[0209] The term "orifices," as used herein, generally describes
openings having a wide variety of sizes and cross-sectional shapes
including, but not limited to, circles, ovals, squares, rectangles,
triangles, slits, or other regular or irregular shapes.
[0210] As used herein, a "reaction zone" generally refers to a
volume of a coal formation that is subjected to a chemical reaction
such as an oxidation reaction.
[0211] As used herein, the term "insulated conductor" generally
refers to any elongated material that may conduct electricity and
that is covered, in whole or in part, by an electrically insulating
material. The term "self-controls" generally refers to controlling
an output of a heater without external control of any type.
[0212] "Pyrolysis" is generally defined as the breaking of chemical
bonds due to the application of heat. For example, pyrolysis may
include transforming a compound into one or more other substances
by heat alone. In the context of this patent, heat for pyrolysis
may originate in an oxidation reaction and then such heat may be
transferred to a section of the formation to cause pyrolysis.
[0213] As used herein, a "pyrolyzation fluid" or "pyrolysis
products" generally refers to a fluid produced substantially during
pyrolysis of hydrocarbons. As used herein, a "pyrolysis zone"
generally refers to a volume of coal formation that is reacted or
reacting to form a pyrolyzation fluid.
[0214] "Cracking" generally refers to a process involving
decomposition and molecular recombination of organic compounds
wherein a number of molecules becomes larger. In cracking, a series
of reactions take place accompanied by a transfer of hydrogen atoms
between molecules. Cracking fundamentally changes the chemical
structure of the molecules. For example, naphtha may undergo a
thermal cracking reaction to form ethene and H.sub.2.
[0215] The term "superposition of heat" is generally defined as
providing heat from at least two heat sources to a selected section
of the portion of the formation such that the temperature of the
formation at least at one location between the two wells is
influenced by at least two heat sources.
[0216] The term "fingering" generally refers to injected fluids
bypassing portions of a formation because of variations in
transport characteristics (e.g., permeability).
[0217] "Thermal conductivity" is generally defined as the property
of a material that describes the rate at which heat flows, in
steady state, between two surfaces of the material for a given
temperature difference between the two surfaces.
[0218] "Fluid pressure" is generally defined as a pressure
generated by a fluid within a formation. "Lithostatic pressure" is
sometimes referred to as lithostatic stress and is generally
defined as a pressure within a formation equal to a weight per unit
area of an overlying rock mass. "Hydrostatic pressure" is generally
defined as a pressure within a formation exerted by a column of
water.
[0219] "Condensable hydrocarbons" means the hydrocarbons that
condense at 25.degree. C. at one atmosphere absolute pressure.
Condensable hydrocarbons may include a mixture of hydrocarbons
having carbon numbers greater than 4. "Non-condensable
hydrocarbons" means the hydrocarbons that do not condense at
25.degree. C. and one atmosphere absolute pressure. Non-condensable
hydrocarbons may include hydrocarbons having carbon numbers less
than 5.
[0220] "Olefins" are generally defined as unsaturated hydrocarbons
having one or more non-aromatic carbon-to-carbon double bonds.
[0221] "Urea" is generally described by a molecular formula of
NH.sub.2-CO-NH.sub.2. Urea can be used as a fertilizer.
[0222] "Synthesis gas" is generally defined as a mixture including
hydrogen and carbon monoxide used for synthesizing a wide range of
compounds. Additional components of synthesis gas may include
water, carbon dioxide, nitrogen, methane and other gases. Synthesis
gas may be generated by a variety of processes and feedstocks.
[0223] "Reforming" is generally defined as the reaction of
hydrocarbons (such as methane or naphtha) with steam to produce CO
and H.sub.2 as major products. Generally it is conducted in the
presence of a catalyst although it can be performed thermally
without the presence of a catalyst.
[0224] "Sequestration" generally refers to storing a gas that is a
by-product of a process rather than venting the gas to the
atmosphere.
[0225] The term "dipping" is generally defined as sloping downward
or inclining from a plane parallel to the earth's surface, assuming
the plane is flat (i.e., a "horizontal" plane). A "dip" is
generally defined as an angle that a stratum or similar feature may
make with a horizontal plane. A "steeply dipping" coal formation
generally refers to a coal formation lying at an angle of at least
20.degree. from a horizontal plane. As used herein, "down dip"
generally refers to downward along a direction parallel to a dip in
a formation. As used herein, "up dip" generally refers to upward
along a direction parallel to a dip of a formation.
[0226] "Strike" refers to the course or bearing of hydrocarbon
material that is normal to the direction of the dip.
[0227] The term "subsidence" is generally defined as downward
movement of a portion of a formation relative to an initial
elevation of the surface.
[0228] "Thickness" of a layer refers to the thickness of a
cross-section of a layer, wherein the cross-section is normal to a
face of the layer.
[0229] "Coring" is generally defined as a process that generally
includes drilling a hole into a formation and removing a
substantially solid mass of the formation from the hole.
[0230] A "surface unit" is generally defined as an ex situ
treatment unit.
[0231] "Middle distillates" generally refers to hydrocarbon
mixtures with a boiling point range that may correspond
substantially with that of kerosene and gas oil fractions obtained
in a conventional atmospheric distillation of crude oil material.
The middle distillate boiling point range may include temperatures
between about 150.degree. C. and about 360.degree. C., with a
fraction boiling point between about 200.degree. C. and about
360.degree. C. Middle distillates may be referred to as gas
oil.
[0232] A "boiling point cut" is generally defined as a hydrocarbon
liquid fraction that may be separated from hydrocarbon liquids when
the hydrocarbon liquids are heated to a boiling point range of the
fraction.
[0233] The term "selected mobilized section" refers to a section of
a relatively permeable formation that is at an average temperature
within a mobilization temperature range. The term "selected
pyrolyzation section" refers to a section of a relatively permeable
formation that is at an average temperature within a pyrolyzation
temperature range.
[0234] "Enriched air" generally refers to air having a larger mole
fraction of oxygen than air in the atmosphere. Enrichment of air is
typically done to increase its combustion-supporting ability.
[0235] The phrase "off peak" times generally refers to times of
operation where utility energy is less commonly used and,
therefore, less expensive.
[0236] "Thermal fracture" refers to fractures created in a
formation caused by expansion or contraction of a formation and/or
fluids within the formation, which is in turn caused by
increasing/decreasing the temperature of the formation and/or
fluids within the formation, and/or by increasing/decreasing a
pressure of fluids within the formation due to heating.
[0237] Hydrocarbons in coal formations may be treated in various
ways to produce many different products. In certain embodiments
such formations may be treated in stages. FIG. 1 illustrates
several stages of heating a coal formation. FIG. 1 also depicts an
example of yield (barrels of oil equivalent per ton) (y axis) of
formation fluids from a coal formation versus temperature (.degree.
C.) (x axis) of the formation.
[0238] Desorption of methane and vaporization of water occurs
during stage 1 heating in FIG. 1. For example, when a coal
formation is initially heated, hydrocarbons in the formation may
desorb adsorbed methane. The desorbed methane may be produced from
the formation. If the coal formation is heated further, water
within the coal formation may be vaporized. In addition, the
vaporized water may be produced from the formation. Heating of the
formation through stage 1 is in many instances preferably performed
as quickly as possible.
[0239] After stage 1 heating, the formation may be heated further
such that a temperature within the formation reaches (at least) an
initial pyrolyzation temperature (e.g., the temperature at the
lower end of the temperature range shown as stage 2). A pyrolysis
temperature range may vary depending on types of hydrocarbons
within the formation. For example, a pyrolysis temperature range
may include temperatures between about 250.degree. C. and about
900.degree. C. In an alternative embodiment, a pyrolysis
temperature range may include temperatures between about
270.degree. C. to about 400.degree. C. Hydrocarbons within the
formation may be pyrolyzed throughout stage 2.
[0240] Formation fluids including pyrolyzation fluids may be
produced from the formation. The pyrolyzation fluids may include,
but are not limited to, hydrocarbons, hydrogen, carbon dioxide,
carbon monoxide, hydrogen sulfide, ammonia, nitrogen, water and
mixtures thereof. As the temperature of the formation increases,
the condensable hydrocarbons of produced formation fluid tends to
decrease, and the formation will in many instances tend to produce
mostly methane and hydrogen. If a coal formation is heated
throughout an entire pyrolysis range, the formation may produce
only small amounts of hydrogen towards an upper limit of the
pyrolysis range. After all of the available hydrogen is depleted, a
minimal amount of fluid production from the formation will
typically occur.
[0241] After pyrolysis of hydrocarbons, a large amount of carbon
and some hydrogen may still be present in the formation. A
significant portion of remaining carbon in the formation can be
produced from the formation in the form of synthesis gas. Synthesis
gas generation may take place during stage 3 heating as shown in
FIG. 1. Stage 3 may include heating a coal formation to a
temperature sufficient to allow synthesis gas generation. For
example, synthesis gas may be produced within a temperature range
from about 400.degree. C. to about 1200.degree. C. The temperature
of the formation when the synthesis gas generating fluid is
introduced to the formation will in many instances determine the
composition of synthesis gas produced within the formation. If a
synthesis gas generating fluid is introduced into a formation at a
temperature sufficient to allow synthesis gas generation, then
synthesis gas may be generated within the formation. The generated
synthesis gas may be removed from the formation. A large volume of
synthesis gas may be produced during generation of synthesis gas
generation.
[0242] Depending on the amounts of fluid produced, total energy
content of fluids produced from a coal formation may in some
instances stay relatively constant throughout pyrolysis and
synthesis gas generation. For example, during pyrolysis, at
relatively low formation temperatures, a significant portion of the
produced fluid may be condensable hydrocarbons that have a high
energy content. At higher pyrolysis temperatures, however, less of
the formation fluid may include condensable hydrocarbons, and more
non-condensable formation fluids may be produced. In this manner,
energy content per unit volume of the produced fluid may decline
slightly during generation of predominantly non-condensable
formation fluids. During synthesis gas generation, energy content
per unit volume of produced synthesis gas declines significantly
compared to energy content of pyrolyzation fluid. The volume of the
produced synthesis gas, however, will in many instance increase
substantially, thereby compensating for the decreased energy
content.
[0243] As explained below, the van Krevelen diagram shown in FIG. 2
depicts a plot of atomic hydrogen to carbon ratio (y axis) versus
atomic oxygen to carbon ratio (x axis) for various types of
kerogen. This diagram shows the maturation sequence for various
types of kerogen that typically occurs over geologic time due to
temperature, pressure, and biochemical degradation. The maturation
may be accelerated by heating in situ at a controlled rate and/or a
controlled pressure.
[0244] A van Krevelen diagram may be useful for selecting a
resource for practicing various embodiments described herein (see
discussion below). Treating a formation containing kerogen in
region 5 will in many instances produce, e.g., carbon dioxide,
non-condensable hydrocarbons, hydrogen, and water, along with a
relatively small amount of condensable hydrocarbons. Treating a
formation containing kerogen in region 7 will in many instances
produce, e.g., carbon condensable and non-condensable hydrocarbons,
carbon dioxide, hydrogen, and water. Treating a formation
containing kerogen in region 9 will in many instances produce,
e.g., methane and hydrogen. A formation containing kerogen in
region 7, for example, may in many instances be selected for
treatment because doing so will tend to produce larger quantities
of valuable hydrocarbons, and lower quantities of undesirable
products such as carbon dioxide and water, since the region 7
kerogen has already undergone dehydration and/or decarboxylation
over geological time. In addition, region 7 kerogen can also be
further treated to make other useful products (e.g., methane,
hydrogen, and/or synthesis gas) as such kerogen transforms to
region 9 kerogen.
[0245] If a formation containing kerogen in region 5 or 7 was
selected for treatment, then treatment pursuant to certain
embodiments described herein would cause such kerogen to transform
during treatment (see arrows in FIG. 2) to a region having a higher
number (e.g., region 5 kerogen could transform to region 7 kerogen
and possibly then to region 9 kerogen, or region 7 kerogen could
transform to region 9 kerogen). Thus, certain embodiments described
herein cause expedited maturation of kerogen, thereby allowing
production of valuable products.
[0246] If region 5 kerogen, for example, is treated, then
substantial carbon dioxide may be produced due to decarboxylation
of hydrocarbons in the formation. In addition, treating region 5
kerogen may also produce some hydrocarbons (e.g., primarily
methane). Treating region 5 kerogen may also produce substantial
amounts of water due to dehydration of 5 kerogen in the formation.
Production of such compounds from a formation may leave residual
hydrocarbons relatively enriched in carbon. Oxygen content of the
hydrocarbons will in many instances decrease faster than a hydrogen
content of the hydrocarbons during production of such compounds.
Therefore, as shown in FIG. 2, production of such compounds may
result in a larger decrease in the atomic oxygen to carbon ratio
than a decrease in the atomic hydrogen to carbon ratio (see region
5 arrows in FIG. 2 which depict more horizontal than vertical
movement).
[0247] If region 7 kerogen is treated, then typically at least some
of the hydrocarbons in the formation are pyrolyzed to produce
condensable and non-condensable hydrocarbons. For example, treating
region 7 kerogen may result in production of oil from hydrocarbons,
as well as some carbon dioxide and water (albeit generally less
carbon dioxide and water than is produced when the region 5 kerogen
is treated). Therefore, the atomic hydrogen to carbon ratio of the
kerogen will in many instances decrease rapidly as the kerogen in
region 7 is treated. The atomic oxygen to carbon ratio of the
region 7 kerogen, however, will in many instances decrease much
slower than the atomic hydrogen to carbon ratio of the region 7
kerogen.
[0248] Kerogen in region 9 may be treated to generate methane and
hydrogen. For example, if such kerogen was previously treated
(e.g., it was previously region 7 kerogen), then after pyrolysis
longer hydrocarbon chains of the hydrocarbons may have already
cracked and produced from the formation. Carbon and hydrogen,
however, may still be present in the formation.
[0249] If kerogen in region 9 were heated to a synthesis gas
generating temperature and a synthesis gas generating fluid (e.g.,
steam) were added to the region 9 kerogen, then at least a portion
of remaining hydrocarbons in the formation may be produced from the
formation in the form of synthesis gas. For region 9 kerogen, the
atomic hydrogen to carbon ratio and the atomic oxygen to carbon
ratio in the hydrocarbons may significantly decrease as the
temperature rises. In this manner, hydrocarbons in the formation
may be transformed into relatively pure carbon in region 9. Heating
region 9 kerogen to still higher temperatures will tend to
transform such kerogen into graphite 11.
[0250] A coal formation may have a number of properties that will
depend on, for example, a composition of at least some of the
hydrocarbons within the formation. Such properties tend to affect
the composition and amount of products that are produced from a
coal formation. Therefore, properties of a coal formation can be
used to determine if and/or how a coal formation could optimally be
treated.
[0251] Coal formations typically contain kerogen. Kerogen is
composed of organic matter that has been transformed due to a
maturation process. The maturation process may include two stages:
a biochemical stage and a geochemical stage. The biochemical stage
typically involves degradation of organic material by both aerobic
and anaerobic organisms. The geochemical stage typically involves
conversion of organic matter due to temperature changes and
significant pressures. During maturation, oil and gas may be
produced as the organic matter of the kerogen is transformed.
[0252] The van Krevelen diagram shown in FIG. 2 classifies various
natural deposits of kerogen. For example, kerogen may be classified
into four distinct groups: type I, type II, type III, and type IV,
which are illustrated by the four branches of the van Krevelen
diagram. This drawing shows the maturation sequence for kerogen,
which typically occurs over geological time due to temperature and
pressure. The types depend upon precursor materials of the kerogen.
The precursor materials transform over time into macerals, which
are microscopic structures that have different structures and
properties based on the precursor materials from which they are
derived. Oil shale may be described as a kerogen type I or type II
and may primarily contain macerals from the liptinite group. Type
II kerogen may develop from organic matter that was deposited in
marine environments.
[0253] Type III kerogen may generally include vitrinite macerals.
Vitrinite is derived from cell walls and/or woody tissues (e.g.,
stems, branches, leaves and roots of plants). Type III kerogen may
be present in most humic coals. Type III kerogen may develop from
organic matter that was deposited in swamps. Type IV kerogen
includes the inertinite maceral group. This group is composed of
plant material such as leaves, bark and stems that have undergone
oxidation during the early peat stages of burial diagenesis. It is
chemically similar to vitrinite but has a high carbon and low
hydrogen content. Thus, it is considered inert.
[0254] The dashed lines in FIG. 2 correspond to vitrinite
reflectance. The vitrinite reflectance is a measure of maturation.
As kerogen undergoes maturation, the composition of the kerogen
usually changes. For example, as kerogen undergoes maturation,
volatile matter of kerogen tends to decrease. Rank classifications
of kerogen indicate the level to which kerogen has matured. For
example, as kerogen undergoes maturation, the rank of kerogen
increases. Therefore, as rank increases, the volatile matter of
kerogen tends to decrease. In addition, the moisture content of
kerogen generally decreases as the rank increases. At higher ranks,
however, the moisture content may become relatively constant. For
example, higher rank kerogens that have undergone significant
maturation, such as semi-anthracite or anthracite coal, tend to
have a higher carbon content and a lower volatile matter content
than lower rank kerogens such as lignite. For example, rank stages
of coal formations include the following classifications, which are
listed in order of increasing rank and maturity for type III
kerogen: wood, peat, lignite, sub-bituminous coal, high volatile
bituminous coal, medium volatile bituminous coal, low volatile
bituminous coal, semi-anthracite, and anthracite. In addition, as
rank increases, kerogen tends to exhibit an increase in aromatic
nature.
[0255] Coal formations may be selected for in situ treatment based
on properties of at least a portion of the formation. For example,
a formation may be selected based on richness, thickness, and depth
(i.e., thickness of overburden) of the formation. In addition, a
formation may be selected that will have relatively high quality
fluids produced from the formation. In certain embodiments the
quality of the fluids to be produced may be assessed in advance of
treatment, thereby generating significant cost savings since only
more optimal formations will be selected for treatment. Properties
that may be used to assess hydrocarbons in a coal formation
include, but are not limited to, an amount of hydrocarbon liquids
that tend to be produced from the hydrocarbons, a likely API
gravity of the produced hydrocarbon liquids, an amount of
hydrocarbon gas that tend to be produced from the hydrocarbons,
and/or an amount of carbon dioxide and water that tend to be
produced from the hydrocarbons.
[0256] Another property that may be used to assess the quality of
fluids produced from certain coal formations is vitrinite
reflectance. Coal formations that include kerogen can typically be
assessed/selected for treatment based on a vitrinite reflectance of
the kerogen. Vitrinite reflectance is often related to a hydrogen
to carbon atomic ratio of a kerogen and an oxygen to carbon atomic
ratio of the kerogen, as shown by the dashed lines in FIG. 2. For
example, a van Krevelen diagram may be useful in selecting a
resource for an in situ conversion process.
[0257] Vitrinite reflectance of a kerogen in a coal formation tends
to indicate which fluids may be produced from a formation upon
heating. For example, a vitrinite reflectance of approximately 0.5%
to approximately 1.5% tends to indicate a kerogen that, upon
heating, will produce fluids as described in region 7 above.
Therefore, if a coal formation having such kerogen is heated, a
significant amount (e.g., majority) of the fluid produced by such
heating will often include oil and other such hydrocarbon fluids.
In addition, a vitrinite reflectance of approximately 1.5% to 3.0%
may indicate a kerogen in region 9 as described above. If a coal
formation having such kerogen is heated, a significant amount
(e.g., majority) of the fluid produced by such heating may include
methane and hydrogen (and synthesis gas, if, for example, the
temperature is sufficiently high and steam is injected). In an
embodiment, at least a portion of a coal formation selected for
treatment in situ has a vitrinite reflectance in a range between
about 0.2% and about 3.0%. Alternatively, at least a portion of a
coal formation selected for treatment has a vitrinite reflectance
from about 0.5% to about 2.0%, and, in some circumstances, the
vitrinite reflectance may range from about 0.5% to 1.0%. Such
ranges of vitrinite reflectance tend to indicate that relatively
higher quality formation fluids will be produced from the
formation.
[0258] In an embodiment, a coal formation may be selected for
treatment based on a hydrogen content within the hydrocarbons in
the formation. For example, a method of treating a coal formation
may include selecting a portion of the coal formation for treatment
having hydrocarbons with a hydrogen content greater than about 3
weight %, 3.5 weight %, or 4 weight % when measured on a dry,
ash-free basis. In addition, a selected section of a coal formation
may include hydrocarbons with an atomic hydrogen to carbon ratio
that falls within a range from about 0.5 to about 2, and in many
instances from about 0.70 to about 1.65.
[0259] Hydrogen content of a coal formation may significantly
affect a composition of hydrocarbon fluids produced from a
formation. For example, pyrolysis of at least some of the
hydrocarbons within the heated portion may generate hydrocarbon
fluids that may include a double bond or a radical. Hydrogen within
the formation may reduce the double bond to a single bond. In this
manner, reaction of generated hydrocarbon fluids with each other
and/or with additional components in the formation may be
substantially inhibited. For example, reduction of a double bond of
the generated hydrocarbon fluids to a single bond may reduce
polymerization of the generated hydrocarbons. Such polymerization
tends to reduce the amount of fluids produced.
[0260] In addition, hydrogen within the formation may also
neutralize radicals in the generated hydrocarbon fluids. In this
manner, hydrogen present in the formation may substantially inhibit
reaction of hydrocarbon fragments by transforming the hydrocarbon
fragments into relatively short chain hydrocarbon fluids. The
hydrocarbon fluids may enter a vapor phase and may be produced from
the formation. The increase in the hydrocarbon fluids in the vapor
phase may significantly reduce a potential for producing less
desirable products within the selected section of the
formation.
[0261] It is believed that if too little hydrogen is present in the
formation, then the amount and quality of the produced fluids will
be negatively affected. If too little hydrogen is naturally
present, then in some embodiments hydrogen or other reducing fluids
may be added to the formation.
[0262] When heating a portion of a coal formation, oxygen within
the portion may form carbon dioxide. It may be desirable to reduce
the production of carbon dioxide and other oxides. In an
embodiment, production of carbon dioxide may be reduced by
selecting and treating a portion of a coal formation having a
vitrinite reflectance of greater than about 0.5%. In addition, an
amount of carbon dioxide produced from a formation may vary
depending on, for example, an oxygen content of a treated portion
of the coal formation. Certain embodiments may thus include
selecting and treating a portion of the formation having a kerogen
with an atomic oxygen weight percentage of less than about 20%,
15%, and/or 10%. In addition, certain embodiments may include
selecting and processing a formation containing kerogen with an
atomic oxygen to carbon ratio of less than about 0.15.
Alternatively, at least some of the hydrocarbons in a portion of a
formation selected for treatment may have an atomic oxygen to
carbon ratio of about 0.03 to about 0.12. In this manner,
production of carbon dioxide and other oxides from an in situ
conversion process for coal may be reduced.
[0263] Heating a coal formation may include providing a large
amount of energy to heat sources located within the formation. Coal
formations may contain water. Water present in the coal formation
will tend to further increase the amount of energy required to heat
a coal formation. In this manner, water tends to hinder efficient
heating of the formation. For example, a large amount of energy may
be required to evaporate water from a coal formation. Thus, an
initial rate of temperature increase may be reduced by the presence
of water in the formation. Therefore, excessive amounts of heat
and/or time may be required to heat a formation having a high
moisture content to a temperature sufficient to allow pyrolysis of
at least some of the hydrocarbons in the formation. In an
embodiment, an in situ conversion process for coal may include
selecting a portion of the coal formation for treatment having an
initial moisture content of less than about 15% by weight (in some
embodiments dewatering wells may be used to reduce the water
content of the formation). Alternatively, an in situ conversion
process for coal may include selecting a portion of the coal
formation for treatment having an initial moisture content of less
than about 10% by weight.
[0264] In an embodiment, a coal formation may be selected for
treatment based on additional factors such as a thickness of coal
layer within the formation and assessed liquid production content.
For example, a coal formation may include multiple layers. Such
layers may include coal layers, and also layers that may be coal
free or have substantially low amounts of coal. Each of the coal
layers may have a thickness that may vary depending on, for
example, conditions under which the coal layer was formed.
Therefore, a coal formation will typically be selected for
treatment if that formation includes at least one coal layer having
a thickness sufficient for economical production of formation
fluids. A formation may also be chosen if the thickness of several
layers that are closely spaced together is sufficient for
economical production of formation fluids.
[0265] In addition, a layer of a coal formation may be selected for
treatment based on a thickness of the coal layer, and/or a total
thickness of coal layers in a formation. For example, an in situ
conversion process for coal may include selecting and treating a
layer of a coal formation having a thickness of greater than about
2 m, 3 m, and/or 5 m. In this manner, heat losses (as a fraction of
total injected heat) to layers formed above and below a layer of
hydrocarbons may be less than such heat losses from a thin layer of
coal. A process as described herein, however, may also include
selecting and treating layers that may include layers substantially
free of coal and thin layers of coal.
[0266] Each of the coal layers may also have a potential formation
fluid yield that may vary depending on, for example, conditions
under which the coal layer was formed, an amount of hydrocarbons in
the layer, and/or a composition of hydrocarbons in the layer. A
potential formation fluid yield may be measured, for example, by
the Fischer Assay. The Fischer Assay is a standard method which
involves heating a sample of a coal layer to approximately
500.degree. C. in one hour, collecting products produced from the
heated sample, and quantifying the amount of products produced. A
sample of a coal layer may be obtained from a coal formation by a
method such as coring or any other sample retrieval method.
[0267] FIG. 3 shows a schematic view of an embodiment of a portion
of an in situ conversion system for treating a coal formation. Heat
sources 100 may be placed within at least a portion of the coal
formation. Heat sources 100 may include, for example, electrical
heaters such as insulated conductors, conductor-in-conduit heaters,
surface burners, flameless distributed combustors, and/or natural
distributed combustors. Heat sources 100 may also include other
types of heaters. Heat sources 100 are configured to provide heat
to at least a portion of a coal formation. Energy may be supplied
to the heat sources 100 through supply lines 102. The supply lines
may be structurally different depending on the type of heat source
or heat sources being used to heat the formation. Supply lines for
heat sources may transmit electricity for electrical heaters, may
transport fuel for combustors, or may transport heat exchange fluid
that is circulated within the formation.
[0268] Production wells 104 may be used to remove formation fluid
from the formation. Formation fluid produced from the production
wells 104 may be transported through collection piping 106 to
treatment facilities 108. Formation fluids may also be produced
from heat sources 100. For example, fluid may be produced from heat
sources 100 to control pressure within the formation adjacent to
the heat sources. Fluid produced from heat sources 100 may be
transported through tubing or piping to the collection piping 106
or the produced fluid may be transported through tubing or piping
directly to the treatment facilities 108. The treatment facilities
108 may include separation units, reaction units, upgrading units,
fuel cells, turbines, storage vessels, and other systems and units
for processing produced formation fluids.
[0269] An in situ conversion system for treating coal may include
dewatering wells 110 (wells shown with reference number 110 may, in
some embodiments, be capture and/or isolation wells). Dewatering
wells 110 or vacuum wells may be configured to remove and inhibit
liquid water from entering a portion of a coal formation to be
heated, or to a formation being heated. A plurality of water wells
may surround all or a portion of a formation to be heated. In the
embodiment depicted in FIG. 3, the dewatering wells 110 are shown
extending only along one side of heat sources 100, but dewatering
wells typically encircle all heat sources 100 used, or to be used,
to heat the formation.
[0270] Dewatering wells 110 may be placed in one or more rings
surrounding selected portions of the formation. New dewatering
wells may need to be installed as an area being treated by the in
situ conversion process expands. An outermost row of dewatering
wells may inhibit a significant amount of water from flowing into
the portion of formation that is heated or to be heated. Water
produced from the outermost row of dewatering wells should be
substantially clean, and may require little or no treatment before
being released. An innermost row of dewatering wells may inhibit
water that bypasses the outermost row from flowing into the portion
of formation that is heated or to be heated. The innermost row of
dewatering wells may also inhibit outward migration of vapor from a
heated portion of the formation into surrounding portions of the
formation. Water produced by the innermost row of dewatering wells
may include some hydrocarbons. The water may need to be treated
before being released. Alternately, water with hydrocarbons may be
stored and used to produce synthesis gas from a portion of
formation during a synthesis gas phase of the in situ conversion
process. The dewatering wells may reduce heat loss to surrounding
portions of the formation, may increase production of vapors from
the heated portion, and may inhibit contamination of a water table
proximate the heated portion of the formation.
[0271] In an alternative embodiment, a fluid (e.g., liquid or gas)
may be injected in the innermost row of wells, allowing a selected
pressure to be maintained in or about the pyrolysis zone.
Additionally, this fluid may act as an isolation barrier between
the outermost wells and the pyrolysis fluids, thereby improving the
efficiency of the dewatering wells.
[0272] The coal to be treated may be located under a large area.
The in situ conversion system may be used to treat small portions
of the formation, and other sections of the formation may be
treated as time progresses. In an embodiment of a system for
treating a coal formation, a field layout for 24 years of
development may be divided into 24 individual plots that represent
individual drilling years. Each plot may include 120 "tiles"
(repeating matrix patterns) wherein each tile is made of 6 rows by
20 columns. Each tile may include 1 production well and 12 or 18
heater wells. The heater wells may be placed in an equilateral
triangle pattern with, for example, a well spacing of about 12 m.
Production wells may be located in centers of equilateral triangles
of heater wells, or the production wells may be located
approximately at a midpoint between two adjacent heater wells.
[0273] In certain embodiments, heat sources will be placed within a
heater well formed within a coal formation. The heater well may
include an opening through an overburden of the formation and into
at least one section of the formation. Alternatively, as shown in
FIG. 3a, heater well 224 may include an opening in formation 222
that may have a shape substantially similar to a helix or spiral. A
spiral configuration for a heater well may in some embodiments
increase the transfer of heat from the heat source and/or allow the
heat source to expand when heated, without buckling or other modes
of failure. In some embodiments, such a heater well may also
include a substantially straight section through overburden 220.
Use of a straight heater well through the overburden may decrease
heat loss to the overburden.
[0274] In an alternative embodiment, as shown in FIG. 3b, heat
sources may be placed into heater well 224 that may include an
opening in formation 222 having a shape substantially similar to a
"U" (the "legs" of the "U" may be wider or more narrow depending on
the embodiments used). First portion 226 and third portion 228 of
heater well 224 may be arranged substantially perpendicular to an
upper surface of formation 222. In addition, the first and the
third portion of the heater well may extend substantially
vertically through overburden 220. Second portion 230 of heater
well 224 may be substantially parallel to the upper surface of the
formation.
[0275] In addition, multiple heat sources (e.g., 2, 3, 4, 5, 10
heat sources or more) may extend from a heater well in some
situations. For example, as shown in FIG. 3c, heat sources 232,
234, and 236 may extend through overburden 220 into formation 222
from heater well 224. Such situations may occur when surface
considerations (e.g., aesthetics, surface land use concerns, and/or
unfavorable soil conditions near the surface) make it desirable to
concentrate the surface facilities in fewer locations. For example,
in areas where the soil is frozen and/or marshy it may be more
cost-effective to have surface facilities located in a more
centralized location.
[0276] In certain embodiments a first portion of a heater well may
extend from a surface of the ground, through an overburden, and
into a coal formation. A second portion of the heater well may
include one or more heater wells in the coal formation. The one or
more heater wells may be disposed within the coal formation at
various angles. In some embodiments, at least one of heater wells
may be disposed substantially parallel to a boundary of the coal
formation. In alternate embodiments, at least one of the heater
wells may be substantially perpendicular to the coal formation. In
addition, one of the one or more heater wells may be positioned at
an angle between perpendicular and parallel to a layer in the
formation.
[0277] FIG. 4 illustrates an embodiment of a coal formation 200
that may be at a substantially near-horizontal angle with respect
to an upper surface of the ground 204. An angle of coal formation
200, however, may vary. For example, coal formation 200 may be
steeply dipping. Economically viable production of a steeply
dipping coal formation may not be possible using presently
available mining methods. A relatively steeply dipping coal
formation, however, may be subjected to an in situ conversion
process as described herein. For example, a single set of gas
producing wells may be disposed near a top of a steeply dipping
coal formation. Such a formation may be heated by heating a portion
of the formation proximate a top of the coal formation and
sequentially heating lower sections of the coal formation. Gases
may be produced from the coal formation by transporting gases
through the previously pyrolyzed hydrocarbons with minimal pressure
loss.
[0278] In an embodiment, an in situ conversion process for coal may
include providing heat to at least a portion of a coal formation
that dips in sections. For example, a portion of the formation may
include a dip that may include a minimum depth of the portion. A
production well may be located in the portion of the coal formation
proximate the minimum depth. An additional production well may not
be required in the portion. For example, as heat transfers through
the coal formation and at least some hydrocarbons in the portion
pyrolyze, pyrolyzation fluids formed in the portion may travel
through pyrolyzed sections of the coal formation to the production
well. As described herein, increased permeability due to in situ
treatment of a coal formation may increase transfer of vapors
through the treated portion of the formation. Therefore, a number
of production wells required to produce a mixture from the
formation may be reduced. Reducing the number of production wells
required for production may increase economic viability of an in
situ conversion process.
[0279] In steeply dipping formations, directional drilling may be
used to form an opening for a heater well in the formation.
Directional drilling may include drilling an opening in which the
route/course of the opening may be planned before drilling. Such an
opening may usually be drilled with rotary equipment. In
directional drilling, a route/course of an opening may be
controlled by deflection wedges, etc.
[0280] Drilling heater well 202 may also include drilling an
opening in the formation with a drill equipped with a steerable
motor and an accelerometer that may be configured to follow coal
formation 200. For example, a steerable motor may be configured to
maintain a substantially constant distance between heater well 202
and a boundary of coal formation 200 throughout drilling of the
opening. Drilling of heater well 202 with the steerable motor and
the accelerometer may be relatively economical.
[0281] Alternatively, geosteered drilling may be used to drill
heater well 202 into coal formation 200. Geosteered drilling may
include determining or estimating a distance from an edge of coal
formation 200 to heater well 202 with a sensor. The sensor may
include, but may not be limited to, sensors that may be configured
to determine a distance from an edge of coal formation 200 to
heater well 202. In addition, such a sensor may be configured to
determine and monitor a variation in a characteristic of the coal
formation 200. Such sensors may include, but may not be limited to,
sensors that may be configured to measure a characteristic of a
hydrocarbon seam using resistance, gamma rays, acoustic pulses,
and/or other devices. Geosteered drilling may also include forming
an opening for a heater well with a drilling apparatus that may
include a steerable motor. The motor may be controlled to maintain
a predetermined distance from an edge of a coal formation. In an
additional embodiment, drilling of a heater well or any other well
in a formation may also include sonic drilling.
[0282] FIG. 5 illustrates an embodiment of a plurality of heater
wells 210 formed in coal formation 212. Coal formation 212 may be a
steeply dipping formation. One or more of the heater wells 210 may
be formed in the formation such that two or more of the heater
wells are substantially parallel to each other, and/or such that at
least one heater well is substantially parallel to coal formation
212. For example, one or more of the heater wells 210 may be formed
in coal formation 212 by a magnetic steering method. An example of
a magnetic steering method is illustrated in U.S. Pat. No.
5,676,212 to Kuckes, which is incorporated by reference as if fully
set forth herein. Magnetic steering may include drilling heater
well 210 parallel to an adjacent heater well. The adjacent well may
have been previously drilled. In addition, magnetic steering may
include directing the drilling by sensing and/or determining a
magnetic field produced in an adjacent heater well. For example,
the magnetic field may be produced in the adjacent heater well by
flowing a current through an insulated current-carrying wireline
disposed in the adjacent heater well. Alternatively, one or more of
the heater wells 210 may be formed by a method as is otherwise
described herein. A spacing between heater wells 210 may be
determined according to any of the embodiments described
herein.
[0283] In some embodiments, heated portion 310 may extend
substantially radially from heat source 300, as shown in FIG. 6.
For example, a width of heated portion 310, in a direction
extending radially from heat source 300, may be about 0 m to about
10 m. A width of heated portion 310 may vary, however, depending
upon, for example, heat provided by heat source 300 and the
characteristics of the formation. Heat provided by heat source 300
will typically transfer through the heated portion to create a
temperature gradient within the heated portion. For example, a
temperature proximate the heater well will generally be higher than
a temperature proximate an outer lateral boundary of the heated
portion. A temperature gradient within the heated portion, however,
may vary within the heated portion depending on, for example, the
thermal conductivity of the formation.
[0284] As heat transfers through heated portion 310 of the coal
formation, a temperature within at least a section of the heated
portion may be within a pyrolysis temperature range. In this
manner, as the heat transfers away from the heat source, a front at
which pyrolysis occurs will in many instances travel outward from
the heat source. For example, heat from the heat source may be
allowed to transfer into a selected section of the heated portion
such that heat from the heat source pyrolyzes at least some of the
hydrocarbons within the selected section. As such, pyrolysis may
occur within selected section 315 of the heated portion, and
pyrolyzation fluids will be generated from hydrocarbons in the
selected section. An inner lateral boundary of selected section 315
may be radially spaced from the heat source. For example, an inner
lateral boundary of selected section 315 may be radially spaced
from the heat source by about 0 m to about 1 m. In addition,
selected section 315 may have a width radially extending from the
inner lateral boundary of the selected section. For example, a
width of the selected section may be at least approximately 1.5 m,
at least approximately 2.4 m, or even at least approximately 3.0 m.
A width of the selected section, however, may also be greater than
approximately 1.5 m and less than approximately 10 m.
[0285] After pyrolyzation of hydrocarbons in a portion of the
selected section is complete, a section of spent hydrocarbons 317
may be generated proximate to the heat source.
[0286] In some embodiments, a plurality of heated portions may
exist within a unit of heat sources. A unit of heat sources refers
to a minimal number of heat sources that form a template that may
be repeated to create a pattern of heat sources within the
formation. The heat sources may be located within the formation
such that superposition (overlapping) of heat produced from the
heat sources is effective. For example, as illustrated in FIG. 7,
transfer of heat from two or more heat sources 330 results in
superposition of heat 332 to be effective within an area defined by
the unit of heat sources. Superposition may also be effective
within an interior of a region defined by two, three, four, five,
six or more heat sources. For example, an area in which
superposition of heat 332 is effective includes an area to which
significant heat is transferred by two or more heat sources of the
unit of heat sources. An area in which superposition of heat is
effective may vary depending upon, for example, the spacings
between heat sources. Superposition of heat may increase a
temperature in at least a portion of the formation to a temperature
sufficient for pyrolysis of hydrocarbon within the portion. In this
manner, superposition of heat 332 tends to increase the amount of
hydrocarbon in a formation that may be pyrolyzed. As such, a
plurality of areas that are within a pyrolysis temperature range
may exist within the unit of heat sources. The selected sections
334 may include areas at a pyrolysis temperature range due to heat
transfer from only one heat source, as well as areas at a pyrolysis
temperature range due to superposition of heat.
[0287] In addition, a pattern of heat sources will often include a
plurality of units of heat sources. There will typically be a
plurality of heated portions, as well as selected sections within
the pattern of heat sources. The plurality of heated portions and
selected sections may be configured as described herein.
Superposition of heat within a pattern of heat sources may decrease
the time necessary to reach pyrolysis temperatures within the
multitude of heated portions. Superposition of heat may allow for a
relatively large spacing between adjacent heat sources, which may
in turn provide a relatively slow rate of heating of the coal
formation. In certain embodiments, superposition of heat will also
generate fluids substantially uniformly from a heated portion of a
coal formation.
[0288] In certain embodiments, a majority of pyrolysis fluids may
be produced when the selected section is within a range from about
0 m to about 25 m from a heat source.
[0289] As shown in FIG. 3, in addition to heat sources 100, one or
more production wells 102 will typically be disposed within the
portion of the coal formation. Production well 102 may be
configured such that a mixture that may include formation fluids
may be produced through the production well. Production well 102
may also include a heat source. In this manner, the formation
fluids may be maintained at a selected temperature throughout
production, thereby allowing more or all of the formation fluids to
be produced as vapors. Therefore high temperature pumping of
liquids from the production well may be reduced or substantially
eliminated, which in turn decreases production costs. Providing
heating at or through the production well tends to: (1) prevent
condensation and/or refluxing of production fluid when such
production fluid is moving in the production well proximate to the
overburden, (2) increase heat input into the formation, and/or (3)
increase formation permeability at or proximate the production
well.
[0290] Because permeability and/or porosity increase in the heated
formation, produced vapors may flow considerable distances through
the formation with relatively little pressure differential.
Therefore, in some embodiments, production wells may be provided
near an upper surface of the formation. Increases in permeability
may result from a reduction of mass of the heated portion due to
vaporization of water, removal of hydrocarbons, and/or creation of
fractures. In this manner, fluids may more easily flow through the
heated portion.
[0291] For example, fluid generated within a coal formation may
move a considerable distance through the coal formation as a vapor.
Such a considerable distance may include, for example, about 50 m
to about 1000 m. The vapor may have a relatively small pressure
drop across the considerable distance due to the permeability of
the heated portion of the formation. In addition, due to such
permeability, a production well may only need to be provided in
every other unit of heat sources or every third, fourth, fifth,
sixth units of heat sources. Furthermore, as shown in FIG. 4,
production wells 206 may extend through a coal formation near the
top of heated portion 208.
[0292] Embodiments of production well 102 may include valves
configured to alter, maintain, and/or control a pressure of at
least a portion of the formation. Production wells may be cased
wells that may have production screens or perforated casings
adjacent to production zones. In addition, the production wells may
be surrounded by sand, gravel or other packing material adjacent to
production zones. Furthermore, production wells 102 may be coupled
to treatment section 108, as shown in FIG. 3. Treatment section 108
may include any of the surface facilities as described herein.
[0293] In addition, water pumping wells or vacuum wells may be
configured to remove liquid water from a portion of a coal
formation to be heated. Water removed from the formation may be
used on the surface, and/or monitored for water quality. For
example, a plurality of water wells may surround all or a portion
of a formation to be heated. The plurality of water wells may be
configured in one or more rings surrounding the portion of the
formation. An outermost row of water wells may inhibit a
significant amount of water from flowing into the portion to be
heated. An innermost row of water wells may inhibit water that
bypasses the outermost row from flowing into the portion to be
heated. The innermost row of water wells may also inhibit outward
migration of vapor from a heated portion of the formation into
surrounding portions of the formation. In this manner, the water
wells may reduce heat loss to surrounding portions of the
formation, may increase production of vapors from the heated
portion, and may inhibit contamination of a water table proximate
to the heated portion of the formation. In some embodiments
pressure differences between successive rows of dewatering wells
may be minimized (e.g., maintained or near zero) to create a "no or
low flow" boundary between rows.
[0294] In certain embodiments, wells initially used for one purpose
may be later used for one or more other purposes, thereby lowering
project costs and/or decreasing the time required to perform
certain tasks. For instance, production wells (and in some
circumstances heater wells) may initially be used as dewatering
wells (e.g., before heating is begun and/or when heating is
initially started). In addition, in some circumstances dewatering
wells can later be used as production wells (and in some
circumstances heater wells). As such, the dewatering wells may be
placed and/or designed so that such wells can be later used as
production wells and/or heater wells. The heater wells may be
placed and/or designed so that such wells can be later used as
production wells and/or dewatering wells. The production wells may
be placed and/or designed so that such wells can be later used as
dewatering wells and/or heater wells. Similarly, injection wells
may be wells that initially were used for other purposes (e.g.,
heating, production, dewatering, monitoring, etc.), and injection
wells may later be used for other purposes. Similarly, monitoring
wells may be wells that initially were used for other purposes
(e.g., heating, production, dewatering, injection, etc.), and
monitoring wells may later be used for other purposes.
[0295] FIG. 8 illustrates a pattern of heat sources 400 and
production wells 402 that may be configured to treat a coal
formation. Heat sources 400 may be arranged in a unit of heat
sources such as triangular pattern 401. Heat sources 400, however,
may be arranged in a variety of patterns including, but not limited
to, squares, hexagons, and other polygons. The pattern may include
a regular polygon to promote uniform heating through at least the
portion of the formation in which the heat sources are placed. The
pattern may also be a line drive pattern. A line drive pattern is
defined to include at least one linear array of heater wells
configured to heat at least a portion of a formation such that
fluids may be produced from at least one production well. A line
drive pattern may also include a first linear array of heater
wells, a second linear array of heater wells, and a production well
or a linear array of production wells between the first and second
linear array of heater wells.
[0296] A distance from a node of a polygon to a centroid of the
polygon is smallest for a 3 sided polygon and increases with
increasing number of sides of the polygon. The distance from a node
to the centroid for an equilateral triangle is (length/2)/(square
root(3)/2) or 0.5774 times the length. For a square, the distance
from a node to the centroid is (length/2)/(square root(2)/2) or
0.7071 times the length. For a hexagon, the distance from a node to
the centroid is (length/2)/(1/2) or the length. The difference in
distance between a heat source and a mid point to a second heat
sources (length/2) and the distance from a heat source to the
centroid for an equilateral pattern (0.5774 times the length) is
significantly less for the equilateral triangle pattern than for
any higher order polygon pattern. The small difference means that
superposition of heat may develop more rapidly and that formation
between heat sources may rise to a substantially more uniform
temperature using an equilateral triangle pattern rather than a
higher order polygon pattern.
[0297] Triangular patterns tend to provide more uniform heating to
a portion of the formation in comparison to other patterns such as
squares and/or hexagons. Triangular patterns tend to provide faster
heating to a predetermined temperature in comparison to other
patterns such as squares and/or hexagons. Triangle patterns may
also result in a small volume of the portion that is overheated. A
plurality of units of heat sources such as triangular pattern 401
may be arranged substantially adjacent to each other to form a
repetitive pattern of units over an area of the formation. For
example, triangular patterns 401 may be arranged substantially
adjacent to each other in a repetitive pattern of units by
inverting an orientation of adjacent triangles 401. Other patterns
of heat sources 400 may also be arranged such that smaller patterns
may be disposed adjacent to each other to form larger patterns.
[0298] Production wells may be disposed in the formation in a
repetitive pattern of units. In certain embodiments, production
well 402 may be disposed proximate to a center of every third
triangle 401 arranged in the pattern. Production well 402, however,
may be disposed in every triangle 401 or within just a few
triangles. A production well may be placed within every 13, 20, or
30 heater well triangles. For example, a ratio of heat sources in
the repetitive pattern of units to production wells in the
repetitive pattern of units may be more than approximately 5 (e.g.,
more than 6, 7, 8, or 9). In addition, the placement of production
well 402 may vary depending on the heat generated by one or more
heat sources 400 and the characteristics of the formation (such as
permeability). Furthermore, three or more production wells may be
located within an area defined by a repetitive pattern of units.
For example, as shown in FIG. 8, production wells 410 may be
located within an area defined by repetitive pattern of units 412.
Production wells 410 may be located in the formation in a unit of
production wells. For example, the unit of production wells may be
a triangular pattern. Production wells 410, however, may be
disposed in another pattern within repetitive pattern of units
412.
[0299] In addition, one or more injection wells may be disposed
within a repetitive pattern of units. The injection wells may be
configured as described herein. For example, as shown in FIG. 8,
injection wells 414 may be located within an area defined by
repetitive pattern of units 416. Injection wells 414 may also be
located in the formation in a unit of injection wells. For example,
the unit of injection wells may be a triangular pattern. Injection
wells 414, however, may be disposed in any other pattern as
described herein. In certain embodiments, one or more production
wells and one or more injection wells may be disposed in a
repetitive pattern of units. For example, as shown in FIG. 8,
production wells 418 and injection wells 420 may be located within
an area defined by repetitive pattern of units 422. Production
wells 418 may be located in the formation in a unit of production
wells, which may be arranged in a first triangular pattern. In
addition, injection wells 420 may be located within the formation
in a unit of production wells, which may be arranged in a second
triangular pattern. The first triangular pattern may be
substantially different than the second triangular pattern. For
example, areas defined by the first and second triangular patterns
may be substantially different.
[0300] In addition, one or more monitoring wells may be disposed
within a repetitive pattern of units. The monitoring wells may be
configured as described herein. For example, the wells may be
configured with one or more devices that measure a temperature, a
pressure, and/or a property of a fluid. In some embodiments,
logging tools may be placed in monitoring well wellbores to measure
properties within a formation. The logging tools may be moved to
other monitoring well wellbores as needed. The monitoring well
wellbores may be cased or uncased wellbores. As shown in FIG. 8,
monitoring wells 424 may be located within an area defined by
repetitive pattern of units 426. Monitoring wells 424 may be
located in the formation in a unit of monitoring wells, which may
be arranged in a triangular pattern. Monitoring wells 424, however,
may be disposed in any of the other patterns as described herein
within repetitive pattern of units 426.
[0301] It is to be understood that a geometrical pattern of heat
sources 400 and production wells 402 is described herein by
example. A pattern of heat sources and production wells will in
many instances vary depending on, for example, the type of coal
formation to be treated. For example, for relatively thin layers
heating wells may be aligned along one or more layers along strike
or along dip. For relatively thick layers, heat sources may be
configured at an angle to one or more layers (e.g., orthogonally or
diagonally).
[0302] A triangular pattern of heat sources may be configured to
treat a coal formation having a thickness of about 10 meters or
more. For a thinner coal formation, e.g., about 10 meters thick or
less, a line and/or staggered line pattern of heat sources may be
configured to treat the coal formation.
[0303] For certain thinner formations, heating wells may be placed
closer to an edge of the coal formation (e.g., in a staggered line
instead of line placed in the center of the layer) of the formation
to increase the amount of hydrocarbons produced per unit of energy
input. A portion of input heating energy may heat non-hydrocarbon
containing formation, but the staggered pattern may allow
superposition of heat to heat a majority of the coal formation to
pyrolysis temperatures. If the thin formation is heated by placing
one or more heater wells in the formation along a center of the
thickness, a significant portion of the coal formation may not be
heated to pyrolysis temperatures. In some embodiments, placing
heater wells closer to an edge of the formation may increase the
volume of formation undergoing pyrolysis per unit of energy
input.
[0304] In addition, the location of production well 402 within a
pattern of heat sources 400 may be determined by, for example, a
desired heating rate of the coal formation, a heating rate of the
heat sources, the type of heat sources used, the type of coal
formation (and its thickness), the composition of the coal
formation, the desired composition to be produced from the
formation, and/or a desired production rate. Exact placement of
heater wells, production wells, etc. will depend on variables
specific to the formation (e.g., thickness of the layer,
composition of the layer, etc.), project economics, etc. In certain
embodiments heater wells may be substantially horizontal while
production wells may be vertical, or vice versa.
[0305] Any of the wells described herein may be aligned along dip
or strike, or oriented at an angle between dip and strike.
[0306] The spacing between heat sources may also vary depending on
a number of factors that may include, but are not limited to, the
type of a coal formation, the selected heating rate, and/or the
selected average temperature to be obtained within the heated
portion. For example, the spacing between heat sources may be
within a range of about 5 m to about 25 m. Alternatively, the
spacing between heat sources may be within a range of about 8 m to
about 15 m.
[0307] The spacing between heat sources may influence the
composition of fluids produced from a coal formation. In an
embodiment, a computer-implemented method may be used to determine
optimum heat source spacings within a coal formation. For example,
at least one property of a portion of coal formation can usually be
measured. The measured property may include, but is not limited to,
vitrinite reflectance, hydrogen content, atomic hydrogen to carbon
ratio, oxygen content, atomic oxygen to carbon ratio, water
content, thickness of the coal formation, and/or the amount of
stratification of the coal formation into separate layers of rock
and hydrocarbons.
[0308] In certain embodiments a computer-implemented method may
include providing at least one measured property to a computer
system. One or more sets of heat source spacings in the formation
may also be provided to the computer system. For example, a spacing
between heat sources may be less than about 30 m. Alternatively, a
spacing between heat sources may be less than about 15 m. The
method may also include determining properties of fluids produced
from the portion as a function of time for each set of heat source
spacings. The produced fluids include, but are not limited to,
formation fluids such as pyrolyzation fluids and synthesis gas. The
determined properties may include, but are not limited to, API
gravity, carbon number distribution, olefin content, hydrogen
content, carbon monoxide content, and/or carbon dioxide content.
The determined set of properties of the produced fluid may be
compared to a set of selected properties of a produced fluid. In
this manner, sets of properties that match the set of selected
properties may be determined. Furthermore, heat source spacings may
be matched to heat source spacings associated with desired
properties.
[0309] Unit cell 404 will often include a number of heat sources
400 disposed within a formation around each production well 402. An
area of unit cell 404 may be determined by midlines 406 that may be
equidistant and perpendicular to a line connecting two production
wells 402. Vertices 408 of the unit cell may be at the intersection
of two midlines 406 between production wells 402. Heat sources 400
may be disposed in any arrangement within the area of unit cell
404. For example, heat sources 400 may be located within the
formation such that a distance between each heat source varies by
less than approximately 10%, 20%, or 30%. In addition, heat sources
400 may be disposed such that an approximately equal space exists
between each of the heat sources. Other arrangements of heat
sources 400 within unit cell 404, however, may be used depending
on, for example, a heating rate of each of the heat sources. A
ratio of heat sources 400 to production wells 402 may be determined
by counting the number of heat sources 400 and production wells 402
within unit cell 404, or over the total field.
[0310] FIG. 9 illustrates an embodiment of unit cell 404. Unit cell
404 includes heat sources 400 and production wells 402. Unit cell
404 may have six full heat sources 400a and six partial heat
sources 400b. Full heat sources 400a may be closer to production
well 402 than partial heat sources 400b. In addition, an entirety
of each of the full heat sources 400 may be located within unit
cell 404. Partial heat sources 400b may be partially disposed
within unit cell 404. Only a portion of heat source 400b disposed
within unit cell 404 may be configured to provide heat to a portion
of a coal formation disposed within unit cell 404. A remaining
portion of heat source 400b disposed outside of unit cell 404 may
be configured to provide heat to a remaining portion of the coal
formation outside of unit cell 404. Therefore, to determine a
number of heat sources within unit cell 404 partial heat source
400b may be counted as one-half of full heat sources 400. In other
unit cell embodiments, fractions other than 1/2 (e.g. 1/3) may more
accurately describe the amount of heat applied to a portion from a
partial heat source.
[0311] The total number of heat sources 400 in unit cell 404 may
include six full heat sources 400a that are each counted as one
heat source, and six partial heat sources 400b that are each
counted as one half of a heat source. Therefore, a ratio of heat
sources 400 to production wells 402 in unit cell 404 may be
determined as 9:1. A ratio of heat sources to production wells may
vary, however, depending on, for example, the desired heating rate
of the coal formation, the heating rate of the heat sources, the
type of heat source, the type of coal formation, the composition of
coal formation, the desired composition of the produced fluid,
and/or the desired production rate. Providing more heat sources
wells per unit area will allow faster heating of the selected
portion and thus hastening the onset of production, however more
heat sources will generally cost more money to install. An
appropriate ratio of heat sources to production wells may also
include ratios greater than about 5:1, and ratios greater than
about 7:1. In some embodiments an appropriate ratio of heat sources
to production wells may be about 10:1, 20:1, 50:1 or greater. If
larger ratios are used, then project costs tend to decrease since
less wells and equipment are needed.
[0312] A "selected section" would generally be the volume of
formation that is within a perimeter defined by the location of the
outermost heat sources (assuming that the formation is viewed from
above). For example, if four heat sources were located in a single
square pattern with an area of about 100 m.sup.2 (with each source
located at a corner of the square), and if the formation had an
average thickness of approximately 5 m across this area, then the
selected section would be a volume of about 500 m.sup.3 (i.e., the
area multiplied by the average formation thickness across the
area). In many commercial applications, it is envisioned that many
(e.g., hundreds or thousands) heat sources would be adjacent to
each other to heat a selected section, and therefore in such cases
only the outermost (i.e., the "edge") heat sources would define the
perimeter of the selected section.
[0313] A heat source may include, but is not limited to, an
electric heater or a combustion heater. The electric heater may
include an insulated conductor, an elongated member disposed in the
opening, and/or a conductor disposed in a conduit. Such an electric
heater may be configured according to any of the embodiments
described herein.
[0314] In an embodiment, a coal formation may be heated with a
natural distributed combustor system located in the formation. The
generated heat may be allowed to transfer to a selected section of
the formation to heat it.
[0315] A temperature sufficient to support oxidation may be, for
example, at least about 200.degree. C. or 250.degree. C. The
temperature sufficient to support oxidation will tend to vary,
however, depending on, for example, a composition of the
hydrocarbons in the coal formation, water content of the formation,
and/or type and amount of oxidant. Some water may be removed from
the formation prior to heating. For example, the water may be
pumped from the formation by dewatering wells. The heated portion
of the formation may be near or substantially adjacent to an
opening in the coal formation. The opening in the formation may be
a heater well formed in the formation. The heater well may be
formed as in any of the embodiments described herein. The heated
portion of the coal formation may extend radially from the opening
to a width of about 0.3 m to about 1.2 m. The width, however, may
also be less than about 0.9 m. A width of the heated portion may
vary. In certain embodiments the variance will depend on, for
example, a width necessary to generate sufficient heat during
oxidation of carbon to maintain the oxidation reaction without
providing heat from an additional heat source.
[0316] After the portion of the formation reaches a temperature
sufficient to support oxidation, an oxidizing fluid may be provided
into the opening to oxidize at least a portion of the hydrocarbons
at a reaction zone, or a heat source zone, within the formation.
Oxidation of the hydrocarbons will generate heat at the reaction
zone. The generated heat will in most embodiments transfer from the
reaction zone to a pyrolysis zone in the formation. In certain
embodiments the generated heat will transfer at a rate between
about 650 watts per meter as measured along a depth of the reaction
zone, and/or 1650 watts per meter as measured along a depth of the
reaction zone. Upon oxidation of at least some of the hydrocarbons
in the formation, energy supplied to the heater for initially
heating may be reduced or may be turned off. As such, energy input
costs may be significantly reduced, thereby providing a
significantly more efficient system for heating the formation.
[0317] In an embodiment, a conduit may be disposed in the opening
to provide the oxidizing fluid into the opening. The conduit may
have flow orifices, or other flow control mechanisms (i.e., slits,
venturi meters, valves, etc.) to allow the oxidizing fluid to enter
the opening. The term "orifices" includes openings having a wide
variety of cross-sectional shapes including, but not limited to,
circles, ovals, squares, rectangles, triangles, slits, or other
regular or irregular shapes. The flow orifices may be critical flow
orifices in some embodiments. The flow orifices may be configured
to provide a substantially constant flow of oxidizing fluid into
the opening, regardless of the pressure in the opening.
[0318] In some embodiments, the number of flow orifices, which may
be formed in or coupled to the conduit, may be limited by the
diameter of the orifices and a desired spacing between orifices for
a length of the conduit. For example, as the diameter of the
orifices decreases, the number of flow orifices may increase, and
vice versa. In addition, as the desired spacing increases, the
number of flow orifices may decrease, and vice versa. The diameter
of the orifices may be determined by, for example, a pressure in
the conduit and/or a desired flow rate through the orifices. For
example, for a flow rate of about 1.7 standard cubic meters per
minute and a pressure of about 7 bar absolute, an orifice diameter
may be about 1.3 mm with a spacing between orifices of about 2
m.
[0319] Smaller diameter orifices may plug more easily than larger
diameter orifices due to, for example, contamination of fluid in
the opening or solid deposition within or proximate to the
orifices. In some embodiments, the number and diameter of the
orifices can be chosen such that a more even or nearly uniform
heating profile will be obtained along a depth of the formation
within the opening. For example, a depth of a heated formation that
is intended to have an approximately uniform heating profile may be
greater than about 300 m, or even greater than about 600 m. Such a
depth may vary, however, depending on, for example, a type of
formation to be heated and/or a desired production rate.
[0320] In some embodiments, flow orifices may be disposed in a
helical pattern around the conduit within the opening. The flow
orifices may be spaced by about 0.3 m to about 3 m between orifices
in the helical pattern. In some embodiments, the spacing may be
about 1 m to about 2 m or, for example, about 1.5 m.
[0321] The flow of the oxidizing fluid into the opening may be
controlled such that a rate of oxidation at the reaction zone is
controlled. Transfer of heat between incoming oxidant and outgoing
oxidation products may heat the oxidizing fluid. The transfer of
heat may also maintain the conduit below a maximum operating
temperature of the conduit.
[0322] FIG. 10 illustrates an embodiment of a natural distributed
combustor configured to heat a coal formation. Conduit 512 may be
placed into opening 514 in formation 516. Conduit 512 may have
inner conduit 513. Oxidizing fluid source 508 may provide oxidizing
fluid 517 into inner conduit 513. Inner conduit 513 may have
critical flow orifices 515 along its length. Critical flow orifices
515 may be disposed in a helical pattern (or any other pattern)
along a length of inner conduit 513 in opening 514. For example,
critical flow orifices 515 may be arranged in a helical pattern
with a distance of about 1 m to about 2.5 m between adjacent
orifices. Critical flow orifices 515 may be further configured as
described herein. Inner conduit 513 may be sealed at the bottom.
Oxidizing fluid 517 may be provided into opening 514 through
critical flow orifices 515 of inner conduit 513.
[0323] Critical flow orifices 515 may be designed such that
substantially the same flow rate of oxidizing fluid 517 may be
provided through each critical flow orifice. Critical flow orifices
515 may also provide substantially uniform flow of oxidizing fluid
517 along a length of conduit 512. Such flow may provide
substantially uniform heating of formation 516 along the length of
conduit 512. Packing material 542 may enclose conduit 512 in
overburden 540 of the formation.
[0324] Packing material 542 may substantially inhibit flow of
fluids from opening 514 to surface 550. Packing material 542 may
include any material configurable to inhibit flow of fluids to
surface 550 such as cement, sand, and/or gravel. Typically a
conduit or an opening in the packing remains to provide a path for
oxidation products to reach the surface.
[0325] Oxidation products 519 typically enter conduit 512 from
opening 514. Oxidation products 519 may include carbon dioxide,
oxides of nitrogen, oxides of sulfur, carbon monoxide, and/or other
products resulting from a reaction of oxygen with hydrocarbons
and/or carbon. Oxidation products 519 may be removed through
conduit 512 to surface 550. Oxidation product 519 may flow along a
face of reaction zone 524 in opening 514 until proximate an upper
end of opening 514 where oxidation product 519 may flow into
conduit 512. Oxidation products 519 may also be removed through one
or more conduits disposed in opening 514 and/or in formation 516.
For example, oxidation products 519 may be removed through a second
conduit disposed in opening 514. Removing oxidation products 519
through a conduit may substantially inhibit oxidation products 519
from flowing to a production well disposed in formation 516.
Critical flow orifices 515 may also be configured to substantially
inhibit oxidation products 519 from entering inner conduit 513.
[0326] A flow rate of oxidation product 519 may be balanced with a
flow rate of oxidizing fluid 517 such that a substantially constant
pressure is maintained within opening 514. For a 100 m length of
heated section, a flow rate of oxidizing fluid may be between about
0.5 standard cubic meters per minute to about 5 standard cubic
meters per minute, or about 1.0 standard cubic meters per minute to
about 4.0 standard cubic meters per minute, or, for example, about
1.7 standard cubic meters per minute. A flow rate of oxidizing
fluid into the formation may be incrementally increased during use
to accommodate expansion of the reaction zone. A pressure in the
opening may be, for example, about 8 bar absolute. Oxidizing fluid
517 may oxidize at least a portion of the hydrocarbons in heated
portion 518 of coal formation 516 at reaction zone 524. Heated
portion 518 may have been initially heated to a temperature
sufficient to support oxidation by an electric heater, as shown in
FIG. 14, or by any other suitable system or method described
herein. In some embodiments, an electric heater may be placed
inside or strapped to the outside of conduit 513.
[0327] In certain embodiments it is beneficial to control the
pressure within the opening 514 such that oxidation product and/or
oxidation fluids are inhibited from flowing into the pyrolysis zone
of the formation. In some instances pressure within opening 514
will be balanced with pressure within the formation to do so.
[0328] Although the heat from the oxidation is transferred to the
formation, oxidation product 519 (and excess oxidation fluid such
as air) may be substantially inhibited from flowing through the
formation and/or to a production well within formation 516. Instead
oxidation product 519 (and excess oxidation fluid) is removed
(e.g., through a conduit such as conduit 512) as is described
herein. In this manner, heat is transferred to the formation from
the oxidation but exposure of the pyrolysis zone with oxidation
product 519 and/or oxidation fluid may be substantially inhibited
and/or prevented.
[0329] In certain embodiments, some pyrolysis product near the
reaction zone 524 may also be oxidized in reaction zone 524 in
addition to the carbon. Oxidation of the pyrolysis product in
reaction zone 524 may provide additional heating of formation 516.
When such oxidation of pyrolysis product occurs, it is desirable
that oxidation product from such oxidation be removed (e.g.,
through a conduit such as conduit 512) near the reaction zone as is
described herein, thereby inhibiting contamination of other
pyrolysis product in the formation with oxidation product.
[0330] Conduit 512 may be configured to remove oxidation product
519 from opening 514 in formation 516. As such, oxidizing fluid 517
in inner conduit 513 may be heated by heat exchange in overburden
section 540 from oxidation product 519 in conduit 512. Oxidation
product 519 may be cooled by transferring heat to oxidizing fluid
517. In this manner, oxidation of hydrocarbons within formation 516
may be more thermally efficient.
[0331] Oxidizing fluid 517 may transport through reaction zone 524,
or heat source zone, by gas phase diffusion and/or convection.
Diffusion of oxidizing fluid 517 through reaction zone 524 may be
more efficient at the relatively high temperatures of oxidation.
Diffusion of oxidizing fluid 517 may inhibit development of
localized overheating and fingering in the formation. Diffusion of
oxidizing fluid 517 through formation 516 is generally a mass
transfer process. In the absence of an external force, a rate of
diffusion for oxidizing fluid 517 may depend upon concentration,
pressure, and/or temperature of oxidizing fluid 517 within
formation 516. The rate of diffusion may also depend upon the
diffusion coefficient of oxidizing fluid 517 through formation 516.
The diffusion coefficient may be determined by measurement or
calculation based on the kinetic theory of gases. In general,
random motion of oxidizing fluid 517 may transfer oxidizing fluid
517 through formation 516 from a region of high concentration to a
region of low concentration.
[0332] With time, reaction zone 524 may slowly extend radially to
greater diameters from opening 514 as hydrocarbons are oxidized.
Reaction zone 524 may, in many embodiments, maintain a relatively
constant width. For example, reaction zone 524 may extend radially
at a rate of less than about 0.91 m per year for a coal formation.
For example, for a coal formation, reaction zone 524 may extend
radially at a rate between about 0.5 m per year to about 1 m per
year. Reaction zone 524 may extend at slower rates for hydrocarbon
rich formations since more hydrocarbons per volume are available
for combustion in the hydrocarbon rich formations.
[0333] A flow rate of oxidizing fluid 517 into opening 514 may be
increased as a diameter of reaction zone 524 increases to maintain
the rate of oxidation per unit volume at a substantially steady
state. Thus, a temperature within reaction zone 524 may be
maintained substantially constant in some embodiments. The
temperature within reaction zone 524 may be between about
650.degree. C. to about 900.degree. C. or, for example, about
760.degree. C. The temperature may be maintained below a
temperature that results in production of oxides of nitrogen
(NO.sub.x).
[0334] The temperature within reaction zone 524 may vary depending
on, for example, a desired heating rate of selected section 526.
The temperature within reaction zone 524 may be increased or
decreased by increasing or decreasing, respectively, a flow rate of
oxidizing fluid 517 into opening 514. A temperature of conduit 512,
inner conduit 513, and/or any metallurgical materials within
opening 514 typically will not exceed a maximum operating
temperature of the material. Maintaining the temperature below the
maximum operating temperature of a material may inhibit excessive
deformation and/or corrosion of the material.
[0335] An increase in the diameter of reaction zone 524 may allow
for relatively rapid heating of the coal formation 516. As the
diameter of reaction zone 524 increases, an amount of heat
generated per time in reaction zone 524 may also increase.
Increasing an amount of heat generated per time in the reaction
zone will in many instances increase the heating rate of the
formation 516 over a period of time, even without increasing the
temperature in the reaction zone or the temperature at conduit 513.
Thus, increased heating may be achieved over time without
installing additional heat sources, and without increasing
temperatures adjacent to wellbores. In some embodiments the heating
rates may be increased while allowing the temperatures to decrease
(allowing temperatures to decrease may often lengthen the life of
the equipment used).
[0336] By utilizing the carbon in the formation as a fuel, the
natural distributed combustor may save significantly on energy
costs. Thus, an economical process may be provided for heating
formations that may otherwise be economically unsuitable for
heating by other methods. Also, fewer heaters may be placed over an
extended area of formation 516. This may provide for a reduced
equipment cost associated with heating the formation 516.
[0337] The heat generated at reaction zone 524 may transfer by
thermal conduction to selected section 526 of formation 516. In
addition, generated heat may transfer from a reaction zone to the
selected section to a lesser extent by convection heat transfer.
Selected section 526, sometimes referred to herein as the
"pyrolysis zone," may be substantially adjacent to reaction zone
524. Since oxidation product (and excess oxidation fluid such as
air) is typically removed from the reaction zone, the pyrolysis
zone can receive heat from the reaction zone without being exposed
to oxidation product, or oxidants, that are in the reaction zone.
Oxidation product and/or oxidation fluids may cause the formation
of undesirable formation products if they are present in the
pyrolysis zone. For example, in certain embodiments it is desirable
to conduct pyrolysis in a reducing environment. Thus, it is often
useful to allow heat to transfer from the reaction zone to the
pyrolysis zone while inhibiting or preventing oxidation product
and/or oxidation fluid from reaching the pyrolysis zone.
[0338] Pyrolysis of hydrocarbons, or other heat-controlled
processes, may take place in heated selected section 526. Selected
section 526 may be at a temperature between about 270.degree. C. to
about 400.degree. C. for pyrolysis. The temperature of selected
section 526 may be increased by heat transfer from reaction zone
524. A rate of temperature increase may be selected as in any of
the embodiments described herein. A temperature in formation 516,
selected section 526, and/or reaction zone 524 may be controlled
such that production of oxides of nitrogen may be substantially
inhibited. Oxides of nitrogen are often produced at temperatures
above about 1200.degree. C.
[0339] A temperature within opening 514 may be monitored with a
thermocouple disposed in opening 514. The temperature within
opening 514 may be monitored such that a temperature may be
maintained within a selected range. The selected range may vary,
depending on, for example, a desired heating rate of formation 516.
A temperature may be maintained within a selected range by
increasing or decreasing a flow rate of oxidizing fluid 517. For
example, if a temperature within opening 514 falls below a selected
range of temperatures, the flow rate of oxidizing fluid 517 may be
increased to increase the combustion and thereby increase the
temperature within opening 514. Alternatively, a thermocouple may
be disposed on conduit 512 and/or disposed on a face of reaction
zone 524, and a temperature may be monitored accordingly.
[0340] In certain embodiments one or more natural distributed
combustors may be placed along strike and/or horizontally. Doing so
tends to reduce pressure differentials along the heated length of
the well, thereby tending to promote more uniform heating and
improved control.
[0341] In some embodiments, a presence of air or molecular oxygen,
O.sub.2 , in oxidation product 519 may be monitored. Alternatively,
an amount of nitrogen, carbon monoxide, carbon dioxide, oxides of
nitrogen, oxides of sulfur, etc. may be monitored in oxidation
product 519. Monitoring the composition and/or quantity of
oxidation product 519 may be useful for heat balances, for process
diagnostics, process control, etc.
[0342] FIG. 11 illustrates an embodiment of a section of overburden
with a natural distributed combustor as described in FIG. 10.
Overburden casing 541 may be disposed in overburden 540 of
formation 516. Overburden casing 541 may be substantially
surrounded by materials (e.g., an insulating material such as
cement) that may substantially inhibit heating of overburden 540.
Overburden casing 541 may be made of a metal material such as, but
not limited to, carbon steel.
[0343] Overburden casing may be placed in reinforcing material 544
in overburden 540. Reinforcing material 544 may be, for example,
cement, sand, concrete, etc. Packing material 542 may be disposed
between overburden casing 541 and opening 514 in the formation.
Packing material 542 may be any substantially non-porous material
(e.g., cement, concrete, grout, etc.). Packing material 542 may
inhibit flow of fluid outside of conduit 512 and between opening
514 and surface 550. Inner conduit 513 may provide a fluid into
opening 514 in formation 516. Conduit 512 may remove a combustion
product (or excess oxidation fluid) from opening 514 in formation
516. Diameter of conduit 512 may be determined by an amount of the
combustion product produced by oxidation in the natural distributed
combustor. For example, a larger diameter may be required for a
greater amount of exhaust product produced by the natural
distributed combustor heater.
[0344] In an alternative embodiment, at least a portion of the
formation may be heated to a temperature such that at least a
portion of the coal formation may be converted to coke and/or char.
Coke and/or char may be formed at temperatures above about
400.degree. C. and at a high heating rate (e.g., above about
10.degree. C./day). In the presence of an oxidizing fluid, the coke
or char will oxidize. Heat may be generated from the oxidation of
coke or char as in any of the embodiments described herein.
[0345] FIG. 12 illustrates an embodiment of a natural distributed
combustor heater. Insulated conductor 562 may be coupled to conduit
532 and placed in opening 514 in formation 516. Insulated conductor
562 may be disposed internal to conduit 532 (thereby allowing
retrieval of the insulated conductor 562), or, alternately, coupled
to an external surface of conduit 532. Such insulating material may
include, for example, minerals, ceramics, etc. Conduit 532 may have
critical flow orifices 515 disposed along its length within opening
514. Critical flow orifices 515 may be configured as described
herein. Electrical current may be applied to insulated conductor
562 to generate radiant heat in opening 514. Conduit 532 may be
configured to serve as a return for current. Insulated conductor
562 may be configured to heat portion 518 of the formation to a
temperature sufficient to support oxidation of hydrocarbons.
Portion 518, reaction zone 524, and selected section 526 may have
characteristics as described herein. Such a temperature may include
temperatures as described herein.
[0346] Oxidizing fluid source 508 may provide oxidizing fluid into
conduit 532. Oxidizing fluid may be provided into opening 514
through critical flow orifices 515 in conduit 532. Oxidizing fluid
may oxidize at least a portion of the coal formation in at reaction
zone 524. Reaction zone 524 may have characteristics as described
herein. Heat generated at reaction zone 524 may transfer heat to
selected section 526, for example, by convection, radiation, and/or
conduction. Oxidation product may be removed through a separate
conduit placed in opening 514 or through an opening 543 in
overburden casing 541. The separate conduit may be configured as
described herein. Packing material 542 and reinforcing material 544
may be configured as described herein.
[0347] FIG. 13 illustrates an embodiment of a natural distributed
combustor heater with an added fuel conduit. Fuel conduit 536 may
be disposed into opening 514. It may be disposed substantially
adjacent to conduit 533 in certain embodiments. Fuel conduit 536
may have critical flow orifices 535 along its length within opening
514. Conduit 533 may have critical flow orifices 515 along its
length within opening 514. Critical flow orifices 515 may be
configured as described herein. Critical flow orifices 535 and
critical flow orifices 515 may be placed on fuel conduit 536 and
conduit 533, respectively, such that a fuel fluid provided through
fuel conduit 536 and an oxidizing fluid provided through conduit
533 may not substantially heat fuel conduit 536 and/or conduit 533
upon reaction. For example, the fuel fluid and the oxidizing fluid
may react upon contact with each other, thereby producing heat from
the reaction. The heat from this reaction may heat fuel conduit 536
and/or conduit 533 to a temperature sufficient to substantially
begin melting metallurgical materials in fuel conduit 536 and/or
conduit 533 if the reaction takes place proximate to fuel conduit
536 and/or conduit 533. Therefore, a design for disposing critical
flow orifices 535 on fuel conduit 536 and critical flow orifices
515 on conduit 533 may be provided such that the fuel fluid and the
oxidizing fluid may not substantially react proximate to the
conduits. For example, conduits 536 and 533 may be mechanically
coupled such that orifices are oriented in opposite directions, and
such that the orifices face the formation 516.
[0348] Reaction of the fuel fluid and the oxidizing fluid may
produce heat. The fuel fluid and the oxidizing fluid may have
characteristics herein. The fuel fluid may be, for example, natural
gas, ethane, hydrogen or synthesis gas that is generated in the in
situ process in another part of the formation. The produced heat
may be configured to heat portion 518 to a temperature sufficient
to support oxidation of hydrocarbons. Upon heating of portion 518
to a temperature sufficient to support oxidation, a flow of fuel
fluid into opening 514 may be turned down or may be turned off.
Alternatively, the supply of fuel may be continued throughout the
heating of the formation, thereby utilizing the stored heat in the
carbon to maintain the temperature in opening 514 above the
autoignition temperature of the fuel.
[0349] The oxidizing fluid may oxidize at least a portion of the
hydrocarbons at reaction zone 524. Generated heat will transfer
heat to selected section 526, for example, by radiation,
convection, and/or conduction. An oxidation product may be removed
through a separate conduit placed in opening 514 or through an
opening 543 in overburden casing 541. Packing material 542 and
reinforcing material 544 may be configured as herein.
[0350] FIG. 14 illustrates an embodiment of a system configured to
heat a coal formation. Electric heater 510 may be disposed within
opening 514 in coal formation 516. Opening 514 may be formed
through overburden 540 into formation 516. Opening 514 may be at
least about 5 cm in diameter. Opening 514 may, as an example, have
a diameter of about 13 cm. Electric heater 510 may heat at least
portion 518 of coal formation 516 to a temperature sufficient to
support oxidation (e.g., about 260.degree. C.). Portion 518 may
have a width of about 1 m. An oxidizing fluid (e.g., liquid or gas)
may be provided into the opening through conduit 512 or any other
appropriate fluid transfer mechanism. Conduit 512 may have critical
flow orifices 515 disposed along a length of the conduit. Critical
flow orifices 515 may be configured as described herein.
[0351] For example, conduit 512 may be a pipe or tube configured to
provide the oxidizing fluid into opening 514 from oxidizing fluid
source 508. For example, conduit 512 may be a stainless steel tube.
The oxidizing fluid may include air or any other oxygen containing
fluid (e.g., hydrogen peroxide, oxides of nitrogen, ozone).
Mixtures of oxidizing fluids may be used. An oxidizing fluid
mixture may include, for example, a fluid including fifty percent
oxygen and fifty percent nitrogen. The oxidizing fluid may also, in
some embodiments, include compounds that release oxygen when heated
as described herein such as hydrogen peroxide. The oxidizing fluid
may oxidize at least a portion of the hydrocarbons in the
formation.
[0352] In some embodiments, a heat exchanger disposed external to
the formation may be configured to heat the oxidizing fluid. The
heated oxidizing fluid may be provided into the opening from
(directly or indirectly) the heat exchanger. For example, the
heated oxidizing fluid may be provided from the heat exchanger into
the opening through a conduit disposed in the opening and coupled
to the heat exchanger. In some embodiments the conduit may be a
stainless steel tube. The heated oxidizing fluid may be configured
to heat, or at least contribute to the heating of, at least a
portion of the formation to a temperature sufficient to support
oxidation of hydrocarbons. After the heated portion reaches such a
temperature, heating of the oxidizing fluid in the heat exchanger
may be reduced or may be turned off.
[0353] FIG. 15 illustrates another embodiment of a system
configured to heat a coal formation. Heat exchanger 520 may be
disposed external to opening 514 in coal formation 516. Opening 514
may be formed through overburden 540 into formation 516. Heat
exchanger 520 may provide heat from another surface process, or it
may include a heater (e.g., an electric or combustion heater).
Oxidizing fluid source 508 may provide an oxidizing fluid to heat
exchanger 520. Heat exchanger 520 may heat an oxidizing fluid
(e.g., above 200.degree. C. or a temperature sufficient to support
oxidation of hydrocarbons). The heated oxidizing fluid may be
provided into opening 514 through conduit 521. Conduit 521 may have
critical flow orifices 515 disposed along a length of the conduit.
Critical flow orifices 515 may be configured as described herein.
The heated oxidizing fluid may heat, or at least contribute to the
heating of, at least portion 518 of the formation to a temperature
sufficient to support oxidation of hydrocarbons. The oxidizing
fluid may oxidize at least a portion of the hydrocarbons in the
formation.
[0354] In another embodiment, a fuel fluid may be oxidized in a
heater located external to a coal formation. The fuel fluid may be
oxidized with an oxidizing fluid in the heater. As an example, the
heater may be a flame-ignited heater. A fuel fluid may include any
fluid configured to react with oxygen. An example of a fuel fluid
may be methane, ethane, propane, or any other hydrocarbon or
hydrogen and synthesis gas. The oxidized fuel fluid may be provided
into the opening from the heater through a conduit and return to
the surface through another conduit in the overburden. The conduits
may be coupled within the overburden. In some embodiments, the
conduits may be concentrically placed. The oxidized fuel fluid may
be configured to heat, or at least contribute to the heating of, at
least a portion of the formation to a temperature sufficient to
support oxidation of hydrocarbons. Upon reaching such a
temperature, the oxidized fuel fluid may be replaced with an
oxidizing fluid. The oxidizing fluid may oxidize at least a portion
of the hydrocarbons at a reaction zone within the formation.
[0355] An electric heater may be configured to heat a portion of
the coal formation to a temperature sufficient to support oxidation
of hydrocarbons. The portion may be proximate to or substantially
adjacent to the opening in the formation. The portion may also
radially extend a width of less than approximately 1 m from the
opening. A width of the portion may vary, however, depending on,
for example, a power supplied to the heater. An oxidizing fluid may
be provided to the opening for oxidation of hydrocarbons. Oxidation
of the hydrocarbons may be configured to heat the coal formation in
a process of natural distributed combustion. Electrical current
applied to the electric heater may subsequently be reduced or may
be turned off. Thus, natural distributed combustion may be
configured, in conjunction with an electric heater, to provide a
reduced input energy cost method to heat the coal formation
compared to using an electric heater.
[0356] An insulated conductor heater may be a heater element of a
heat source. In an embodiment of an insulated conductor heater, the
insulated conductor heater is a mineral insulated cable or rod. An
insulated conductor heater may be placed in an opening in a coal
formation. The insulated conductor heater may be placed in an
uncased opening in the coal formation. Placing the heater in an
uncased opening in the coal formation may allow heat transfer from
the heater to the formation by radiation, as well as, conduction.
In addition, using an uncased opening may also allow retrieval of
the heater from the well, if necessary, and may eliminate the cost
of the casing. Alternately, the insulated conductor heater may be
placed within a casing in the formation; may be cemented within the
formation; or may be packed in an opening with sand, gravel, or
other fill material. The insulated conductor heater may be
supported on a support member positioned within the opening. The
support member may be a cable, rod, or a conduit (e.g., a pipe).
The support member may be made of a metal, ceramic, inorganic
material, or combinations thereof. Portions of a support member may
be exposed to formation fluids and heat during use, so the support
member may be chemically resistant and thermally resistant.
[0357] Ties, spot welds and/or other types of connectors may be
used to couple the insulated conductor heater to the support member
at various locations along a length of the insulated conductor
heater. The support member may be attached to a wellhead at an
upper surface of the formation. In an alternate embodiment of an
insulated conductor heater, the insulated conductor heater is
designed to have sufficient structural strength so that a support
member is not needed. The insulated conductor heater will in many
instances have some flexibility to inhibit thermal expansion damage
when heated or cooled.
[0358] In certain embodiments, insulated conductor heaters may be
placed in wellbores without support members and/or centralizers.
This can be accomplished for heaters if the insulated conductor has
a suitable combination of temperature and corrosion resistance,
creep strength, length, thickness (diameter), and metallurgy that
will inhibit failure of the insulated conductor during use. In an
embodiment, insulated conductors that are heated to working
temperature of about 700.degree. C. are less than about 150 meters
in length, are made of 310 stainless steel, and may be used without
support members.
[0359] FIG. 16 depicts a perspective view of an end portion of an
embodiment of an insulated conductor heater 562. An insulated
conductor heater may have any desired cross sectional shape, such
as, but not limited to round (as shown in FIG. 16), triangular,
ellipsoidal, rectangular, hexagonal or irregular shape. An
insulated conductor heater may include conductor 575, electrical
insulation 576 and sheath 577. The conductor 575 may resistively
heat when an electrical current passes through the conductor. An
alternating or direct current may be used to heat the conductor
575. In an embodiment, a 60 cycle AC current may be used.
[0360] In some embodiments, the electrical insulation 576 may
inhibit current leakage and may inhibit arcing to the sheath 577.
The electrical insulation 576 may also thermally conduct heat
generated in the conductor 575 to the sheath 577. The sheath 577
may radiate or conduct heat to the formation. An insulated
conductor heater 562 may be 1000 m or more in length. In an
embodiment of an insulated conductor heater, the insulated
conductor heater 562 may have a length from about 15 m to about 950
m. Longer or shorter insulated conductors may also be used to meet
specific application needs. In embodiments of insulated conductor
heaters, purchased insulated conductor heaters have lengths of
about 100 m to 500 m (e.g., 230 m). In certain embodiments,
dimensions of sheaths and/or conductors of an insulated conductor
may be formed so that the insulated conductors have enough strength
to be self supporting even at upper working temperatures. Such
insulated cables may be suspended from wellheads or supports
positioned near an interface between an overburden and a coal
formation without the need for support members extending into the
hydrocarbon formation along with the insulated conductors.
[0361] In an embodiment, a higher frequency current may be used to
take advantage of the skin effect in certain metals. In some
embodiments, a 60 cycle AC current may be used in combination with
conductors made of metals that exhibit pronounced skin effects. For
example, ferromagnetic metals like iron alloys and nickel may
exhibit a skin effect. The skin effect confines the current to a
region close to the outer surface of the conductor, thereby
effectively increasing the resistance of the conductor. A higher
resistance may be desired to decrease the operating current,
minimize ohmic losses in surface cables, and also minimize the cost
of surface facilities.
[0362] As illustrated in FIG. 17, an insulated conductor heater 562
will in many instances be designed to operate at a power level of
up to about 1650 watts/meter. The insulated conductor heater 562
may typically operate at a power level between about 500
watts/meter and about 1150 watts/meter when heating a formation.
The insulated conductor heater 562 may be designed so that a
maximum voltage level at a typical operating temperature does not
cause substantial thermal and/or electrical breakdown of electrical
insulation 576. The insulated conductor heater 562 may be designed
so that the sheath 577 does not exceed a temperature that will
result in a significant reduction in corrosion resistance
properties of the sheath material.
[0363] In an embodiment of an insulated conductor heater 562, the
conductor 575 may be designed to reach temperatures within a range
between about 650.degree. C. to about 870.degree. C., and the
sheath 577 may be designed to reach temperatures within a range
between about 535.degree. C. to about 760.degree. C. Insulated
conductors having other operating ranges may be formed to meet
specific operational requirements. In an embodiment of an insulated
conductor heater 562, the conductor 575 is designed to operate at
about 760.degree. C., the sheath 577 is designed to operate at
about 650.degree. C., and the insulated conductor heater is
designed to dissipate about 820 watts/meter.
[0364] An insulated conductor heater 562 may have one or more
conductors 575. For example, a single insulated conductor heater
may have three conductors within electrical insulation that are
surrounded by a sheath. FIG. 16 depicts an insulated conductor
heater 562 having a single conductor 575. The conductor may be made
of metal. The material used to form a conductor may be, but is not
limited to, nichrome, nickel, and a number of alloys made from
copper and nickel in increasing nickel concentrations from pure
copper to Alloy 30, Alloy 60, Alloy 180 and Monel. Alloys of copper
and nickel may advantageously have better electrical resistance
properties than substantially pure nickel or copper.
[0365] In an embodiment, the conductor may be chosen to have a
diameter and a resistivity at operating temperatures such that its
resistance, as derived from Ohm's law, makes it electrically and
structurally stable for the chosen power dissipation per meter, the
length of the heater, and/or the maximum voltage allowed to pass
through the conductor. In an alternate embodiment, the conductor
may be designed, using Maxwell's equations, to make use of skin
effect heating in and/or on the conductor.
[0366] The conductor may be made of different material along a
length of the insulated conductor heater. For example, a first
section of the conductor may be made of a material that has a
significantly lower resistance than a second section of the
conductor. The first section may be placed adjacent to a formation
layer that does not need to be heated to as high a temperature as a
second formation layer that is adjacent to the second section. The
resistivity of various sections of conductor may be adjusted by
having a variable diameter and/or by having conductor sections made
of different materials.
[0367] A diameter of a conductor 575 may typically be between about
1.3 mm to about 10.2 mm. Smaller or larger diameters may also be
used to have conductors with desired resistivity characteristics.
In an embodiment of an insulated conductor heater, the conductor is
made of Alloy 60 that has a diameter of about 5.8 mm.
[0368] As illustrated in FIG. 16, an electrical insulator 576 of an
insulated conductor heater 562 may be made of a variety of
materials. Pressure may be used to place electrical insulator
powder between a conductor 575 and a sheath 577. Low flow
characteristics and other properties of the powder and/or the
sheaths and conductors may inhibit the powder from flowing out of
the sheaths. Commonly used powders may include, but are not limited
to, MgO, Al.sub.2O.sub.3, Zirconia, BeO, different chemical
variations of Spinels, and combinations thereof. MgO may provide
good thermal conductivity and electrical insulation properties. The
desired electrical insulation properties include low leakage
current and high dielectric strength. A low leakage current
decreases the possibility of thermal breakdown and the high
dielectric strength decreases the possibility of arcing across the
insulator. Thermal breakdown can occur if the leakage current
causes a progressive rise in the temperature of the insulator
leading also to arcing across the insulator. An amount of
impurities 578 in the electrical insulator powder may be tailored
to provide required dielectric strength and a low level of leakage
current. The impurities 578 added may be, but are not limited to,
CaO, Fe.sub.2O.sub.3, Al.sub.2O.sub.3, and other metal oxides. Low
porosity of the electrical insulation tends to reduce leakage
current and increase dielectric strength. Low porosity may be
achieved by increased packing of the MgO powder during fabrication
or by filling of the pore space in the MgO powder with other
granular materials, for example, Al.sub.2O.sub.3.
[0369] The impurities 578 added to the electrical insulator powder
may have particle sizes that are smaller than the particle sizes of
the powdered electrical insulator. The small particles may occupy
pore space between the larger particles of the electrical insulator
so that the porosity of the electrical insulator is reduced.
Examples of powdered electrical insulators that may be used to form
electrical insulation 576 are "H" mix manufactured by Idaho
Laboratories Corporation (Idaho Falls, Id.), or Standard MgO used
by Pyrotenax Cable Company (Trenton, Ontario) for high temperature
applications. In addition, other powdered electrical insulators may
be used.
[0370] A sheath 577 of an insulated conductor heater 562 may be an
outer metallic layer. The sheath 577 may be in contact with hot
formation fluids. The sheath 577 may need to be made of a material
having a high resistance to corrosion at elevated temperatures.
Alloys that may be used in a desired operating temperature range of
the sheath include, but are not limited to, 304 stainless steel,
310 stainless steel, Incoloy 800, and Inconel 600. The thickness of
the sheath has to be sufficient to last for three to ten years in a
hot and corrosive environment. A thickness of the sheath may
generally vary between about 1 mm and about 2.5 mm. For example, a
1.3 mm thick 310 stainless steel outer layer provides a sheath 577
that is able to provide good chemical resistance to sulfidation
corrosion in a heated zone of a formation for a period of over 3
years. Larger or smaller sheath thicknesses may be used to meet
specific application requirements.
[0371] An insulated conductor heater may be tested after
fabrication. The insulated conductor heater may be required to
withstand 2-3 times an operating voltage at a selected operating
temperature. Also, selected samples of produced insulated conductor
heaters may be required to withstand 1000 VAC at 760.degree. C. for
one month.
[0372] As illustrated in FIG. 17a, a short flexible transition
conductor 571 may be connected to a lead-in conductor 572 using a
connection 569 made during heater installation in the field. The
transition conductor 571 may, for example, be a flexible, low
resistivity, stranded copper cable that is surrounded by rubber or
polymer insulation. A transition conductor 571 may typically be
between about 1.5 m and about 3 m, although longer or shorter
transition conductors may be used to accommodate particular needs.
Temperature resistant cable may be used as transition conductor
571. The transition conductor 571 may also be connected to a short
length of an insulated conductor heater that is less resistive than
a primary heating section of the insulated conductor heater. The
less resistive portion of the insulated conductor heater may be
referred to as a "cold pin" 568. A cold pin 568 may be designed to
dissipate about one tenth to about one fifth of the power per unit
length as is dissipated in a unit length of the primary heating
section. Cold pins may typically be between about 1.5 m to about 15
m, although shorter or longer lengths may be used to accommodate
specific application needs. In an embodiment, the conductor of a
cold pin section is copper with a diameter of about 6.9 mm and a
length of 9.1 m. The electrical insulation is the same type of
insulation used in the primary heating section. A sheath of the
cold pin may be made of Inconel 600. Chloride corrosion cracking in
the cold pin region may occur, so a chloride corrosion resistant
metal such as Inconel 600 may be used as the sheath.
[0373] As illustrated in FIG. 17a, a small, epoxy filled canister
573 may be used to create a connection between a transition
conductor 571 and a cold pin 568. Cold pins 568 may be connected to
the primary heating sections of insulated conductor 562 heaters by
"splices" 567. The length of the cold pin 568 may be sufficient to
significantly reduce a temperature of the insulated conductor
heater 562. The heater section of the insulated conductor heater
562 may operate from about 530.degree. C. to about 760.degree. C.,
the splice 567 may be at a temperature from about 260.degree. C. to
about 370.degree. C., and the temperature at the lead-in cable
connection to the cold pin may be from about 40.degree. C. to about
90.degree. C. In addition to a cold pin at a top end of the
insulated conductor heater, a cold pin may also be placed at a
bottom end of the insulated conductor heater. The cold pin at the
bottom end may in many instances make a bottom termination easier
to manufacture.
[0374] Splice material may have to withstand a temperature equal to
half of a target zone operating temperature. Density of electrical
insulation in the splice should in many instances be high enough to
withstand the required temperature and the operating voltage.
[0375] A splice 567 may be required to withstand 1000 VAC at
480.degree. C. Splice material may be high temperature splices made
by Idaho Laboratories Corporation or by Pyrotenax Cable Company. A
splice may be an internal type of splice or an external splice. An
internal splice is typically made without welds on the sheath of
the insulated conductor heater. The lack of weld on the sheath may
avoid potential weak spots (mechanical and/or electrical) on the
insulated cable heater. An external splice is a weld made to couple
sheaths of two insulated conductor heaters together. An external
splice may need to be leak tested prior to insertion of the
insulated cable heater into a formation. Laser welds or orbital TIG
(tungsten inert gas) welds may be used to form external splices. An
additional strain relief assembly may be placed around an external
splice to improve the splice's resistance to bending and to protect
the external splice against partial or total parting.
[0376] An insulated conductor assembly may include heating
sections, cold pins, splices, and termination canisters and
flexible transition conductors. The insulated conductor assembly
may need to be examined and electrically tested before installation
of the assembly into an opening in a formation. The assembly may
need to be examined for competent welds and to make sure that there
are no holes in the sheath anywhere along the whole heater
(including the heated section, the cold-pins, the splices and the
termination cans). Periodic X-ray spot checking of the commercial
product may need to be made. The whole cable may be immersed in
water prior to electrical testing. Electrical testing of the
assembly may need to show more than 2000 megaohms at 500 VAC at
room temperature after water immersion. In addition, the assembly
may need to be connected to 1000 VAC and show less than about 10
microamps per meter of resistive leakage current at room
temperature. Also, a check on leakage current at about 760.degree.
C. may need to show less than about 0.4 milliamps per meter.
[0377] There are a number of companies that manufacture insulated
conductor heaters. Such manufacturers include, but are not limited
to, MI Cable Technologies (Calgary, Alberta), Pyrotenax Cable
Company (Trenton, Ontario), Idaho Laboratories Corporation (Idaho
Falls, Id.), and Watlow (St. Louis, Mo.). As an example, an
insulated conductor heater may be ordered from Idaho Laboratories
as cable model 355-A90-310-"H" 30'/750'/30' with Inconel 600 sheath
for the cold-pins, three phase Y configuration and bottom jointed
conductors. The required specification for the heater should also
include 1000 VAC, 1400.degree. F. quality cable in addition to the
preferred mode specifications described above. The designator 355
specifies the cable OD (0.355"), A90 specifies the conductor
material, 310 specifies the heated zone sheath alloy (SS 310), "H"
specifies the MgO mix, 30'/750'/30' specifies about a 230 m heated
zone with cold-pins top and bottom having about 9 m lengths. A
similar part number with the same specification using high
temperature Standard purity MgO cable may be ordered from Pyrotenax
Cable Company.
[0378] One or more insulated conductor heaters may be placed within
an opening in a formation to form a heat source or heat sources.
Electrical current may be passed through each insulated conductor
heater in the opening to heat the formation. Alternately,
electrical current may be passed through selected insulated
conductor heaters in an opening. The unused conductors may be
backup heaters. Insulated conductor heaters may be electrically
coupled to a power source in any convenient manner. Each end of an
insulated conductor heater may be coupled to lead-in cables that
pass through a wellhead. Such a configuration typically has a
180.degree. bend (a "hairpin" bend) or turn located near a bottom
of the heat source. An insulated conductor heater that includes a
180.degree. bend or turn may not require a bottom termination, but
the 180.degree. bend or turn may be an electrical and/or structural
weakness in the heater. Insulated conductor heaters may be
electrically coupled together in series, in parallel, or in series
and parallel combinations. In some embodiments of heat sources,
electrical current may pass into the conductor of an insulated
conductor heater and may returned through the sheath of the
insulated conductor heater by connecting the conductor 575 to the
sheath 577 at the bottom of the heat source.
[0379] In an embodiment of a heat source depicted in FIG. 17, three
insulated conductor heaters 562 are electrically coupled in a
3-phase Y configuration to a power supply. The power supply may
provide a 60 cycle AC current to the electrical conductors. No
bottom connection may be required for the insulated conductor
heaters. Alternately, all three conductors of the three phase
circuit may be connected together near the bottom of a heat source
opening. The connection may be made directly at ends of heating
sections of the insulated conductor heaters or at ends of cold pins
coupled to the heating sections at the bottom of the insulated
conductor heaters. The bottom connections may be made with
insulator filled and sealed canisters or with epoxy filled
canisters. The insulator may be the same composition as the
insulator used as the electrical insulation.
[0380] The three insulated conductor heaters depicted in FIG. 17
may be coupled to support member 564 using centralizers 566.
Alternatively, the three insulated conductor heaters may be
strapped directly to the support tube using metal straps.
Centralizers 566 may be configured to maintain a location of
insulated conductor heaters 562 on support member 564. Centralizers
566 may be made of, for example, metal, ceramic or a combination
thereof. The metal may be stainless steel or any other type of
metal able to withstand a corrosive and hot environment. In some
embodiments, centralizers 566 may be simple bowed metal strips
welded to the support member at distances less than about 6 meters.
A ceramic used in centralizer 566 may be, but is not limited to,
Al.sub.2O.sub.3, MgO or other insulator. Centralizers 566 may be
configured to maintain a location of insulated conductor heaters
562 on support member 564 such that movement of insulated conductor
heaters may be substantially inhibited at operating temperatures of
the insulated conductor heaters. Insulated conductor heaters 562
may also be somewhat flexible to withstand expansion of support
member 564 during heating. Centralizers 566 may also be configured
as described in any of the embodiments herein.
[0381] Support member 564, insulated conductor heater 562, and
centralizers 566 may be placed in opening 514 in coal formation
516. Insulated conductor heaters 562 may be coupled to bottom
conductor junction 570 using cold pin transition conductor 568.
Bottom conductor junction 570 may electrically couple each
insulated conductor heater 562 to each other. Bottom conductor
junction 570 may include materials that are electrically conducting
and do not melt at temperatures found in opening 514. Cold pin
transition conductor 568 may be an insulated conductor heater
having lower electrical resistance than insulated conductor heater
562. As illustrated in FIG. 17a, cold pin 568 may be coupled to
transition conductor 571 and insulated conductor heater 562. Cold
pin transition conductor 568 may provide a temperature transition
between transition conductor 571 and insulated conductor heater
562.
[0382] Lead-in conductor 572 may be coupled to wellhead 590 to
provide electrical power to insulated conductor heater 562.
Wellhead 590 may be configured as shown in FIG. 18 and as described
in any of the embodiments herein. Lead-in conductor 572 may be made
of a relatively low electrical resistance conductor such that
relatively little or substantially no heat may be generated from
electrical current passing through lead-in conductor 572. For
example, the lead-in conductor may include, but may not be limited
to, a rubber insulated stranded copper wire, but the lead-in
conductor may also be a mineral-insulated conductor with a copper
core. Lead-in conductor 572 may couple to a wellhead 590 at surface
550 through a sealing flange located between overburden 540 and
surface 550. The sealing flange 590c may be configured as shown in
FIG. 18 and as described in any of the embodiments herein. The
sealing flange may substantially inhibit fluid from escaping from
opening 514 to surface 550.
[0383] Packing material 542 (see FIG. 17) may optionally be placed
between overburden casing 541 and opening 514. Overburden casing
541 may include any materials configured to substantially contain
cement 544. In an embodiment of a heater source, overburden casing
is a 7.6 cm (3 inch) diameter carbon steel, schedule 40 pipe.
Packing material 542 may be configured to inhibit fluid from
flowing from opening 514 to surface 550. Overburden casing 541 may
be placed in cement 544 in overburden 540 of formation 516. Cement
544 may include, for example, Class G or Class H Portland cement
mixed with silica flour for improved high temperature performance,
slag or silica flour, and/or a mixture thereof (e.g., about 1.58
grams per cubic centimeter slag/silica flour). In selected heat
source embodiments, cement 544 extends radially a width of from
about 5 cm to about 25 cm. In some embodiments cement 544 may
extend radially a width of about 10 cm to about 15 cm. In some
other embodiments, cement 544 may be designed to inhibit heat
transfer from conductor 564 into formation 540 within the
overburden.
[0384] In certain embodiments one or more conduits may be provided
to supply additional components (e.g., nitrogen, carbon dioxide,
reducing agents such as gas containing hydrogen, etc.) to formation
openings, to bleed off fluids, and/or to control pressure.
Formation pressures tend to be highest near heating sources and
thus it is often beneficial to have pressure control equipment
proximate the heating source. In some embodiments adding a reducing
agent proximate the heating source assists in providing a more
favorable pyrolysis environment (e.g., a higher hydrogen partial
pressure). Since permeability and porosity tend to increase more
quickly proximate the heating source, it is often optimal to add a
reducing agent proximate the heating source so that the reducing
agent can more easily move into the formation.
[0385] In FIG. 17, for example, conduit 5000 may be provided to add
gas from gas source 5003, through valve 5001, and into opening 514
(an opening 5004 is provided in packing material 542 to allow gas
to pass into opening 514). Conduit 5000 and valve 5002 may also be
used at different times to bleed off pressure and/or control
pressure proximate to opening 514. In FIG. 19, for example, conduit
5010 may be provided to add gas from gas source 5013, through valve
5011, and into opening 514 (an opening is provided in cement 544 to
allow gas to pass into opening 514). Conduit 5010 and valve 5012
may also be used at different times to bleed off pressure and/or
control pressure proximate to opening 514. It is to be understood
that any of the heating sources described herein may also be
equipped with conduits to supply additional components, bleed off
fluids, and/or to control pressure.
[0386] Support member 564 and lead-in conductor 572 may be coupled
to wellhead 590 at surface 550 of formation 516. Surface conductor
545 may enclose cement 544 and may couple to wellhead 590.
Embodiments of heater source surface conductor 545 may have a
diameter of about 10.16 cm to about 30.48 cm or, for example, a
diameter of about 22 cm. Embodiments of surface casings may extend
to depths of approximately 3 m to approximately 515 m into an
opening in the formation. Alternatively, the surface casing may
extend to a depth of approximately 9 m into the opening. Electrical
current may be supplied from a power source to insulated conductor
heater 562 to generate heat due to the electrical resistance of
conductor 575 as illustrated in FIG. 16. As an example, a voltage
of about 330 volts and a current of about 266 amps are supplied to
insulated conductors 562 to generate a heat of about 1150
watts/meter in insulated conductor heater 562. Heat generated from
the three insulated conductor heaters 562 may transfer (e.g., by
radiation) within opening 514 to heat at least a portion of the
formation 516.
[0387] An appropriate configuration of an insulated conductor
heater may be determined by optimizing a material cost of the
heater based on a length of heater, a power required per meter of
conductor, and a desired operating voltage. In addition, an
operating current and voltage may be chosen to optimize the cost of
input electrical energy in conjunction with a material cost of the
insulated conductor heaters. For example, as input electrical
energy increases, the cost of materials needed to withstand the
higher voltage may also increase. The insulated conductor heaters
may be configured to generate a radiant heat of approximately 650
watts/meter of conductor to approximately 1650 watts/meter of
conductor. The insulated conductor heater may operate at a
temperature between approximately 530.degree. C. and approximately
760.degree. C. within a formation.
[0388] Heat generated by an insulated conductor heater may heat at
least a portion of a coal formation. In some embodiments heat may
be transferred to the formation substantially by radiation of the
generated heat to the formation. Some heat may be transferred by
conduction or convection of heat due to gases present in the
opening. The opening may be an uncased opening. An uncased opening
eliminates cost associated with thermally cementing the heater to
the formation, costs associated with a casing, and/or costs of
packing a heater within an opening. In addition, the heat transfer
by radiation is generally more efficient than by conduction so the
heaters will operate at lower temperatures in an open wellbore. The
conductive heat transfer may be enhanced by the addition of a gas
in the opening at pressures up to about 27 bar absolute. The gas
may include, but may not be limited to, carbon dioxide and/or
helium. Still another advantage is that the heating assembly will
be free to undergo thermal expansion. Yet another advantage is that
the heaters may be replaceable.
[0389] The insulated conductor heater, as described in any of the
embodiments herein, may be installed in opening 514 by any method
known in the art. In an embodiment, more than one spooling assembly
may be used to install both the electric heater and a support
member simultaneously. U.S. Pat. No. 4,572,299 issued to Van Egmond
et al., which is incorporated by reference as if fully set forth
herein, describes spooling an electric heater into a well.
Alternatively, the support member may be installed using a coiled
tubing unit including any unit known in the art. The heaters may be
un-spooled and connected to the support as the support is inserted
into the well. The electric heater and the support member may be
un-spooled from the spooling assemblies. Spacers may be coupled to
the support member and the heater along a length of the support
member. Additional spooling assemblies may be used for additional
electric heater elements.
[0390] In an embodiment, the support member may be installed using
standard oil field operations and welding different sections of
support. Welding may be done by using orbital welding. For example,
a first section of the support member may be disposed into the
well. A second section (e.g., of substantially similar length) may
be coupled to the first section in the well. The second section may
be coupled by welding the second section to the first section. An
orbital welder disposed at the wellhead may be configured to weld
the second section to the first section. This process may be
repeated with subsequent sections coupled to previous sections
until a support of desired length is within the well.
[0391] FIG. 18 illustrates a cross-sectional view of one embodiment
of a wellhead coupled, e.g., to overburden casing 541. Flange 590c
may be coupled to, or may be a part of, wellhead 590. Flange 590c
may be, for example, carbon steel, stainless steel or any other
commercially available suitable sealing material. Flange 590c may
be sealed with o-ring 590f, or any other sealing mechanism.
Thermocouples 590g may be provided into wellhead 590 through flange
590c. Thermocouples 590g may measure a temperature on or proximate
to support member 564 within the heated portion of the well.
Support member 564 may be coupled to flange 590c. Support member
564 may be configured to support one or more insulated conductor
heaters as described herein. Support member 564 may be sealed in
flange 590c by welds 590h. Alternately, support member 564 may be
sealed by any method known in the art.
[0392] Power conductor 590a may be coupled to a lead-in cable
and/or an insulated conductor heater. Power conductor 590a may be
configured to provide electrical energy to the insulated conductor
heater. Power conductor 590a may be sealed in sealing flange 590d.
Sealing flange 590d may be sealed by compression seals or o-rings
590e. Power conductor 590a may be coupled to support member 564
with band 590i. Band 590i may include a rigid and corrosion
resistant material such as stainless steel. Wellhead 590 may be
sealed with weld 590h such that fluid may be substantially
inhibited from escaping the formation through wellhead 590. Lift
bolt 590j may be configured to lift wellhead 590 and support member
564. Wellhead 590 may also include a pressure control valve.
Compression fittings 590k may serve to seal power cable 590a and
compression fittings 5901 may serve to seal thermocouple 590g.
These seals inhibit fluids from escaping the formation. The
pressure control valve may be configured to control a pressure
within an opening in which support member 564 may be disposed.
[0393] In an embodiment, a control system may be configured to
control electrical power supplied to an insulated conductor heater.
Power supplied to the insulated conductor heater may be controlled
with any appropriate type of controller. For alternating current,
the controller may, for example, be a tapped transformer.
Alternatively, the controller may be a zero crossover electrical
heater firing SCR (silicon controlled rectifier) controller. Zero
crossover electrical heater firing control may be achieved by
allowing full supply voltage to the insulated conductor heater to
pass through the insulated conductor heater for a specific number
of cycles, starting at the "crossover," where an instantaneous
voltage may be zero, continuing for a specific number of complete
cycles, and discontinuing when the instantaneous voltage again may
cross zero. A specific number of cycles may be blocked, allowing
control of the heat output by the insulated conductor heater. For
example, the control system may be arranged to block fifteen and/or
twenty cycles out of each sixty cycles that may be supplied by a
standard 60 Hz alternating current power supply. Zero crossover
firing control may be advantageously used with materials having a
low temperature coefficient materials. Zero crossover firing
control may substantially inhibit current spikes from occurring in
an insulated conductor heater.
[0394] FIG. 19 illustrates an embodiment of a conductor-in-conduit
heater configured to heat a section of a coal formation. Conductor
580 may be disposed in conduit 582. Conductor 580 may be a rod or
conduit of electrically conductive material. A conductor 580 may
have a low resistance section 584 at both the top and the bottom of
the conductor 580 in order to generate less heating in these
sections 584. The substantially low resistance section 584 may be
due to a greater cross-sectional area of conductor 580 in that
section. For example, conductor 580 may be a 304 or 310 stainless
steel rod with a diameter of approximately 2.8 cm. The diameter and
wall thickness of conductor 580 may vary, however, depending on,
for example, a desired heating rate of the coal formation. Conduit
582 may include an electrically conductive material. For example,
conduit 582 may be a 304 or 310 stainless steel pipe having a
diameter of approximately 7.6 cm and a thickness of approximately
schedule 40. Conduit 582 may be disposed in opening 514 in
formation 516. Opening 514 may have a diameter of at least
approximately 5 cm. The diameter of the opening may vary, however,
depending on, for example, a desired heating rate in the formation
and/or a diameter of conduit 582. For example, a diameter of the
opening may be from about 10 cm to about 13 cm. Larger diameter
openings may also be used. For example, a larger opening may be
used if more than one conductor is to be placed within a
conduit.
[0395] Conductor 580 may be centered in conduit 582 through
centralizer 581. Centralizer 581 may electrically isolate conductor
580 from conduit 582. In addition, centralizer 581 may be
configured to locate conductor 580 within conduit 582. Centralizer
581 may be made of a ceramic material or a combination of ceramic
and metallic materials. More than one centralizer 581 may be
configured to substantially inhibit deformation of conductor 580 in
conduit 582 during use. More than one centralizer 581 may be spaced
at intervals between approximately 0.5 m and approximately 3 m
along conductor 580. Centralizer 581 may be made of ceramic, 304
stainless steel, 310 stainless steel, or other types of metal.
Centralizer 581 may be configured as shown in FIG. 22 and/or FIGS.
23a and 23b.
[0396] As depicted in FIG. 20, sliding connector 583 may couple an
end of conductor 580 disposed proximate a lowermost surface of
conduit 582. Sliding connector 583 allows for differential thermal
expansion between conductor 580 and conduit 582. Sliding connector
583 is attached to a conductor 580 located at the bottom of the
well at a low resistance section 584 which may have a greater
cross-sectional area. The lower resistance of section 584 allows
the sliding connector to operate at temperatures no greater than
about 90.degree. C. In this manner, corrosion of the sliding
connector components is minimized and therefore contact resistance
between sliding connector 583 and conduit 582 is also minimized.
Sliding connector 583 may be configured as shown in FIG. 20 and as
described in any of the embodiments herein. The substantially low
resistance section 584 of the conductor 580 may couple conductor
580 to wellhead 690 as depicted in FIG. 19. Wellhead 690 may be
configured as shown in FIG. 21 and as described in any of the
embodiments herein. Electrical current may be applied to conductor
580 from power cable 585 through a low resistance section 584 of
the conductor 580. Electrical current may pass from conductor 580
through sliding connector 583 to conduit 582. Conduit 582 may be
electrically insulated from overburden casing 541 and from wellhead
690 to return electrical current to power cable 585. Heat may be
generated in conductor 580 and conduit 582. The generated heat may
radiate within conduit 582 and opening 514 to heat at least a
portion of formation 516. As an example, a voltage of about 330
volts and a current of about 795 amps may be supplied to conductor
580 and conduit 582 in a 229 m (750 ft) heated section to generate
about 1150 watts/meter of conductor 580 and conduit 582.
[0397] Overburden conduit 541 may be disposed in overburden 540 of
formation 516. Overburden conduit 541 may in some embodiments be
surrounded by materials that may substantially inhibit heating of
overburden 540. A substantially low resistance section 584 of a
conductor 580 may be placed in overburden conduit 541. The
substantially low resistance section 584 of conductor 580 may be
made of, for example, carbon steel. The substantially flow
resistance section 584 may have a diameter between about 2 cm to
about 5 cm or, for example, a diameter of about 4 cm. A
substantially low resistance section 584 of conductor 580 may be
centralized within overburden conduit 541 using centralizers 581.
Centralizers 581 may be spaced at intervals of approximately 6 m to
approximately 12 m or, for example, approximately 9 m along
substantially low resistance section 584 of conductor 580. A
substantially low resistance section 584 of conductor 580 may be
coupled to conductor 580 using any method known in the art such as
arc welding. A substantially low resistance section 584 may be
configured to generate little and/or substantially no heat in
overburden conduit 541. Packing material 542 may be placed between
overburden casing 541 and opening 514. Packing material 542 may be
configured to substantially inhibit fluid from flowing from opening
514 to surface 550 or to inhibit most heat carrying fluids from
flowing from opening 514 to surface 550.
[0398] Overburden conduit may include, for example, a conduit of
carbon steel having a diameter of about 7.6 cm and a thickness of
about schedule 40 pipe. Cement 544 may include, for example, slag
or silica flour, or a mixture thereof (e.g., about 1.58 grams per
cubic centimeter slag/silica flour). Cement 544 may extend radially
a width of about 5 cm to about 25 cm. Cement 544 may also be made
of material designed to inhibit flow of heat into formation
516.
[0399] Surface conductor 545 and overburden casing 541 may enclose
cement 544 and may couple to wellhead 690. Surface conductor 545
may have a diameter of about 10 cm to about 30 cm and more
preferably a diameter of about 22 cm. Electrically insulating
sealing flanges may be configured to mechanically couple
substantially low resistance section 584 of conductor 580 to
wellhead 690 and to electrically couple lower resistance section
584 to power cable 585. The electrically insulating sealing flanges
may be configured to couple lead-in conductor 585 to wellhead 690.
For example, lead-in conductor 585 may include a copper cable,
wire, or other elongated member. Lead-in conductor 585 may include,
however, any material having a substantially low resistance. The
lead-in conductor may be clamped to the bottom of the low
resistivity conductor to make electrical contact.
[0400] In an embodiment, heat may be generated in or by conduit
582. In this manner, about 10% to about 30%, or, for example, about
20%, of the total heat generated by the heater may be generated in
or by conduit 582. Both conductor 580 and conduit 582 may be made
of stainless steel. Dimensions of conductor 580 and conduit 582 may
be chosen such that the conductor will dissipate heat in a range
from approximately 650 watts per meter to 1650 watts per meter. A
temperature in conduit 582 may be approximately 480.degree. C. to
approximately 815.degree. C. and a temperature in conductor 580 may
be approximately 500.degree. C. to 840.degree. C. Substantially
uniform heating of a coal formation may be provided along a length
of conduit 582 greater than about 300 m or, maybe, greater than
about 600 m. A length of conduit 582 may vary, however, depending
on, for example, a type of coal formation, a depth of an opening in
the formation, and/or a length of the formation desired for
treating.
[0401] The generated heat may be configured to heat at least a
portion of a coal formation. Heating of at least the portion may
occur substantially by radiation of the generated heat within an
opening in the formation and to a lesser extent by gas conduction.
In this manner, a cost associated with filling the opening with a
filling material to provide conductive heat transfer between the
insulated conductor and the formation may be eliminated. In
addition, heat transfer by radiation is generally more efficient
than by conduction so the heaters will generally operate at lower
temperatures in an open wellbore. Still another advantage is that
the heating assembly will be free to undergo thermal expansion. Yet
another advantage is that the heater may be replaceable.
[0402] The conductor-in-conduit heater, as described in any of the
embodiments herein, may be installed in opening 514. In an
embodiment, the conductor-in-conduit heater may be installed into a
well by sections. For example, a first section of the
conductor-in-conduit heater may be disposed into the well. The
section may be about 12 m in length. A second section (e.g., of
substantially similar length) may be coupled to the first section
in the well. The second section may be coupled by welding the
second section to the first section and/or with threads disposed on
the first and second section. An orbital welder disposed at the
wellhead may be configured to weld the second section to the first
section. This process may be repeated with subsequent sections
coupled to previous sections until a heater of desired length may
be disposed in the well. In some embodiments, three sections may be
coupled prior to being disposed in the well. The three sections may
be coupled by welding. The three sections may have a length of
about 12.2 m each. The resulting 37 m section may be lifted
vertically by a crane at the wellhead. The three sections may be
coupled to three additional sections in the well as described
herein. Welding the three sections prior to being disposed in the
well may reduce a number of leaks and/or faulty welds and may
decrease a time required for installation of the heater.
[0403] In an alternate embodiment, the conductor-in-conduit heater
may be spooled onto a spooling assembly. The spooling assembly may
be mounted on a transportable structure. The transportable
structure may be transported to a well location. The
conductor-in-conduit heater may be un-spooled from the spooling
assembly into the well.
[0404] FIG. 20 illustrates an embodiment of a sliding connector.
Sliding connector 583 may include scraper 593 that may abut an
inner surface of conduit 582 at point 595. Scraper 593 may include
any metal or electrically conducting material (e.g., steel or
stainless steel). Centralizer 591 may couple to conductor 580. In
some embodiments, conductor 580 may have a substantially low
resistance section 584, due to an increased thickness,
substantially around a location of sliding connector 583.
Centralizer 591 may include any electrically conducting material
(e.g., a metal or metal alloy). Centralizer 591 may be coupled to
scraper 593 through spring bow 592. Spring bow 592 may include any
metal or electrically conducting material (e.g., copper-beryllium
alloy). Centralizer 591, spring bow 592, and/or scraper 593 may be
coupled through any welding method known in the art. Sliding
connector 583 may electrically couple the substantially low
resistance section 584 of conductor 580 to conduit 582 through
centralizer 591, spring bow 592, and/or scraper 593. During heating
of conductor 580, conductor 580 may expand at a substantially
different rate than conduit 582. For example, point 594 on
conductor 580 may move relative to point 595 on conduit 582 during
heating of conductor 580. Scraper 593 may maintain electrical
contact with conduit 582 by sliding along surface of conduit 582.
Several sliding connectors may be used for redundancy and to reduce
the current at each scraper. In addition, a thickness of conduit
582 may be increased for a length substantially adjacent to sliding
connector 583 to substantially reduce heat generated in that
portion of the conduit 582. The length of conduit 582 with
increased thickness may be, for example, approximately 6 m.
[0405] FIG. 21 illustrates another embodiment of a wellhead.
Wellhead 690 may be coupled to electrical junction box 690a by
flange 690n or any other suitable mechanical device. Electrical
junction box 690a may be configured to control power (current and
voltage) supplied to an electric heater. The electric heater may be
a conductor-in-conduit heater as described herein. Flange 690n may
include, for example, stainless steel or any other suitable sealing
material. Conductor 690b may be disposed in flange 690n and may
electrically couple overburden casing 541 to electrical junction
box 690a. Conductor 690b may include any metal or electrically
conductive material (e.g., copper). Compression seal 690c may seal
conductor 690b at an inner surface of electrical junction box
690a.
[0406] Flange 690n may be sealed with metal o-ring 690d. Conduit
690f, which may be, e.g., a pipe, may couple flange 690n to flange
690m. Flange 690m may couple to overburden casing 541. Flange 690m
may be sealed with o-ring 690g (e.g., metal o-ring or steel
o-ring). The substantially low resistance section 584 of the
conductor (e.g., conductor 580) may couple to electrical junction
box 690a. The substantially low resistance section 584 may be
passed through flange 690n and may be sealed in flange 690n with
o-ring assembly 690p. Assemblies 690p are designed to insulate the
substantially low resistance section 584 of conductor 580 from
flange 690n and flange 690m. 0-ring assembly 690c may be designed
to electrically insulate conductor 690b from flange 690m and
junction box 690a. Centralizer 581 may couple to low resistance
section 584. Electrically insulating centralizer 581 may have
characteristics as described in any of the embodiments herein.
Thermocouples 690i may be coupled to thermocouple flange 690q with
connectors 690h and wire 690j. Thermocouples 690i may be enclosed
in an electrically insulated sheath (e.g., a metal sheath).
Thermocouples 690i may be sealed in thermocouple flange 690q with
compression seals 690k. Thermocouples 690i may be used to monitor
temperatures in the heated portion downhole.
[0407] FIG. 22 illustrates a perspective view of an embodiment of a
centralizer in, e.g., conduit 582. Electrical insulator 581a may be
disposed on conductor 580. Insulator 581a may be made of, for
example, aluminum oxide or any other electrically insulating
material that may be configured for use at high temperatures. A
location of insulator 581a on the conductor 580 may be maintained
by disc 581d. Disc 581d may be welded to conductor 580. Spring bow
581c may be coupled to insulator 581a by disc 581b. Spring bow 581c
and disc 581b may be made of metals such as 310 stainless steel and
any other thermally conducting material that may be configured for
use at high temperatures. Centralizer 581 may be arranged as a
single cylindrical member disposed on conductor 580. Centralizer
581 may be arranged as two half-cylindrical members disposed on
conductor 580. The two half-cylindrical members may be coupled to
conductor 580 by band 581e. Band 581e may be made of any material
configured for use at high temperatures (e.g., steel).
[0408] FIG. 23a illustrates a cross-sectional view of an embodiment
of a centralizer 581e disposed on conductor 580. FIG. 23b
illustrates a perspective view of the embodiment shown in FIG. 23a.
Centralizer 581e may be made of any suitable electrically
insulating material that may substantially withstand high voltage
at high temperatures. Examples of such materials may be aluminum
oxide and/or Macor. Discs 581d may maintain positions of
centralizer 581e relative to conductor 580. Discs 581d may be metal
discs welded to conductor 580. Discs 581d may be tack-welded to
conductor 580. Centralizer 581e may substantially electrically
insulate conductor 580 from conduit 582.
[0409] In an embodiment, a conduit may be pressurized with a fluid
to balance a pressure in the conduit with a pressure in an opening.
In this manner, deformation of the conduit may be substantially
inhibited. A thermally conductive fluid may be configured to
pressurize the conduit. The thermally conductive fluid may increase
heat transfer within the conduit. The thermally conductive fluid
may include a gas such as helium, nitrogen, air, or mixtures
thereof. A pressurized fluid may also be configured to pressurize
the conduit such that the pressurized fluid may inhibit arcing
between the conductor and the conduit. If air and/or air mixtures
are used to pressurize the conduit, the air and/or air mixtures may
react with materials of the conductor and the conduit to form an
oxide on a surface of the conductor and the conduit such that the
conductor and the conduit are at least somewhat more resistant to
corrosion.
[0410] An emissivity of a conductor and/or a conduit may be
increased. For example, a surface of the conductor and/or the
conduit may be roughened to increase the emissivity. Blackening the
surface of the conductor and/or the conduit may also increase the
emissivity. Alternatively, oxidation of the conductor and/or the
conduit prior to installation may be configured to increase the
emissivity. The conductor and/or the conduit may also be oxidized
by heating the conductor and/or the conduit in the presence of an
oxidizing fluid in the conduit and/or in an opening in a coal
formation. Another alternative for increasing the emissivity may be
to anodize the conductor and/or the conduit such that the surface
may be roughened and/or blackened.
[0411] In another embodiment, a perforated tube may be placed in
the opening formed in the coal formation proximate to and external
the first conduit. The perforated tube may be configured to remove
fluids formed in the opening. In this manner, a pressure may be
maintained in the opening such that deformation of the first
conduit may be substantially inhibited and the pressure in the
formation near the heaters may be reduced. The perforated tube may
also be used to increase or decrease pressure in the formation by
addition or removal of a fluid or fluids from the formation. This
may allow control of the pressure in the formation and control of
quality of produced hydrocarbons. Perforated tubes may be used for
pressure control in all described embodiments of heat sources using
an open hole configuration. The perforated tube may also be
configured to inject gases to upgrade hydrocarbon properties in
situ; for example, hydrogen gas may be injected under elevated
pressure.
[0412] FIG. 24 illustrates an alternative embodiment of a
conductor-in-conduit heater configured to heat a section of a coal
formation. Second conductor 586 may be disposed in conduit 582 in
addition to conductor 580. Conductor 580 may be configured as
described herein. Second conductor 586 may be coupled to conductor
580 using connector 587 located near a lowermost surface of conduit
582. Second conductor 586 may be configured as a return path for
the electrical current supplied to conductor 580. For example,
second conductor 586 may return electrical current to wellhead 690
through second substantially low resistance conductor 588 in
overburden casing 541. Second conductor 586 and conductor 580 may
be configured of an elongated conductive material. Second conductor
586 and conductor 580 may be, for example, a stainless steel rod
having a diameter of approximately 2.4 cm. Connector 587 may be
flexible. Conduit 582 may be electrically isolated from conductor
580 and second conductor 586 using centralizers 581. Overburden
casing 541, cement 544, surface conductor 545, and packing material
542 may be configured as described in the embodiment shown in FIG.
19. Advantages of this embodiment include the absence of a sliding
contactor, which may extend the life of the heater, and the
isolation of all applied power from formation 516.
[0413] In another embodiment, a second conductor may be disposed in
a second conduit, and a third conductor may be disposed in a third
conduit. The second opening may be different from the opening for
the first conduit. The third opening may be different from the
opening for the first conduit and the second opening. For example,
each of the first, second, and third openings may be disposed in
substantially different well locations of the formation and may
have substantially similar dimensions. The first, second, and third
conductors may be configured as described herein. The first,
second, and third conductors may be electrically coupled in a
3-phase Y electrical configuration. The outer conduits may be
connected together or may be connected to the ground. The 3-phase Y
electrical configuration may provide a safer, more efficient method
to heat a coal formation than using a single conductor. The first,
second, and/or third conduits may be electrically isolated from the
first, second, and third conductors, respectively. Dimensions of
each conductor and each conduit may be configured such that each
conductor may generate heat of approximately 650 watts per meter of
conductor to approximately 1650 watts per meter of conductor. In an
embodiment, a first conductor and a second conductor in a conduit
may be coupled by a flexible connecting cable. The bottom of the
first and second conductor may be enlarged to create low resistance
sections, and thus generate less heat. In this manner, the flexible
connector may be made of, for example, stranded copper covered with
rubber insulation.
[0414] In an embodiment, a first conductor and a second conductor
may be coupled to at least one sliding connector within a conduit.
The sliding connector may be configured as described herein. For
example, such a sliding connector may be configured to generate
less heat than the first conductor or the second conductor. The
conduit may be electrically isolated from the first conductor,
second conductor, and/or the sliding connector. The sliding
connector may be placed in a location within the first conduit
where substantially less heating of the coal formation may be
required.
[0415] In an embodiment, a thickness of a section of a conduit may
be increased such that substantially less heat may be transferred
(e.g., radiated) along the section of increased thickness. The
section with increased thickness may preferably be formed along a
length of the conduit where less heating of the coal formation may
be required.
[0416] In an embodiment, the conductor may be formed of sections of
various metals that are welded together. The cross sectional area
of the various metals may be selected to allow the resulting
conductor to be long, to be creep resistant at high operating
temperatures, and/or to dissipate substantially the same amount of
heat per unit length along the entire length of the conductor. For
example a first section may be made of a creep resistant metal
(such as, but not limited to Inconel 617 or HR120) and a second
section of the conductor may be made of 304 stainless steel. The
creep resistant first section may help to support the second
section. The cross sectional area of the first section may be
larger than the cross sectional area of the second section. The
larger cross sectional area of the first section may allow for
greater strength of the first section. Higher resistivity
properties of the first section may allow the first section to
dissipate the same amount of heat per unit length as the smaller
cross sectional area second section.
[0417] In some embodiments, the cross sectional area and/or the
metal used for a particular section may be chosen so that a
particular section provides greater (or lesser) heat dissipation
per unit length than an adjacent section. More heat may be provided
near an interface between a hydrocarbon layer and a non-hydrocarbon
layer (e.g., the overburden and the coal formation) to counteract
end effects and allow for more uniform heat dissipation into the
coal formation. A higher heat dissipation may also be located at a
lower end of an elongated member to counteract end effects and
allow for more uniform heat dissipation.
[0418] In an embodiment, an elongated member may be disposed within
an opening (e.g., an open wellbore) in a coal formation. The
opening may preferably be an uncased opening in the coal formation.
The opening may have a diameter of at least approximately 5 cm or,
for example, approximately 8 cm. The diameter of the opening may
vary, however, depending on, for example, a desired heating rate in
the formation. The elongated member may be a length (e.g., a strip)
of metal or any other elongated piece of metal (e.g., a rod). The
elongated member may include stainless steel. The elongated member,
however, may also include any conductive material configurable to
generate heat to sufficiently heat a portion of the formation and
to substantially withstand a corresponding temperature within the
opening, for example, it may be configured to withstand corrosion
at the temperature within the opening.
[0419] An elongated member may be a bare metal heater. "Bare metal"
refers to a metal that does not include a layer of electrical
insulation, such as mineral insulation, that is designed to provide
electrical insulation for the metal throughout an operating
temperature range of the elongated member. Bare metal may encompass
a metal that includes a corrosion inhibiter such as a naturally
occurring oxidation layer, an applied oxidation layer, and/or a
film. Bare metal includes metal with polymeric or other types of
electrical insulation that cannot retain electrical insulating
properties at typical operating temperature of the elongated
member. Such material may be placed on the metal and may be
thermally degraded during use of the heater.
[0420] An elongated member may have a length of about 650 meters.
Longer lengths may be achieved using sections of high strength
alloys, but such elongated members may be expensive. In some
embodiments, an elongated member may be supported by a plate in a
wellhead. The elongated member may include sections of different
conductive materials that are welded together end-to-end. A large
amount of electrically conductive weld material may be used to
couple the separate sections together to increase strength of the
resulting member and to provide a path for electricity to flow that
will not result in arcing and/or corrosion at the welded
connections. The different conductive materials may include alloys
with a high creep resistance. The sections of different conductive
materials may have varying diameters to ensure uniform heating
along the elongated member. A first metal that has a higher creep
resistance than a second metal typically has a higher resistivity
than the second metal. The difference in resistivities may allow a
section of larger cross sectional area, more creep resistant first
metal to dissipate the same amount of heat as a section of smaller
cross sectional area second metal. The cross sectional areas of the
two different metals may be tailored to result in substantially the
same amount of heat dissipation in two welded together sections of
the metals. The conductive materials may include, but are not
limited to, 617 Inconel, HR-120, 316 stainless steel, and 304
stainless steel. For example, an elongated member may have a 60
meter section of 617 Inconel, 60 meter section of HR-120, and 150
meter section of 304 stainless steel. In addition, the elongated
member may have a low resistance section that may run from the
wellhead through the overburden. This low resistance section may
decrease the heating within the formation from the wellhead through
the overburden. The low resistance section may be the result of,
for example, choosing a substantially electrically conductive
material and/or increasing the cross-sectional area available for
electrical conduction.
[0421] Alternately, a support member may extend through the
overburden, and the bare metal elongated member or members may be
coupled to a plate, a centralizer or other type of support member
near an interface between the overburden and the hydrocarbon
formation. A low resistivity cable, such as a stranded copper
cable, may extend along the support member and may be coupled to
the elongated member or members. The copper cable may be coupled to
a power source that supplies electricity to the elongated member or
members.
[0422] FIG. 25 illustrates an embodiment of a plurality of
elongated members configured to heat a section of a coal formation.
Two or more (e.g., four) elongated members 600 may be supported by
support member 604. Elongated members 600 may be coupled to support
member 604 using insulated centralizers 602. Support member 604 may
be a tube or conduit. Support member 604 may also be a perforated
tube. Support member 604 may be configured to provide a flow of an
oxidizing fluid into opening 514. Support member 604 may have a
diameter between about 1.2 cm to about 4 cm and more preferably
about 2.5 cm. Support member 604, elongated members 600, and
insulated centralizers 602 may be disposed in opening 514 in
formation 516. Insulated centralizers 602 may be configured to
maintain a location of elongated members 600 on support member 604
such that lateral movement of elongated members 600 may be
substantially inhibited at temperatures high enough to deform
support member 604 or elongated members 600. Insulated centralizers
602 may be a centralizer as described herein. Elongated members
600, in some embodiments, may be metal strips of about 2.5 cm wide
and about 0.3 cm thick stainless steel. Elongated members 600,
however, may also include a pipe or a rod formed of a conductive
material. Electrical current may be applied to elongated members
600 such that elongated members 600 may generate heat due to
electrical resistance.
[0423] Elongated members 600 may be configured to generate heat of
approximately 650 watts per meter of elongated members 600 to
approximately 1650 watts per meter of elongated members 600. In
this manner, elongated members 600 may be at a temperature of
approximately 480.degree. C. to approximately 815.degree. C.
Substantially uniform heating of a coal formation may be provided
along a length of elongated members 600 greater than about 305 m
or, maybe, greater than about 610 m. A length of elongated members
600 may vary, however, depending on, for example, a type of coal
formation, a depth of an opening in the formation, and/or a length
of the formation desired for treating Elongated members 600 may be
electrically coupled in series. Electrical current may be supplied
to elongated members 600 using lead-in conductor 572. Lead-in
conductor 572 may be further configured as described herein.
Lead-in conductor 572 may be coupled to wellhead 690. Electrical
current may be returned to wellhead 690 using lead-out conductor
606 coupled to elongated members 600. Lead-in conductor 572 and
lead-out conductor 606 may be coupled to wellhead 690 at surface
550 through a sealing flange located between wellhead 690 and
overburden 540. The sealing flange may substantially inhibit fluid
from escaping from opening 514 to surface 550. Lead-in conductor
572 and lead-out conductor 606 may be coupled to elongated members
using a cold pin transition conductor. The cold pin transition
conductor may include an insulated conductor of substantially low
resistance such that substantially no heat may be generated by the
cold pin transition conductor. The cold pin transition conductor
may be coupled to lead-in conductor 572, lead-out conductor 606,
and/or elongated members 600 by any splicing or welding methods
known in the art. The cold pin transition conductor may provide a
temperature transition between lead-in conductor 572, lead-out
conductor 606, and/or elongated members 600. The cold pin
transition conductor may be further configured as described in any
of the embodiments herein. Lead-in conductor 572 and lead-out
conductor 606 may be made of low resistance conductors such that
substantially no heat may be generated from electrical current
passing through lead-in conductor 572 and lead-out conductor
606.
[0424] Weld beads may be placed beneath the centralizers 602 on the
support member 604 to fix the position of the centralizers. Weld
beads may be placed on the elongated members 600 above the
uppermost centralizer to fix the position of the elongated members
relative to the support member (other types of connecting
mechanisms may also be used). When heated, the elongated member may
thermally expand downwards. The elongated member may be formed of
different metals at different locations along a length of the
elongated member to allow relatively long lengths to be formed. For
example, a "U" shaped elongated member may include a first length
formed of 310 stainless steel, a second length formed of 304
stainless steel welded to the first length, and a third length
formed of 310 stainless steel welded to the second length. 310
stainless steel is more resistive than 304 stainless steel and may
dissipate approximately 25% more energy per unit length than 304
stainless steel of the same dimensions. 310 stainless steel may be
more creep resistant than 304 stainless steel. The first length and
the third length may be formed with cross sectional areas that
allow the first length and third lengths to dissipate as much heat
as a smaller cross area section of 304 stainless steel. The first
and third lengths may be positioned close to the wellhead 690. The
use of different types of metal may allow the formation of long
elongated members. The different metals may be, but are not limited
to, 617 Inconel, HR120, 316 stainless steel, 310 stainless steel,
and 304 stainless steel.
[0425] Packing material 542 may be placed between overburden casing
541 and opening 514. Packing material 542 may be configured to
inhibit fluid flowing from opening 514 to surface 550 and to
inhibit corresponding heat losses towards the surface. Packing
material 542 may be further configured as described herein.
Overburden casing 541 may be placed in cement 544 in overburden 540
of formation 516. Overburden casing 541 may be further configured
as described herein. Surface conductor 545 may be disposed in
cement 544. Surface conductor 545 may be configured as described
herein. Support member 604 may be coupled to wellhead 690 at
surface 550 of formation 516. Centralizer 581 may be configured to
maintain a location of support member 604 within overburden casing
541. Centralizer 581 may be further configured as described herein.
Electrical current may be supplied to elongated members 600 to
generate heat. Heat generated from elongated members 600 may
radiate within opening 514 to heat at least a portion of formation
516.
[0426] The oxidizing fluid may be provided along a length of the
elongated members 600 from oxidizing fluid source 508. The
oxidizing fluid may inhibit carbon deposition on or proximate to
the elongated members. For example, the oxidizing fluid may react
with hydrocarbons to form carbon dioxide, which may be removed from
the opening. Openings 605 in support member 604 may be configured
to provide a flow of the oxidizing fluid along the length of
elongated members 600. Openings 605 may be critical flow orifices
as configured and described herein. Alternatively, a tube may be
disposed proximate to elongated members 600 to control the pressure
in the formation as described in above embodiments. In another
embodiment, a tube may be disposed proximate to elongated members
600 to provide a flow of oxidizing fluid into opening 514. Also, at
least one of elongated members 600 may include a tube having
openings configured to provide the flow of oxidizing fluid. Without
the flow of oxidizing fluid, carbon deposition may occur on or
proximate to elongated members 600 or on insulated centralizers
602, thereby causing shorting between elongated members 600 and
insulated centralizers 602 or hot spots along elongated members
600. The oxidizing fluid may be used to react with the carbon in
the formation as described herein. The heat generated by reaction
with the carbon may complement or supplement the heat generated
electrically.
[0427] In an embodiment, a plurality of elongated members may be
supported on a support member disposed in an opening. The plurality
of elongated members may be electrically coupled in either a series
or parallel configuration. A current and voltage applied to the
plurality of elongated members may be selected such that the cost
of the electrical supply of power at the surface in conjunction
with the cost of the plurality of elongated members may be
minimized. In addition, an operating current and voltage may be
chosen to optimize a cost of input electrical energy in conjunction
with a material cost of the elongated members. The elongated
members may be configured to generate and radiate heat as described
herein. The elongated members may be installed in opening 514 as
described herein.
[0428] In an embodiment, a bare metal elongated member may be
formed in a "U" shape (or hairpin) and the member may be suspended
from a wellhead or from a positioner placed at or near an interface
between the overburden and the formation to be heated. In certain
embodiments, the bare metal heaters are formed of rod stock.
Cylindrical, high alumina ceramic electrical insulators may be
placed over legs of the elongated members. Tack welds along lengths
of the legs may fix the position of the insulators. The insulators
may inhibit the elongated member from contacting the formation or a
well casing (if the elongated member is placed within a well
casing). The insulators may also inhibit legs of the "U" shaped
members from contacting each other. High alumina ceramic electrical
insulators may be purchased from Cooper Industries (Houston, Tex.).
In an embodiment, the "U" shaped member may be formed of different
metals having different cross sectional areas so that the elongated
members may be relatively long and may dissipate substantially the
same amount of heat per unit length along the entire length of the
elongated member. The use of different welded together sections may
result in an elongated member that has large diameter sections near
a top of the elongated member and a smaller diameter section or
sections lower down a length of the elongated member. For example,
an embodiment of an elongated member has two 7/8 inch (2.2 cm)
diameter first sections, two 1/2 inch (1.3 cm) middle sections, and
a 3/8 inch (0.95 cm) diameter bottom section that is bent into a
"U" shape. The elongated member may be made of materials with other
cross section shapes such as ovals, squares, rectangles, triangles,
etc. The sections may be formed of alloys that will result in
substantially the same heat dissipation per unit length for each
section.
[0429] In some embodiments, the cross sectional area and/or the
metal used for a particular section may be chosen so that a
particular section provides greater (or lesser) heat dissipation
per unit length than an adjacent section. More heat dissipation per
unit length may be provided near an interface between a hydrocarbon
layer and a non-hydrocarbon layer (e.g., the overburden and the
coal formation) to counteract end effects and allow for more
uniform heat dissipation into the coal formation. A higher heat
dissipation may also be located at a lower end of an elongated
member to counteract end effects and allow for more uniform heat
dissipation.
[0430] FIG. 26 illustrates an embodiment of a surface combustor
configured to heat a section of a coal formation. Fuel fluid 611
may be provided into burner 610 through conduit 617. An oxidizing
fluid may be provided into burner 610 from oxidizing fluid source
508. Fuel fluid 611 may be oxidized with the oxidizing fluid in
burner 610 to form oxidation products 613. Fuel fluid 6111 may
include, for example, hydrogen. Fuel fluid 611 may also include
methane or any other hydrocarbon fluids. Burner 610 may be located
external to formation 516 or within an opening 614 in the coal
formation 516. Flame 618 may be configured to heat fuel fluid 611
to a temperature sufficient to support oxidation in burner 610.
Flame 618 may be configured to heat fuel fluid 611 to a temperature
of about 1425.degree. C. Flame 618 may be coupled to an end of
conduit 617. Flame 618 may be a pilot flame. The pilot flame may be
configured to burn with a small flow of fuel fluid 611. Flame 618
may, however, be an electrical ignition source.
[0431] Oxidation products 613 may be provided into opening 614
within inner conduit 612 coupled to burner 610. Heat may be
transferred from oxidation products 613 through outer conduit 615
into opening 614 and to formation 516 along a length of inner
conduit 612. Therefore, oxidation products 613 may substantially
cool along the length of inner conduit 612. For example, oxidation
products 613 may have a temperature of about 870.degree. C.
proximate top of inner conduit 612 and a temperature of about
650.degree. C. proximate bottom of inner conduit 612. A section of
inner conduit 612 proximate to burner 610 may have ceramic
insulator 612b disposed on an inner surface of inner conduit 612.
Ceramic insulator 612b may be configured to substantially inhibit
melting of inner conduit 612 and/or insulation 612a proximate to
burner 610. Opening 614 may extend into the formation a length up
to about 550 m below surface 550.
[0432] Inner conduit 612 may be configured to provide oxidation
products 613 into outer conduit 615 proximate a bottom of opening
614. Inner conduit 612 may have insulation 612a. FIG. 27
illustrates an embodiment of inner conduit 612 with insulation 612a
and ceramic insulator 612b disposed on an inner surface of inner
conduit 612. Insulation 612a may be configured to substantially
inhibit heat transfer between fluids in inner conduit 612 and
fluids in outer conduit 615. A thickness of insulation 612a may be
varied along a length of inner conduit 612 such that heat transfer
to formation 516 may vary along the length of inner conduit 612.
For example, a thickness of insulation 612a may be tapered to from
a larger thickness to a lesser thickness from a top portion to a
bottom portion, respectively, of inner conduit 612 in opening 614.
Such a tapered thickness may provide substantially more uniform
heating of formation 516 along the length of inner conduit 612 in
opening 614. Insulation 612a may include ceramic and metal
materials. Oxidation products 613 may return to surface 550 through
outer conduit 615. Outer conduit may have insulation 615a as
depicted in FIG. 26. Insulation 615a may be configured to
substantially inhibit heat transfer from outer conduit 615 to
overburden 540.
[0433] Oxidation products 613 may be provided to an additional
burner through conduit 619 at surface 550. Oxidation products 613
may be configured as a portion of a fuel fluid in the additional
burner. Doing so may increase an efficiency of energy output versus
energy input for heating formation 516. The additional burner may
be configured to provide heat through an additional opening in
formation 516.
[0434] In some embodiments, an electric heater may be configured to
provide heat in addition to heat provided from a surface combustor.
The electric heater may be, for example, an insulated conductor
heater or a conductor-in-conduit heater as described in any of the
above embodiments. The electric heater may be configured to provide
the additional heat to a coal formation such that the coal
formation may be heated substantially uniformly along a depth of an
opening in the formation.
[0435] Flameless combustors such as those described in U.S. Pat.
No. 5,255,742 to Mikus et al., U.S. Pat. No. 5,404,952 to Vinegar
et al., U.S. Pat. No. 5,862,858 to Wellington et al., and U.S. Pat.
No. 5,899,269 to Wellington et al., which are incorporated by
reference as if fully set forth herein, may be configured to heat a
coal formation.
[0436] FIG. 28 illustrates an embodiment of a flameless combustor
configured to heat a section of the coal formation. The flameless
combustor may include center tube 637 disposed within inner conduit
638. Center tube 637 and inner conduit 638 may be placed within
outer conduit 636. Outer conduit 636 may be disposed within opening
514 in formation 516. Fuel fluid 621 may be provided into the
flameless combustor through center tube 637. Fuel fluid 621 may
include any of the fuel fluids described herein. If a hydrocarbon
fuel such as methane is utilized, it may be mixed with steam to
prevent coking in center tube 637. If hydrogen is used as the fuel,
no steam may be required.
[0437] Center tube 637 may include flow mechanisms 635 (e.g., flow
orifices) disposed within an oxidation region to allow a flow of
fuel fluid 621 into inner conduit 638. Flow mechanisms 635 may
control a flow of fuel fluid 621 into inner conduit 638 such that
the flow of fuel fluid 621 is not dependent on a pressure in inner
conduit 638. Flow mechanisms 635 may have characteristics as
described herein. Oxidizing fluid 623 may be provided into the
combustor through inner conduit 638. Oxidizing fluid 623 may be
provided from oxidizing fluid source 508. Oxidizing fluid 623 may
include any of the oxidizing fluids as described in above
embodiments. Flow mechanisms 635 on center tube 637 may be
configured to inhibit flow of oxidizing fluid 623 into center tube
637.
[0438] Oxidizing fluid 621 may mix with fuel fluid 621 in the
oxidation region of inner conduit 638. Either oxidizing fluid 623
or fuel fluid 621, or a combination of both, may be preheated
external to the combustor to a temperature sufficient to support
oxidation of fuel fluid 621. Oxidation of fuel fluid 621 may
provide heat generation within outer conduit 636. The generated
heat may provide heat to at least a portion of a coal formation
proximate to the oxidation region of inner conduit 638. Products
625 from oxidation of fuel fluid 621 may be removed through outer
conduit 636 outside inner conduit 638. Heat exchange between the
downgoing oxidizing fluid and the upgoing combustion products in
the overburden results in enhanced thermal efficiency. A flow of
removed combustion products 625 may be balanced with a flow of fuel
fluid 621 and oxidizing fluid 623 to maintain a temperature above
autoignition temperature but below a temperature sufficient to
produce substantial oxides of nitrogen. Also, a constant flow of
fluids may provide a substantially uniform temperature distribution
within the oxidation region of inner conduit 638. Outer conduit 636
may be, for example, a stainless steel tube. In this manner,
heating of at least the portion of the coal formation may be
substantially uniform. As described above, the lower operating
temperature may also provide a less expensive metallurgical cost
associated with the heating system.
[0439] Certain heat source embodiments may include an operating
system that is coupled to any of heat sources such by insulated
conductors or other types of wiring. The operating system may be
configured to interface with the heat source. The operating system
may receive a signal (e.g., an electromagnetic signal) from a
heater that is representative of a temperature distribution of the
heat source. Additionally, the operating system may be further
configured to control the heat source, either locally or remotely.
For example, the operating system may alter a temperature of the
heat source by altering a parameter of equipment coupled to the
heat source. Therefore, the operating system may monitor, alter,
and/or control the heating of at least a portion of the
formation.
[0440] In some embodiments, a heat source as described above may be
configured to substantially operate without a control and/or
operating system. The heat source may be configured to only require
a power supply from a power source such as an electric transformer.
For example, a conductor-in-conduit heater and/or an elongated
member heater may include conductive materials that may be have a
thermal property that self-controls a heat output of the heat
source. In this manner, the conductor-in-conduit heater and/or the
elongated member heater may be configured to operate throughout a
temperature range without external control. A conductive material
such as stainless steel may be used in the heat sources. Stainless
steel may have a resistivity that increases with temperature, thus,
providing a greater heat output at higher temperatures.
[0441] Leakage current of any of the heat sources described herein
may be monitored. For example, an increase in leakage current may
show deterioration in an insulated conductor heater. Voltage
breakdown in the insulated conductor heater may cause failure of
the heat source. Furthermore, a current and voltage applied to any
of the heat sources may also be monitored. The current and voltage
may be monitored to assess/indicate resistance in a heat source.
The resistance in the heat source may be configured to represent a
temperature in the heat source since the resistance of the heat
source may be known as a function of temperature. Another
alternative method may include monitoring a temperature of a heat
source with at least one thermocouple placed in or proximate to the
heat source. In some embodiments, a control system may monitor a
parameter of the heat source. The control system may alter
parameters of the heat source such that the heat source may provide
a desired output such as heating rate and/or temperature
increase.
[0442] In some embodiments, a thermowell may be disposed into an
opening in a coal formation that includes a heat source. The
thermowell may be disposed in an opening that may or may not have a
casing. In the opening without a casing, the thermowell may include
appropriate metallurgy and thickness such that corrosion of the
thermowell is substantially inhibited. A thermowell and temperature
logging process, such as that described in U.S. Pat. No. 4,616,705
issued to Stegemeier et al., which is incorporated by reference as
if fully set forth herein, may be used to monitor temperature. Only
selected wells may be equipped with thermowells to avoid expenses
associated with installing and operating temperature monitors at
each heat source.
[0443] In some embodiments, a heat source may be turned down and/or
off after an average temperature in a formation may have reached a
selected temperature. Turning down and/or off the heat source may
reduce input energy costs, substantially inhibit overheating of the
formation, and allow heat to substantially transfer into colder
regions of the formation.
[0444] Certain embodiments include providing heat to a first
portion of a coal formation from one or more heat sources. In
addition, certain embodiments may include producing formation
fluids from the first portion, and maintaining a second portion of
the formation in a substantially unheated condition. The second
portion may be substantially adjacent to the first portion of the
formation. In this manner, the second portion may provide
structural strength to the formation. Furthermore, heat may also be
provided to a third portion of the formation. The third portion may
be substantially adjacent to the second portion and/or laterally
spaced from the first portion. In addition, formation fluids may be
produced from the third portion of the formation. In this manner, a
processed formation may have a pattern that may resemble, for
example, a striped or checkerboard pattern with alternating heated
and unheated portions.
[0445] Additional portions of the formation may also include such
alternating heated and unheated portions. In this manner, such
patterned heating of a coal formation may maintain structural
strength within the formation. Maintaining structural strength
within a coal formation may substantially inhibit subsidence.
Subsidence of a portion of the formation being processed may
decrease a permeability of the processed portion due to compaction.
In addition, subsidence may decrease the flow of fluids in the
formation, which may result in a lower production of formation
fluids.
[0446] A pyrolysis temperature range may depend on specific types
of hydrocarbons within the formation. A pyrolysis temperature range
may include temperatures, for example, between approximately
250.degree. C. and about 900.degree. C. Alternatively, a pyrolysis
temperature range may include temperatures between about
250.degree. C. to about 400.degree. C. For example, a majority of
formation fluids may be produced within a pyrolysis temperature
range from about 250.degree. C. to about 400.degree. C. If a coal
formation is heated throughout the entire pyrolysis range, the
formation may produce only small amounts of hydrogen towards the
upper limit of the pyrolysis range. After all of the available
hydrogen has been depleted, little fluid production from the
formation would occur.
[0447] Temperature (and average temperatures) within a heated coal
formation may vary, depending on, for example, proximity to a heat
source, thermal conductivity and thermal diffusivity of the
formation, type of reaction occurring, type of coal formation, and
the presence of water within the coal formation. A temperature
within the coal formation may be assessed using a numerical
simulation model. The numerical simulation model may assess and/or
calculate a subsurface temperature distribution. In addition, the
numerical simulation model may include assessing various properties
of a subsurface formation under the assessed temperature
distribution.
[0448] For example, the various properties of the subsurface
formation may include, but are not limited to, thermal conductivity
of the subsurface portion of the formation and permeability of the
subsurface portion of the formation. The numerical simulation model
may also include assessing various properties of a fluid formed
within a subsurface formation under the assessed temperature
distribution. For example, the various properties of a formed fluid
may include, but are not limited to, a cumulative volume of a fluid
formed at a subsurface of the formation, fluid viscosity, fluid
density, and a composition of the fluid formed at a subsurface of
the formation. Such a simulation may be used to assess the
performance of commercial-scale operation of a small-scale field
experiment as described herein. For example, a performance of a
commercial-scale development may be assessed based on, but not
limited to, a total volume of product that may be produced from a
commercial-scale operation.
[0449] In some embodiments, an in situ conversion process may
increase a temperature or average temperature within a coal
formation. A temperature or average temperature increase (.DELTA.T)
in a specified volume (V) of the coal formation may be assessed for
a given heat input rate (q) over time (t) by the following
equation: 1 T = ( q * t ) C V * B * V
[0450] In this equation, an average heat capacity of the formation
(C.sub.v) and an average bulk density of the formation
(.rho..sub.B) may be estimated or determined using one or more
samples taken from the coal formation.
[0451] In alternate embodiments, an in situ conversion process may
include heating a specified volume to a pyrolysis temperature or
average pyrolysis temperature. Heat input rate (q) during a time
(t) required to heat the specified volume (V) to a desired
temperature increase (.DELTA.T) may be determined or assessed using
the following equation: .SIGMA.q*t=.DELTA.T*C.sub.v*.rho..sub.B*V.
In this equation, an average heat capacity of the formation
(C.sub.v) and an average bulk density of the formation
(.rho..sub.B) may be estimated or determined using one or more
samples taken from the coal formation.
[0452] It is to be understood that the above equations can be used
to assess or estimate temperatures, average temperatures (e.g.,
over selected sections of the formation), heat input, etc. Such
equations do not take into account other factors (such as heat
losses) that would also have some effect on heating and
temperatures assessments. However such factors can ordinarily be
addressed with correction factors, as is commonly done in the
art.
[0453] In some embodiments, a portion of a coal formation may be
heated at a heating rate in a range from about 0.1.degree. C./day
to about 50.degree. C./day. Alternatively, a portion of a coal
formation may be heated at a heating rate in a range of about
0.1.degree. C./day to about 10.degree. C./day. For example, a
majority of hydrocarbons may be produced from a formation at a
heating rate within a range of about 0.1.degree. C./day to about
10.degree. C./day. In addition, a coal formation may be heated at a
rate of less than about 0.7.degree. C./day through a significant
portion of a pyrolysis temperature range. The pyrolysis temperature
range may include a range of temperatures as described in above
embodiments. For example, the heated portion may be heated at such
a rate for a time greater than 50% of the time needed to span the
temperature range, more than 75% of the time needed to span the
temperature range, or more than 90% of the time needed to span the
temperature range.
[0454] A rate at which a coal formation is heated may affect the
quantity and quality of the formation fluids produced from the coal
formation. For example, heating at high heating rates, as is the
case when a Fischer Assay is conducted, may produce a larger
quantity of condensable hydrocarbons from a coal formation. The
products of such a process, however, may be of a significantly
lower quality than when heating using heating rates less than about
10.degree. C./day. Heating at a rate of temperature increase less
than approximately 10.degree. C./day may allow pyrolysis to occur
within a pyrolysis temperature range in which production of
undesirable products and tars may be reduced. In addition, a rate
of temperature increase of less than about 3.degree. C./day may
further increase the quality of the produced condensable
hydrocarbons by further reducing the production of undesirable
products and further reducing production of tars within a coal
formation.
[0455] In some embodiments, controlling temperature within a coal
formation may involve controlling a heating rate within the
formation. For example, controlling the heating rate such that the
heating rate may be less than approximately 3.degree. C./day may
provide better control of a temperature within the coal
formation.
[0456] An in situ process for hydrocarbons may include monitoring a
rate of temperature increase at a production well. A temperature
within a portion of a coal formation, however, may be measured at
various locations within the portion of the coal formation. For
example, an in situ process may include monitoring a temperature of
the portion at a midpoint between two adjacent heat sources. The
temperature may be monitored over time. In this manner, a rate of
temperature increase may also be monitored. A rate of temperature
increase may affect a composition of formation fluids produced from
the formation. As such, a rate of temperature increase may be
monitored, altered and/or controlled, for example, to alter a
composition of formation fluids produced from the formation.
[0457] In some embodiments, a power (Pwr) required to generate a
heating rate (h) in a selected volume (V) of a coal formation may
be determined by the following equation:
Pwr=h*V*C.sub.v*.rho..sub.B. In this equation, an average heat
capacity of the coal formation may be described as C.sub.v. The
average heat capacity of the coal formation may be a relatively
constant value. Average heat capacity may be estimated or
determined using one or more samples taken from a coal formation,
or measured in situ using a thermal pulse test. Methods of
determining average heat capacity based on a thermal pulse test are
described by I. Berchenko, E. Detournay, N. Chandler, J. Martino,
and E. Kozak, "In-situ measurement of some thermoporoelastic
parameters of a granite" in Poromechanics, A Tribute to Maurice A.
Biot, pages 545-550, Rotterdam, 1998 (Balkema), which is
incorporated by reference as if fully set forth herein.
[0458] In addition, an average bulk density of the coal formation
may be described as .rho..sub.B. The average bulk density of the
coal formation may be a relatively constant value. Average bulk
density may be estimated or determined using one or more samples
taken from a coal formation. In certain embodiments the product of
average heat capacity and average bulk density of the coal
formation may be a relatively constant value (such product can be
assessed in situ using a thermal pulse test). A determined power
may be used to determine heat provided from a heat source into the
selected volume such that the selected volume may be heated at a
heating rate, h. For example, a heating rate may be less than about
3.degree. C./day, and even less than about 2.degree. C./day. In
this manner, a heating rate within a range of heating rates may be
maintained within the selected volume. It is to be understood that
in this context "power" is used to describe energy input per time.
The form of such energy input may, however, vary as described
herein (i.e., energy may be provided from electrical resistance
heaters, combustion heaters, etc.).
[0459] The heating rate may be selected based on a number of
factors including, but not limited to, the maximum temperature
possible at the well, a predetermined quality of formation fluids
that may be produced from the formation, etc. A quality of
hydrocarbon fluids may be defined by an API gravity of condensable
hydrocarbons, by olefin content, by the nitrogen, sulfur and/or
oxygen content, etc. In an embodiment, heat may be provided to at
least a portion of a coal formation to produce formation fluids
having an API gravity of greater than about 20.degree.. The API
gravity may vary, however, depending on, for example, the heating
rate and a pressure within the portion of the formation.
[0460] In some embodiments, subsurface pressure in a coal formation
may correspond to the fluid pressure generated within the
formation. Heating hydrocarbons within a coal formation may
generate fluids, for example, by pyrolysis. The generated fluids
may be vaporized within the formation. Fluids that contribute to
the increase in pressure may include, but are not limited to,
fluids produced during pyrolysis and water vaporized during
heating. The produced pyrolysis fluids may include, but are not
limited to, hydrocarbons, water, oxides of carbon, ammonia,
molecular nitrogen, and molecular hydrogen. Therefore, as
temperatures within a selected section of a heated portion of the
formation increase, a pressure within the selected section may
increase as a result of increased fluid generation and vaporization
of water.
[0461] In some embodiments, pressure within a selected section of a
heated portion of a coal formation may vary depending on, for
example, depth, distance from a heat source, a richness of the
hydrocarbons within the coal formation, and/or a distance from a
producer well. Pressure within a formation may be determined at a
number of different locations, which may include but may not be
limited to, at a wellhead and at varying depths within a wellbore.
In some embodiments, pressure may be measured at a producer well.
In alternate embodiments, pressure may be measured at a heater
well.
[0462] Heating of a coal formation to a pyrolysis temperature range
may occur before substantial permeability has been generated within
the coal formation. An initial lack of permeability may prevent the
transport of generated fluids from a pyrolysis zone within the
formation. In this manner, as heat is initially transferred from a
heat source to a coal formation, a fluid pressure within the coal
formation may increase proximate to a heat source. Such an increase
in fluid pressure may be caused by, for example, generation of
fluids during pyrolysis of at least some hydrocarbons in the
formation. The increased fluid pressure may be released, monitored,
altered, and/or controlled through such a heat source. For example,
the heat source may include a valve as described in above
embodiments. Such a valve may be configured to control a flow rate
of fluids out of and into the heat source. In addition, the heat
source may include an open hole configuration through which
pressure may be released.
[0463] Alternatively, pressure generated by expansion of pyrolysis
fluids or other fluids generated in the formation may be allowed to
increase although an open path to the production well or any other
pressure sink may not yet exist in the formation. In addition, a
fluid pressure may be allowed to increase to a lithostatic
pressure. Fractures in the coal formation may form when the fluid
pressure equals or exceeds the lithostatic pressure. For example,
fractures may form from a heat source to a production well. The
generation of fractures within the heated portion may reduce
pressure within the portion due to the production of formation
fluids through a production well. To maintain a selected pressure
within the heated portion, a back pressure may be maintained at the
production well.
[0464] Fluid pressure within a coal formation may vary depending
upon, for example, thermal expansion of hydrocarbons, generation of
pyrolysis fluids, and withdrawal of generated fluids from the
formation. For example, as fluids are generated within the
formation a fluid pressure within the pores may increase. Removal
of generated fluids from the formation may decrease a fluid
pressure within the formation.
[0465] In an embodiment, a pressure may be increased within a
selected section of a portion of a coal formation to a selected
pressure during pyrolysis. A selected pressure may be within a
range from about 2 bars absolute to about 72 bars absolute or, in
some embodiments, 2 bars absolute to 36 bars absolute.
Alternatively, a selected pressure may be within a range from about
2 bars absolute to about 18 bars absolute. For example, in certain
embodiments, a majority of hydrocarbon fluids may be produced from
a formation having a pressure within a range from about 2 bars
absolute to about 18 bars absolute. The pressure during pyrolysis
may vary or be varied. The pressure may be varied to alter and/or
control a composition of a formation fluid produced, to control a
percentage of condensable fluid as compared to non-condensable
fluid, and/or to control an API gravity of fluid being produced.
For example, decreasing pressure may result in production of a
larger condensable fluid component, and the fluid may contain a
larger percentage of olefins, and vice versa.
[0466] It is believed that pyrolyzing at reduced temperature and
increased pressure may decrease an olefin to paraffin ratio in
produced fluids. Pyrolyzing coal for a longer period of time, which
may be accomplished by increasing pressure within the system, tends
to result in a lower average molecular weight oil and higher API
gravity. In addition, production of gas may increase and a
non-volatile coke may be formed.
[0467] In addition, it is believed that operating at high pressure
and a pyrolysis temperature at the lower end of the pyrolysis zone
tends to decrease the fraction of fluids with carbon numbers
greater than 25 produced from the coal.
[0468] It is believed that lower temperatures and/or increased
partial pressure of hydrogen in the coal formation will tend to
produce less olefins in the produced hydrocarbon fluids. In
addition, lower temperatures and/or higher partial pressures of
hydrogen also tend to increase the atomic hydrogen to atomic carbon
ratio in the produced hydrocarbon fluids.
[0469] It is believed that at higher pyrolysis temperatures
production of oil liquids tends to be higher than at the lower
pyrolysis temperatures. In addition, high pressures tend to
decrease the quantity of oil liquids produced from a coal
formation. Operating an in situ conversion process at low pressures
and high temperatures may produce a higher quantity of oil liquids
than operating at low temperatures and high pressures.
[0470] In certain embodiments, pressure within a portion of a coal
formation will increase due to fluid generation within the heated
portion. In addition, such increased pressure may be maintained
within the heated portion of the formation. For example, increased
pressure within the formation may be maintained by bleeding off a
generated formation fluid through heat sources and/or by
controlling the amount of formation fluid produced from the
formation through production wells. Maintaining increased pressure
within a formation inhibits formation subsidence. In addition,
maintaining increased pressure within a formation tends to reduce
the required sizes of collection conduits that are used to
transport condensable hydrocarbons. Furthermore, maintaining
increased pressure within the heated portion may reduce and/or
substantially eliminate the need to compress formation fluids at
the surface because the formation products will usually be produced
at higher pressure. Maintaining increased pressure within a
formation may also facilitate generation of electricity from
produced non-condensable fluid. For example, the produced
non-condensable fluid may be passed through a turbine to generate
electricity.
[0471] Increased pressure in the formation may also be maintained
to produce more and/or improved formation fluids. In certain
embodiments, significant amounts (e.g., a majority) of the
formation fluids produced from a formation within the pyrolysis
pressure range may include non-condensable hydrocarbons. Pressure
may be selectively increased and/or maintained within the
formation, and formation fluids can be produced at or near such
increased and/or maintained pressures. As pressure within a
formation is increased, formation fluids produced from the
formation will, in many instances, include a larger portion of
non-condensable hydrocarbons. In this manner, a significant amount
(e.g., a majority) of the formation fluids produced at such a
pressure may include a lighter and higher quality condensable
hydrocarbons than formation fluids produced at a lower
pressure.
[0472] In addition, a pressure may be maintained within a heated
portion of a coal formation to substantially inhibit production of
formation fluids having carbon numbers greater than, for example,
about 25. For example, increasing a pressure within the portion of
the coal formation may increase a boiling point of a fluid within
the portion. Such an increase in the boiling point of a fluid may
substantially inhibit production of formation fluids having
relatively high carbon numbers, and/or production of multi-ring
hydrocarbon compounds, because such formation fluids tend to remain
in the formation as liquids until they crack.
[0473] In addition, increasing a pressure within a portion of a
coal formation may result in an increase in API gravity of
formation fluids produced from the formation. Higher pressures may
increase production of shorter chain hydrocarbon fluids, which may
have higher API gravity values.
[0474] In an embodiment, a pressure within a heated portion of the
formation may surprisingly increase the quality of relatively high
quality pyrolyzation fluids, the quantity of relatively high
quality pyrolyzation fluids, and/or vapor phase transport of the
pyrolyzation fluids within the formation. Increasing the pressure
often permits production of lower molecular weight hydrocarbons
since such lower molecular weight hydrocarbons will more readily
transport in the vapor phase in the formation. Generation of lower
molecular weight hydrocarbons (and corresponding increased vapor
phase transport) is believed to be due, in part, to autogenous
generation and reaction of hydrogen within a portion of the coal
formation. For example, maintaining an increased pressure may force
hydrogen generated in the heated portion into a liquid phase (e.g.
by dissolving). In addition, heating the portion to a temperature
within a pyrolysis temperature range may pyrolyze at least some of
the hydrocarbons within the formation to generate pyrolyzation
fluids in the liquid phase. The generated components may include a
double bond and/or a radical. H.sub.2 in the liquid phase may
reduce the double bond of the generated pyrolyzation fluids,
thereby reducing a potential for polymerization of the generated
pyrolyzation fluids. In addition, hydrogen may also neutralize
radicals in the generated pyrolyzation fluids. Therefore, H.sub.2
in the liquid phase may substantially inhibit the generated
pyrolyzation fluids from reacting with each other and/or with other
compounds in the formation. In this manner, shorter chain
hydrocarbons may enter the vapor phase and may be produced from the
formation.
[0475] Increasing the formation pressure to increase the amount of
pyrolyzation fluids in the vapor phase may significantly reduce the
potential for coking within the selected section of the formation.
A coking reaction may occur in the liquid phase. Since many of the
generated components may be transformed into short chain
hydrocarbons and may enter the vapor phase, coking within the
selected section may decrease.
[0476] Increasing the formation pressure to increase the amount of
pyrolyzation fluids in the vapor phase is also beneficial because
doing so permits increased recovery of lighter (and relatively high
quality) pyrolyzation fluids. In general, pyrolyzation fluids are
more quickly produced, with less residuals, when such fluids are in
the vapor phase rather than in the liquid phase. Undesirable
polymerization reactions also tend to occur more frequently when
the pyrolyzation fluids are in the liquid phase instead of the
vapor phase. In addition, when pyrolyzation fluids are produced in
the vapor phase, fewer production wells/area are needed, thereby
reducing project costs.
[0477] In an embodiment, a portion of a coal formation may be
heated to increase a partial pressure of H.sub.2. In some
embodiments, an increased H.sub.2 partial pressure may include
H.sub.2 partial pressures in a range from about 1 bar absolute to
about 7 bars absolute. Alternatively, an increased H.sub.2 partial
pressure range may include H.sub.2 partial pressures in a range
from about 5 bars absolute to about 7 bars absolute. For example, a
majority of hydrocarbon fluids may be produced within a range of
about 5 bars absolute to about 7 bars absolute. A range of H.sub.2
partial pressures within the pyrolysis H.sub.2 partial pressure
range may vary, however, depending on, for example, a temperature
and a pressure of the heated portion of the formation.
[0478] Maintaining a H.sub.2 partial pressure within the formation
of greater than atmospheric pressure may increase an API value of
produced condensable hydrocarbon fluids. For example, maintaining
such a H.sub.2 partial pressure may increase an API value of
produced condensable hydrocarbon fluids to greater than about 25
or, in some instances, greater than about 30. Maintaining such a
H.sub.2 partial pressure within a heated portion of a coal
formation may increase a concentration of H.sub.2 within the heated
portion such that H.sub.2 may be available to react with pyrolyzed
components of the hydrocarbons. Reaction of H.sub.2 with the
pyrolyzed components of hydrocarbons may reduce polymerization of
olefins into tars and other cross-linked, difficult to upgrade,
products. Such products may have lower API gravity values.
Therefore, production of hydrocarbon fluids having low API gravity
values may be substantially inhibited.
[0479] A valve may be configured to maintain, alter, and/or control
a pressure within a heated portion of a coal formation. For
example, a heat source disposed within a coal formation may be
coupled to a valve. The valve may be configured to release fluid
from the formation through the heater source. In addition, a
pressure valve may be coupled to a production well, which may be
disposed within the coal formation. In some embodiments, fluids
released by the valves may be collected and transported to a
surface unit for further processing and/or treatment.
[0480] An in situ conversion process for coal may include providing
heat to a portion of a coal formation, and controlling a
temperature, rate of temperature increase, and/or a pressure within
the heated portion. For example, a pressure within the heated
portion may be controlled using pressure valves disposed within a
heater well or a production well as described herein. A temperature
and/or a rate of temperature increase of the heated portion may be
controlled, for example, by altering an amount of energy supplied
to one or more heat sources.
[0481] Controlling a pressure and a temperature within a coal
formation will, in most instances, affect properties of the
produced formation fluids. For example, a composition or a quality
of formation fluids produced from the formation may be altered by
altering an average pressure and/or an average temperature in the
selected section of the heated portion. The quality of the produced
fluids may be defined by a property which may include, but may not
be limited to, API gravity, percent olefins in the produced
formation fluids, ethene to ethane ratio, atomic hydrogen to carbon
ratio, percent of hydrocarbons within produced formation fluids
having carbon numbers greater than 25, total equivalent production
(gas and liquid), total liquids production, and/or liquid yield as
a percent of Fischer Assay. For example, controlling the quality of
the produced formation fluids may include controlling average
pressure and average temperature in the selected section such that
the average assessed pressure in the selected section may be
greater than the pressure (p) as set forth in the form of the
following relationship for an assessed average temperature (T) in
the selected section: 2 p = exp [ A T + B ]
[0482] where p is measured in psia (pounds per square inch
absolute), T is measured in degrees Kelvin, A and B are parameters
dependent on the value of the selected property. An assessed
average temperature may be determined as described herein.
[0483] The relationship given above may be rewritten such that the
natural log of pressure may be a linear function of an inverse of
temperature. This form of the relationship may be rewritten:
ln(p)=A/T+B. In a plot of the absolute pressure as a function of
the reciprocal of the absolute temperature, A is the slope and B is
the intercept. The intercept B is defined to be the natural
logarithm of the pressure as the reciprocal of the temperature
approaches zero. Therefore, the slope and intercept values (A and
B) of the pressure-temperature relationship may be determined from
two pressure-temperature data points for a given value of a
selected property. The pressure-temperature data points may include
an average pressure within a formation and an average temperature
within the formation at which the particular value of the property
was, or may be, produced from the formation. For example, the
pressure-temperature data points may be obtained from an experiment
such as a laboratory experiment or a field experiment.
[0484] A relationship between the slope parameter, A, and a value
of a property of formation fluids may be determined. For example,
values of A may be plotted as a function of values of a formation
fluid property. A cubic polynomial may be fitted to these data. For
example, a cubic polynomial relationship such as
A=a.sub.1*(property).sup.3+a.sub.2*(prope-
rty).sup.2+a.sub.3*(property)+a.sub.4 may be fitted to the data,
where a.sub.1, a.sub.2, a.sub.3, and a.sub.4 are empirical
constants that may describe a relationship between the first
parameter, A, and a property of a formation fluid. Alternatively,
relationships having other functional forms such as another order
polynomial or a logarithmic function may be fitted to the data. In
this manner, a.sub.1, a.sub.2, . . . , may be estimated from the
results of the data fitting. Similarly, a relationship between the
second parameter, B, and a value of a property of formation fluids
may be determined. For example, values of B may be plotted as a
function of values of a property of a formation fluid. A cubic
polynomial may also be fitted to the data. For example, a cubic
polynomial relationship such as
B=b.sub.1*(property).sup.3+b.sub.2*(property).sup.2+-
b.sub.3*(property)+b.sub.4 may be fitted to the data, where
b.sub.1, b.sub.2, b.sub.3, and b.sub.4 are empirical constants that
may describe a relationship between the parameter B, and the value
of a property of a formation fluid. As such, b.sub.1, b.sub.2,
b.sub.3, and b.sub.4 may be estimated from results of fitting the
data. To determine an average pressure and an average temperature
that may be used to produce a formation fluid having a selected
property, the value of the selected property and the empirical
constants as described above may be used to determine values for
the first parameter A, and the second parameter B, according to the
following relationships:
A=a.sub.1*(property).sup.3+a.sub.2*(property).sup.2+a.sub.3*(property)+a.s-
ub.4
B=b.sub.1*(property).sup.3+b.sub.2*(property).sup.2+b.sub.3*(property)+b.s-
ub.4
[0485] The determined values for the parameter A, and the parameter
B, may be used to determine an average pressure in the selected
section of the formation using an assessed average temperature, T,
in the selected section. The assessed average temperature may be
determined as described herein. For example, an average pressure of
the selected section may be determined by the relationship:
p=exp[(A/T)+B], in which p is measured in psia, and T is measured
in degrees Kelvin. Alternatively, an average absolute pressure of
the selected section, measured in bars, may be determined using the
following relationship: p.sub.bars=exp[(A/T)+B-2.674- 4]. In this
manner, an average pressure within the selected section may be
controlled such that an average pressure within the selected
section is adjusted to the average pressure as determined above, in
order to produce a formation fluid from the selected section having
a selected property.
[0486] Alternatively, the determined values for the parameter A,
and the parameter B, may be used to determine an average
temperature in the selected section of the formation using an
assessed average pressure, p, in the selected section. The assessed
average pressure may be determined as described herein. Therefore,
using the relationship described above, an average temperature
within the selected section may be controlled to approximate the
calculated average temperature in order to produce hydrocarbon
fluids having a selected property.
[0487] As described herein, a composition of formation fluids
produced from a formation may be varied by altering at least one
operating condition of an in situ conversion process for coal. In
addition, at least one operating condition may be determined by
using a computer-implemented method. For example, an operating
condition may include, but is not limited to, a pressure in the
formation, a temperature in the formation, a heating rate of the
formation, a power supplied to a heat source, and/or a flow rate of
a synthesis gas generating fluid. The computer-implemented method
may include measuring at least one property of the formation. For
example, measured properties may include a thickness of a layer
containing coal, vitrinite reflectance, hydrogen content, oxygen
content, moisture content, depth/width of the coal formation, and
other properties otherwise described herein.
[0488] At least one measured property may be inputted into a
computer executable program. The program may be operable to
determine at least one operating condition from a measured
property. In addition, at least one property of selected formation
fluids may be input into the program. For example, properties of
selected formation fluids may include, but are not limited to, API
gravity, olefin content, carbon number distribution, ethene to
ethane ratio, and atomic carbon to hydrogen ratio. The program may
also be operable to determine at least one operating condition from
a property of the selected formation fluids. In this manner, an
operating condition of an in situ conversion process may be altered
to be approximate at least one determined operating condition such
that production of selected formation fluids from the formation may
increase.
[0489] In an embodiment, a computer-implemented method may be used
to determine at least one property of a formation fluid that may be
produced from a coal formation for a set of operating conditions as
a function of time. The method may include measuring at least one
property of the formation and providing at least the one measured
property to a computer program as described herein. In addition,
one or more sets of operating conditions may also be provided to
the computer program. At least one of the operating conditions may
include, for example, a heating rate or a pressure. One or more
sets of operating conditions may include currently used operating
conditions (in an in situ conversion process) or operating
conditions being considered for an in situ conversion process. The
computer program may be operable to determine at least one property
of a formation fluid that may be produced by an in situ conversion
process for coal as a function of time using at least one set of
operating conditions and at least one measured property of the
formation. Furthermore, the method may include comparing a
determined property of the fluid to a selected property. In this
manner, if multiple determined properties are generated by the
computer program, then the determined property that differs least
from a selected property may be determined.
[0490] Formation fluid properties may vary depending on a location
of a production well in the formation. For example, a location of a
production well with respect to a location of a heat source in the
formation may affect the composition of formation fluid produced
from a formation. In addition, a distance between a production well
and a heat source in a formation may be varied to alter the
composition of formation fluid produced from a formation.
Decreasing a distance between a production well and a heat source
may increase a temperature at the production well. In this manner,
a substantial portion of pyrolyzation fluids flowing through a
production well may in some instances crack to non-condensable
compounds due to increased temperature at a production well.
Therefore, a location of a production well with respect to a heat
source may be selected to increase a non-condensable gas fraction
of the produced formation fluids. In addition, a location of a
production well with respect to a heat source may be selected such
that a non-condensable gas fraction of produced formation fluids
may be larger than a condensable gas fraction of the produced
formation fluids.
[0491] A carbon number distribution of a produced formation fluid
may indicate a quality of the produced formation fluid. In general,
condensable hydrocarbons with low carbon numbers are considered to
be more valuable than condensable hydrocarbons having higher carbon
numbers. Low carbon numbers may include, for example, carbon
numbers less than about 25. High carbon numbers may include carbon
numbers greater than about 25. In an embodiment, an in situ
conversion process for coal may include providing heat to at least
a portion of a formation and allowing heat to transfer such that
heat may produce pyrolyzation fluids such that a majority of the
pyrolyzation fluids have carbon numbers of less than approximately
25.
[0492] In an embodiment, an in situ conversion process for coal may
include providing heat to at least a portion of a coal formation at
a rate sufficient to alter and/or control production of olefins.
For example, the process may include heating the portion at a rate
to produce formation fluids having an olefin content of less than
about 10% by weight of condensable hydrocarbons of the formation
fluids. Reducing olefin production may substantially reduce coating
of a pipe surface by such olefins, thereby reducing difficulty
associated with transporting hydrocarbons through such piping.
Reducing olefin production may also tend to inhibit polymerization
of hydrocarbons during pyrolysis, thereby increasing permeability
in the formation and/or enhancing the quality of produced fluids
(e.g., by lowering the carbon number distribution, increasing API
gravity, etc.).
[0493] In some embodiments, however, the portion may be heated at a
rate to selectively increase the olefin content of condensable
hydrocarbons in the produced fluids. For example, olefins may be
separated from such condensable hydrocarbons and may be used to
produce additional products.
[0494] In some embodiments, the portion may be heated at a rate to
selectively increase the content of phenol and substituted phenols
of condensable hydrocarbons in the produced fluids. For example,
phenol and/or substituted phenols may be separated from such
condensable hydrocarbons and may be used to produce additional
products. The resource may, in some embodiments, be selected to
enhance production of phenol and/or substituted phenols.
[0495] Hydrocarbons in the produced fluids may include a mixture of
a number of different components, some of which are condensable and
some of which are not. The fraction of non-condensable hydrocarbons
within the produced fluid may be altered and/or controlled by
altering, controlling, and/or maintaining a temperature within a
pyrolysis temperature range in a heated portion of the coal
formation. Additionally, the fraction of non-condensable
hydrocarbons within the produced fluids may be altered and/or
controlled by altering, controlling, and/or maintaining a pressure
within the heated portion. In some embodiments, surface facilities
may be configured to separate condensable and non-condensable
hydrocarbons of a produced fluid.
[0496] In some embodiments, the non-condensable hydrocarbons may
include, but are not limited to, hydrocarbons having less than
about 5 carbon atoms, H.sub.2, CO.sub.2, ammonia, H.sub.2S, N.sub.2
and/or CO. In certain embodiments, non-condensable hydrocarbons of
a fluid produced from a portion of a coal formation may have a
weight ratio of hydrocarbons having carbon numbers from 2 through 4
("C.sub.2-4"hydrocarbons) to methane of greater than about 0.3,
greater than about 0.75, or greater than about 1 in some
circumstances. For example, non-condensable hydrocarbons of a fluid
produced from a portion of a coal formation may have a weight ratio
of hydrocarbons having carbon numbers from 2 through 4, to methane,
of greater than approximately 0.3.
[0497] Such weight ratios of C.sub.2-4 hydrocarbons to methane are
believed to be beneficial as compared to similar weight ratios
produced from other formations. Such weight ratios indicate higher
amounts of hydrocarbons with 2, 3, and/or 4 carbons (e.g., ethane,
propane, and butane) than is normally present in gases produced
from formations. Such hydrocarbons are often more valuable.
Production of hydrocarbons with such weight ratios is believed to
be due to the conditions applied to the formation during pyrolysis
(e.g., controlled heating and/or pressure used in reducing
environments, or at least non-oxidizing environments). It is
believed that in such conditions longer chain hydrocarbons can be
more easily broken down to form substantially smaller (and in many
cases more saturated) compounds such as C.sub.2-4 hydrocarbons. The
C.sub.2-4 hydrocarbons to methane weight ratio may vary depending
on, for example, a temperature of the heated portion and a heating
rate of the heated portion.
[0498] In certain embodiments, the API gravity of the hydrocarbons
in a fluid produced from a coal formation may be approximately 20
or above (e.g., 25, 30, 35, 40, 50, etc.).
[0499] Methane and at least a portion of ethane may be separated
from non-condensable hydrocarbons in the produced fluid and may be
utilized as natural gas. A portion of propane and butane may be
separated from non-condensable hydrocarbons of the produced fluid.
In addition, the separated propane and butane may be utilized as
fuels or as feedstocks for producing other hydrocarbons. A portion
of the produced fluid having carbon numbers less than 4 may be
reformed, as described herein, in the formation to produce
additional H.sub.2 and/or methane. In addition, ethane, propane,
and butane may be separated from the non-condensable hydrocarbons
and may be used to generate olefins.
[0500] The non-condensable hydrocarbons of fluid produced from a
coal formation may have a H.sub.2 content of greater than about 5%
by weight, greater than 10% by weight, or even greater than 15% by
weight. The H.sub.2 may be used, for example, as a fuel for a fuel
cell, to hydrogenate hydrocarbon fluids in situ, and/or to
hydrogenate hydrocarbon fluids ex situ. In addition, presence of
H.sub.2 within a formation fluid in a heated section of a coal
formation is believed to increase the quality of produced fluids.
In certain embodiments, the hydrogen to carbon atomic ratio of a
produced fluid may be at least approximately 1.7 or above. For
example, the hydrogen to carbon atomic ratio of a produced fluid
may be approximately 1.8, approximately 1.9, or greater.
[0501] The non-condensable hydrocarbons may include some hydrogen
sulfide. The non-condensable hydrocarbons may be treated to
separate the hydrogen sulfide from other compounds in the
non-condensable hydrocarbons. The separated hydrogen sulfide may be
used to produce, for example, sulfuric acid, fertilizer, and/or
elemental sulfur.
[0502] In certain embodiments, fluid produced from a coal formation
by an in situ conversion process may include carbon dioxide. Carbon
dioxide produced from the formation may be used, for example, for
enhanced oil recovery, as at least a portion of a feedstock for
production of urea, and/or may be reinjected into a coal formation
for synthesis gas production and/or coal bed methane
production.
[0503] Fluid produced from a coal formation by an in situ
conversion process may include carbon monoxide. Carbon monoxide
produced from the formation may be used, for example, as a
feedstock for a fuel cell, as a feedstock for a Fischer Tropsch
process, as a feedstock for production of methanol, and/or as a
feedstock for production of methane.
[0504] The condensable hydrocarbons of the produced fluids may be
separated from the fluids. In an embodiment, a condensable
component may include condensable hydrocarbons and compounds found
in an aqueous phase. The aqueous phase may be separated from the
condensable component. The ammonia content of the total produced
fluids may be greater than about 0.1% by weight of the fluid,
greater than about 0.5% by weight of the fluid, and, in some
embodiments, up to about 10% by weight of the produced fluids. The
ammonia may be used to produce, for example, urea.
[0505] Certain embodiments of a fluid may be produced in which a
majority of hydrocarbons in the produced fluid have a carbon number
of less than approximately 25. Alternatively, less than about 15%
by weight of the hydrocarbons in the condensable hydrocarbons have
a carbon number greater than approximately 25. In some embodiments,
less than about 5% by weight of hydrocarbons in the condensable
hydrocarbons have a carbon number greater than approximately 25,
and/or less than about 2% by weight of hydrocarbons in the
condensable hydrocarbons have a carbon number greater than
approximately 25.
[0506] In certain embodiments, a fluid produced from a formation
(e.g., a coal formation) may include oxygenated hydrocarbons. For
example, condensable hydrocarbons of the produced fluid may include
an amount of oxygenated hydrocarbons greater than about 5% by
weight of the condensable hydrocarbons. Alternatively, the
condensable hydrocarbons may include an amount of oxygenated
hydrocarbons greater than about 1.0% by weight of the condensable
hydrocarbons. Furthermore, the condensable hydrocarbons may include
an amount of oxygenated hydrocarbons greater than about 1.5% by
weight of the condensable hydrocarbons or greater than about 2.0%
by weight of the condensable hydrocarbons. In an embodiment, the
oxygenated hydrocarbons may include, but are not limited to, phenol
and/or substituted phenols. In some embodiments, phenol and
substituted phenols may have more economic value than other
products produced from an in situ conversion process. Therefore, an
in situ conversion process may be utilized to produce phenol and/or
substituted phenols. For example, generation of phenol and/or
substituted phenols may increase when a fluid pressure within the
formation is maintained at a lower pressure.
[0507] In some embodiments, condensable hydrocarbons of a fluid
produced from a coal formation may also include olefins. For
example, an olefin content of the condensable hydrocarbons may be
in a range from about 0.1% by weight to about 15% by weight.
Alternatively, an olefin content of the condensable hydrocarbons
may also be within a range from about 0.1% by weight to about 5% by
weight. Furthermore, an olefin content of the condensable
hydrocarbons may also be within a range from about 0.1% by weight
to about 2.5% by weight. An olefin content of the condensable
hydrocarbons may be altered and/or controlled by controlling a
pressure and/or a temperature within the formation. For example,
olefin content of the condensable hydrocarbons may be reduced by
selectively increasing pressure within the formation, by
selectively decreasing temperature within the formation, by
selectively reducing heating rates within the formation, and/or by
selectively increasing hydrogen partial pressures in the formation.
In some embodiments, a reduced olefin content of the condensable
hydrocarbons may be preferred. For example, if a portion of the
produced fluids is used to produce motor fuels, a reduced olefin
content may be desired.
[0508] In alternate embodiments, a higher olefin content may be
preferred. For example, if a portion of the condensable
hydrocarbons may be sold, a higher olefin content may be preferred
due to a high economic value of olefin products. In some
embodiments, olefins may be separated from the produced fluids and
then sold and/or used as a feedstock for the production of other
compounds.
[0509] Non-condensable hydrocarbons of a produced fluid may also
include olefins. For example, an olefin content of the
non-condensable hydrocarbons may be gauged using an ethene/ethane
molar ratio. In certain embodiments, the ethene/ethane molar ratio
may range from about 0.001 to about 0.15.
[0510] Fluid produced from a coal formation may include aromatic
compounds. For example, the condensable hydrocarbons may include an
amount of aromatic compounds greater than about 20% by weight or
about 25% by weight of the condensable hydrocarbons. Alternatively,
the condensable hydrocarbons may include an amount of aromatic
compounds greater than about 30% by weight of the condensable
hydrocarbons. The condensable hydrocarbons may also include
relatively low amounts of compounds with more than two rings in
them (e.g., tri-aromatics or above). For example, the condensable
hydrocarbons may include less than about 1% by weight or less than
about 2% by weight of tri-aromatics or above in the condensable
hydrocarbons. Alternatively, the condensable hydrocarbons may
include less than about 5% by weight of tri-aromatics or above in
the condensable hydrocarbons.
[0511] In particular, in certain embodiments, asphaltenes (i.e.,
large multi-ring aromatics that may be substantially soluble in
hydrocarbons) make up less than about 0.1% by weight of the
condensable hydrocarbons. For example, the condensable hydrocarbons
may include an asphaltene component of from about 0.0% by weight to
about 0.1% by weight or, in some embodiments, less than about 0.3%
by weight.
[0512] Condensable hydrocarbons of a produced fluid may also
include relatively large amounts of cycloalkanes. For example, the
condensable hydrocarbons may include a cycloalkane component of
from about 5% by weight to about 30% by weight of the condensable
hydrocarbons.
[0513] In certain embodiments, the condensable hydrocarbons of a
fluid produced from a formation may include compounds containing
nitrogen. For example, less than about 1% by weight (when
calculated on an elemental basis) of the condensable hydrocarbons
may be nitrogen (e.g., typically the nitrogen may be in nitrogen
containing compounds such as pyridines, amines, amides, carbazoles,
etc.).
[0514] In certain embodiments, the condensable hydrocarbons of a
fluid produced from a formation may include compounds containing
oxygen. For example, in an embodiments, in a fluid produced from a
coal formation between about 5% by weight and about 30% by weight
of the condensable hydrocarbons may typically include oxygen
containing compounds such as phenols, substituted phenols, ketones,
etc. In some instances, certain compounds containing oxygen (e.g.,
phenols) may be valuable and, as such, may be economically
separated from the produced fluid.
[0515] In certain embodiments, condensable hydrocarbons of the
fluid produced from a formation may include compounds containing
sulfur. For example, less than about 1% by weight (when calculated
on an elemental basis) of the condensable hydrocarbons may be
sulfur (e.g., typically the sulfur containing compounds may include
compounds such as thiophenes, mercaptans, etc.).
[0516] Furthermore, the fluid produced from the formation may
include ammonia (typically the ammonia may condense with water, if
any, produced from the formation). For example, the fluid produced
from the formation may in certain embodiments include about 0.05%
or more by weight of ammonia. In some embodiments coal formations
may produce larger amounts of ammonia (e.g., up to about 10% by
weight of the total fluid produced may be ammonia).
[0517] In addition, a produced fluid from the formation may also
include molecular hydrogen (H.sub.2). For example, the fluid may
include a H.sub.2 content between about 10% to about 80% by volume
of the non-condensable hydrocarbons.
[0518] In some embodiments, at least about 15% by weight of a total
organic carbon content of hydrocarbons in the portion may be
transformed into hydrocarbon fluids.
[0519] A total potential amount of products that may be produced
from hydrocarbons may be determined by a Fischer Assay. The Fischer
Assay is a standard method that involves heating a sample of
hydrocarbons to approximately 500.degree. C. in one hour,
collecting products produced from the heated sample, and
quantifying the products. In an embodiment, a method for treating a
coal formation in situ may include heating a section of the
formation to yield greater than about 60% by weight of the
potential amount of products from the hydrocarbons as measured by
the Fischer Assay.
[0520] In certain embodiments, heating of the selected section of
the formation may be controlled to pyrolyze at least about 20% by
weight (or in some embodiments about 25% by weight) of the
hydrocarbons within the selected section of the formation.
Conversion of hydrocarbons within a formation may be limited to
inhibit subsidence of the formation.
[0521] Heating at least a portion of a formation may cause at least
some of the hydrocarbons within the portion to pyrolyze, thereby
forming hydrocarbon fragments. The hydrocarbon fragments may be
reactive and may react with other compounds in the formation and/or
with other hydrocarbon fragments produced by pyrolysis. Reaction of
the hydrocarbon fragments with other compounds and/or with each
other, however, may reduce production of a selected product. A
reducing agent in or provided to the portion of the formation
during heating, however, may increase production of the selected
product. An example of a reducing agent may include, but may not be
limited to, H.sub.2. For example, the reducing agent may react with
the hydrocarbon fragments to form a selected product.
[0522] In an embodiment, molecular hydrogen may be provided to the
formation to create a reducing environment. A hydrogenation
reaction between the molecular hydrogen and at least some of the
hydrocarbons within a portion of the formation may generate heat.
The generated heat may be used to heat the portion of the
formation. Molecular hydrogen may also be generated within the
portion of the formation. In this manner, the generated H.sub.2 may
be used to hydrogenate hydrocarbon fluids within a portion of a
formation.
[0523] For example, H.sub.2 may be produced from a first portion of
the coal formation. The H.sub.2 may be produced as a component of a
fluid produced from a first portion. For example, at least a
portion of fluids produced from a first portion of the formation
may be provided to a second portion of the formation to create a
reducing environment within the second portion. The second portion
of the formation may be heated as described herein. In addition,
produced H.sub.2 may be provided to a second portion of the
formation. For example, a partial pressure of H.sub.2 within the
produced fluid may be greater than a pyrolysis H.sub.2 partial
pressure, as measured at a well from which the produced fluid may
be produced.
[0524] For example, a portion of a coal formation may be heated in
a reducing environment. The presence of a reducing agent during
pyrolysis of at least some of the hydrocarbons in the heated
portion may reduce (e.g., at least partially saturate) at least
some of the pyrolyzed product. Reducing the pyrolyzed product may
decrease a concentration of olefins in hydrocarbon fluids. Reducing
the pyrolysis products may improve the product quality of the
hydrocarbon fluids.
[0525] An embodiment of a method for treating a coal formation in
situ may include generating H.sub.2 and hydrocarbon fluids within
the formation. In addition, the method may include hydrogenating
the generated hydrocarbon fluids using the H.sub.2 within the
formation. In some embodiments, the method may also include
providing the generated H.sub.2 to a portion of the formation.
[0526] In an embodiment, a method of treating a portion of a coal
formation may include heating the portion such that a thermal
conductivity of a selected section of the heated portion increases.
For example, porosity and permeability within a selected section of
the portion may increase substantially during heating such that
heat may be transferred through the formation not only by
conduction but also by convection and/or by radiation from a heat
source. In this manner, such radiant and convective transfer of
heat may increase an apparent thermal conductivity of the selected
section and, consequently, the thermal diffusivity. The large
apparent thermal diffusivity may make heating at least a portion of
a coal formation from heat sources feasible. For example, a
combination of conductive, radiant, and/or convective heating may
accelerate heating. Such accelerated heating may significantly
decrease a time required for producing hydrocarbons and may
significantly increase the economic feasibility of
commercialization of an in situ conversion process. In a further
embodiment, the in situ conversion process for a coal formation may
also include providing heat to the heated portion to increase a
thermal conductivity of a selected section to greater than about
0.5 W/(m.degree. C.) or about 0.6 W/(m.degree. C.).
[0527] In some embodiments, an in situ conversion process for a
coal formation may increase the rank level of coal within a heated
portion of the coal. The increase in rank level, as assessed by the
vitrinite reflectance, of the coal may coincide with a substantial
change of the structure (e.g., molecular changes in the carbon
structure) of the coal. The changed structure of the coal may have
a higher thermal conductivity.
[0528] Thermal diffusivity within a coal formation may vary
depending on, for example, a density of the coal formation, a heat
capacity of the formation, and a thermal conductivity of the
formation. As pyrolysis occurs within a selected section, the coal
formation mass may be removed from the selected section. The
removal of mass may include, but is not limited to, removal of
water and a transformation of hydrocarbons to formation fluids. For
example, a lower thermal conductivity may be expected as water is
removed from a coal formation. This effect may vary significantly
at different depths. At greater depths a lithostatic pressure may
be higher, and may close certain openings (e.g., cleats and/or
fractures) in the coal. The closure of the coal openings may
increase a thermal conductivity of the coal. In some embodiments, a
higher thermal conductivity may be observed due to a higher
lithostatic pressure.
[0529] In some embodiments, an in situ conversion process may
generate molecular hydrogen during the pyrolysis process. In
addition, pyrolysis tends to increase the porosity/void spaces in
the formation. Void spaces in the formation may contain hydrogen
gas generated by the pyrolysis process. Hydrogen gas may have about
six times the thermal conductivity of nitrogen or air. This may
raise the thermal conductivity of the formation.
[0530] Certain embodiments described herein will in many instances
be able to economically treat formations that were previously
believed to be uneconomical. Such treatment will be possible
because of the surprising increases in thermal conductivity and
thermal diffusivity that can be achieved with such embodiments.
These surprising results are illustrated by the fact that prior
literature indicated that certain coal formations exhibited
relatively low values for thermal conductivity and thermal
diffusivity when heated. For example, in government report No. 8364
by J. M. Singer and R. P. Tye entitled "Thermal, Mechanical, and
Physical Properties of Selected Bituminous Coals and Cokes," U.S.
Department of the Interior, Bureau of Mines (1979), the authors
report the thermal conductivity and thermal diffusivity for four
bituminous coals. This government report includes graphs of thermal
conductivity and diffusivity that show relatively low values up to
about 400.degree. C. (e.g., thermal conductivity is about 0.2
W/(m.degree. C.) or below, and thermal diffusivity is below about
1.7.times.10.sup.-3 cm.sup.2/s). This government report states that
"coals and cokes are excellent thermal insulators."
[0531] In contrast, in certain embodiments described herein coal
may be treated such that the thermal conductivity and thermal
diffusivity are significantly higher (e.g., thermal conductivity at
or above about 0.5 W/(m.degree. C.) and thermal diffusivity at or
above 4.1.times.10.sup.-3 cm.sup.2/s) than would be expected based
on previous literature such as government report No. 8364. If
treated as described in certain embodiments herein, coal does not
act as "an excellent thermal insulator." Instead, heat can and does
transfer and/or diffuse into the formation at significantly higher
(and better) rates than would be expected according to the
literature, thereby significantly enhancing economic viability of
treating the formation.
[0532] In an embodiment, heating a portion of a coal formation in
situ to a temperature less than an upper pyrolysis temperature may
increase permeability of the heated portion. For example,
permeability may increase due to formation of fractures within the
heated portion caused by application of heat. As a temperature of
the heated portion increases, water may be removed due to
vaporization. The vaporized water may escape and/or be removed from
the formation. Removal of water may also increase the permeability
of the heated portion. In addition, permeability of the heated
portion may also increase as a result of production of hydrocarbons
from pyrolysis of at least some of the hydrocarbons within the
heated portion on a macroscopic scale. In an embodiment, a
permeability of a selected section within a heated portion of a
coal formation may be substantially uniform. For example, heating
by conduction may be substantially uniform, and thus a permeability
created by conductive heating may also be substantially uniform. In
the context of this patent "substantially uniform permeability"
means that the assessed (e.g., calculated or estimated)
permeability of any selected portion in the formation does not vary
by more than a factor of 10 from the assessed average permeability
of such selected portion.
[0533] Permeability of a selected section within the heated portion
of the coal formation may also rapidly increase while the selected
section is heated by conduction. For example, permeability of an
impermeable coal formation may be less than about 1 millidarcy
before treatment. In some embodiments, pyrolyzing at least a
portion of a coal formation may increase a permeability within a
selected section of the portion to greater than about 10
millidarcy, 100 millidarcy, 1 Darcy, 10 Darcy, 20 Darcy, or 50
Darcy. Therefore, a permeability of a selected section of the
portion may increase by a factor of more than about 10, 100, 1,000,
or 10,000.
[0534] In some embodiments, superposition (e.g., overlapping) of
heat from one or more heat sources may result in substantially
uniform heating of a portion of a coal formation. Since formations
during heating will typically have temperature profiles throughout
them, in the context of this patent "substantially uniform" heating
means heating such that the temperatures in a majority of the
section do not vary by more than 100.degree. C. from the assessed
average temperature in the majority of the selected section
(volume) being treated.
[0535] Substantially uniform heating of the coal formation may
result in a substantially uniform increase in permeability. For
example, uniformly heating may generate a series of substantially
uniform fractures within the heated portion due to thermal stresses
generated in the formation. Heating substantially uniformly may
generate pyrolysis fluids from the portion in a substantially
homogeneous manner. Water removed due to vaporization and
production may result in increased permeability of the heated
portion. In addition to creating fractures due to thermal stresses,
fractures may also be generated due to fluid pressure increase. As
fluids are generated within the heated portion a fluid pressure
within the heated portion may also increase. As the fluid pressure
approaches a lithostatic pressure of the heated portion, fractures
may be generated. Substantially uniform heating and homogeneous
generation of fluids may generate substantially uniform fractures
within the heated portion. In some embodiments, a permeability of a
heated section of a coal formation may not vary by more than a
factor of about 10.
[0536] Removal of hydrocarbons due to treating at least a portion
of a coal formation, as described in any of the above embodiments,
may also occur on a microscopic scale. Hydrocarbons may be removed
from micropores within the portion due to heating. Micropores may
be generally defined as pores having a cross-sectional dimension of
less than about 1000 .ANG.. In this manner, removal of solid
hydrocarbons may result in a substantially uniform increase in
porosity within at least a selected section of the heated portion.
Heating the portion of a coal formation, as described in any of the
above embodiments, may substantially uniformly increase a porosity
of a selected section within the heated portion. In the context of
this patent "substantially uniform porosity" means that the
assessed (e.g., calculated or estimated) porosity of any selected
portion in the formation does not vary by more than about 25% from
the assessed average porosity of such selected portion.
[0537] Physical characteristics of a portion of a coal formation
after pyrolysis may be similar to those of a porous bed. For
example, a portion of a coal formation after pyrolysis may include
particles having sizes of about several millimeters. Such physical
characteristics may differ from physical characteristics of a coal
formation that may be subjected to injection of gases that burn
hydrocarbons in order to heat the hydrocarbons. Such gases injected
into virgin or fractured formations may tend to channel and may not
be uniformly distributed throughout the formation. In contrast, a
gas injected into a pyrolyzed portion of a coal formation may
readily and substantially uniformly contact the carbon and/or
hydrocarbons remaining in the formation. In addition, gases
produced by heating the hydrocarbons may be transferred a
significant distance within the heated portion of the formation
with a minimal pressure loss. Such transfer of gases may be
particularly advantageous, for example, in treating a steeply
dipping coal formation.
[0538] Synthesis gas may be produced from a portion of a coal
formation. The coal formation may be heated prior to synthesis gas
generation to produce a substantially uniform, relatively high
permeability formation. In an embodiment, synthesis gas production
may be commenced after production of pyrolysis fluids has been
substantially exhausted or becomes uneconomical. Alternately,
synthesis gas generation may be commenced before substantial
exhaustion or uneconomical pyrolysis fluid production has been
achieved if production of synthesis gas will be more economically
favorable. Formation temperatures will usually be higher than
pyrolysis temperatures during synthesis gas generation. Raising the
formation temperature from pyrolysis temperatures to synthesis gas
generation temperatures allows further utilization of heat applied
to the formation to pyrolyze the formation. While raising a
temperature of a formation from pyrolysis temperatures to synthesis
gas temperatures, methane and/or H.sub.2 may be produced from the
formation.
[0539] Producing synthesis gas from a formation from which
pyrolyzation fluids have been previously removed allows a synthesis
gas to be produced that includes mostly H.sub.2, CO, water and/or
CO.sub.2. Produced synthesis gas, in certain embodiments, may have
substantially no hydrocarbon component unless a separate source
hydrocarbon stream is introduced into the formation with or in
addition to the synthesis gas producing fluid. Producing synthesis
gas from a substantially uniform, relatively high permeability
formation that was formed by slowly heating a formation through
pyrolysis temperatures may allow for easy introduction of a
synthesis gas generating fluid into the formation, and may allow
the synthesis gas generating fluid to contact a relatively large
portion of the formation. The synthesis gas generating fluid can do
so because the permeability of the formation has been increased
during pyrolysis and/or because the surface area per volume in the
formation has increased during pyrolysis. The relatively large
surface area (e.g., "contact area") in the post-pyrolysis formation
tends to allow synthesis gas generating reactions to be
substantially at equilibrium conditions for C, H.sub.2, CO, water
and CO.sub.2. Reactions in which methane is formed may, however,
not be at equilibrium because they are kinetically limited. The
relatively high, substantially uniform formation permeability may
allow production wells to be spaced farther apart than production
wells used during pyrolysis of the formation.
[0540] A temperature of at least a portion of a formation that is
used to generate synthesis gas may be raised to a synthesis gas
generating temperature (e.g., between about 400.degree. C. and
about 1200.degree. C.). In some embodiments composition of produced
synthesis gas may be affected by formation temperature, by the
temperature of the formation adjacent to synthesis gas production
wells, and/or by residence time of the synthesis gas components. A
relatively low synthesis gas generation temperature may produce a
synthesis gas having a high H.sub.2 to CO ratio, but the produced
synthesis gas may also include a large portion of other gases such
as water, CO.sub.2, and methane. A relatively high formation
temperature may produce a synthesis gas having a H.sub.2 to CO
ratio that approaches 1, and the stream may include mostly (and in
some cases substantially only) H.sub.2 and CO. If the synthesis gas
generating fluid is substantially pure steam, then the H.sub.2 to
CO ratio may approach 1 at relatively high temperatures. At a
formation temperature of about 700.degree. C., the formation may
produce a synthesis gas with a H.sub.2 to CO ratio of about 2 at a
certain pressure. The composition of the synthesis gas tends to
depend on the nature of the synthesis gas generating fluid.
[0541] Synthesis gas generation is generally an endothermic
process. Heat may be added to a portion of a formation during
synthesis gas production to keep formation temperature at a desired
synthesis gas generating temperature or above a minimum synthesis
gas generating temperature. Heat may be added to the formation from
heat sources, from oxidation reactions within the portion, and/or
from introducing synthesis gas generating fluid into the formation
at a higher temperature than the temperature of the formation.
[0542] An oxidant may be introduced into a portion of the formation
with synthesis gas generating fluid. The oxidant may exothermically
react with carbon within the portion of the formation to heat the
formation. Oxidation of carbon within a formation may allow a
portion of a formation to be economically heated to relatively high
synthesis gas generating temperatures. The oxidant may also be
introduced into the formation without synthesis gas generating
fluid to heat the portion. Using an oxidant, or an oxidant and heat
sources, to heat the portion of the formation may be significantly
more favorable than heating the portion of the formation with only
the heat sources. The oxidant may be, but is not limited to, air,
oxygen, or oxygen enriched air. The oxidant may react with carbon
in the formation to produce CO.sub.2 and/or CO. The use of air, or
oxygen enriched air (i.e., air with an oxygen content greater than
21% by volume), to generate heat within the formation may cause a
significant portion of N.sub.2 to be present in produced synthesis
gas. Temperatures in the formation may be maintained below
temperatures needed to generate oxides of nitrogen (NO.sub.x) so
that little or no NO.sub.x compounds may be present in produced
synthesis gas.
[0543] A mixture of steam and oxygen, or steam and air, may be
substantially continuously injected into a formation. If injection
of steam and oxygen is used for synthesis gas production, the
oxygen may be produced on site by electrolysis of water utilizing
direct current output of a fuel cell. H.sub.2 produced by the
electrolysis of water may be used as a fuel stream for the fuel
cell. O.sub.2 produced by the electrolysis of water may be injected
into the hot formation to raise a temperature of the formation.
[0544] Heat sources and/or production wells within a formation for
pyrolyzing and producing pyrolysis fluids from the formation may be
utilized for different purposes during synthesis gas production. A
well that was used as a heat source or a production well during
pyrolysis may be used as an injection well to introduce synthesis
gas producing fluid into the formation. A well that was used as a
heat source or a production well during pyrolysis may be used as a
production well during synthesis gas generation. A well that was
used as a heat source or a production well during pyrolysis may be
used as a heat source to heat the formation during synthesis gas
generation. Synthesis gas production wells may be spaced further
apart than pyrolysis production wells because of the relatively
high, substantially uniform permeability of the formation.
Synthesis gas production wells may be heated to relatively high
temperatures so that a portion of the formation adjacent to the
production well is at a temperature that will produce a desired
synthesis gas composition. Comparatively, pyrolysis fluid
production wells may not be heated at all, or may only be heated to
a temperature that will inhibit condensation of pyrolysis fluid
within the production well.
[0545] Synthesis gas may be produced from a dipping formation from
wells used during pyrolysis of the formation. As shown in FIG. 4,
synthesis gas production wells 206 may be located above and down
dip from an injection well 208. Hot synthesis gas producing fluid
may be introduced into injection well 208. Hot synthesis gas fluid
that moves down dip may generate synthesis gas that is produced
through synthesis gas production wells 206. Synthesis gas
generating fluid that moves up dip may generate synthesis gas in a
portion of the formation that is at synthesis gas generating
temperatures. A portion of the synthesis gas generating fluid and
generated synthesis gas that moves up dip above the portion of the
formation at synthesis gas generating temperatures may heat
adjacent formation. The synthesis gas generating fluid that moves
up dip may condense, heat adjacent portions of formation, and flow
downwards towards or into a portion of the formation at synthesis
gas generating temperature. The synthesis gas generating fluid may
then generate additional synthesis gas.
[0546] Synthesis gas generating fluid may be any fluid capable of
generating H.sub.2 and CO within a heated portion of a formation.
Synthesis gas generating fluid may include water, O.sub.2, air,
CO.sub.2, hydrocarbon fluids, or combinations thereof. Water may be
introduced into a formation as a liquid or as steam. Water may
react with carbon in a formation to produce H.sub.2, CO, and
CO.sub.2. CO.sub.2 may react with hot carbon to form CO. Air and
O.sub.2 may be oxidants that react with carbon in a formation to
generate heat and form CO.sub.2, CO, and other compounds.
Hydrocarbon fluids may react within a formation to form H.sub.2,
CO, CO.sub.2, H.sub.2O, coke, methane and/or other light
hydrocarbons. Introducing low carbon number hydrocarbons (i.e.,
compounds with carbon numbers less than 5) may produce additional
H.sub.2 within the formation. Adding higher carbon number
hydrocarbons to the formation may increase an energy content of
generated synthesis gas by having a significant methane and other
low carbon number compounds fraction within the synthesis gas.
[0547] Water provided as a synthesis gas generating fluid may be
derived from numerous different sources. Water may be produced
during a pyrolysis stage of treating a formation. The water may
include some entrained hydrocarbon fluids. Such fluid may be used
as synthesis gas generating fluid. Water that includes hydrocarbons
may advantageously generate additional H.sub.2 when used as a
synthesis gas generating fluid. Water produced from water pumps
that inhibit water flow into a portion of formation being subjected
to an in situ conversion process may provide water for synthesis
gas generation. A low rank kerogen resource or hydrocarbons having
a relatively high water content (i.e. greater than about 20%
H.sub.2O by weight) may generate a large amount of water and/or
CO.sub.2 if subjected to an in situ conversion process. The water
and CO.sub.2 produced by subjecting a low rank kerogen resource to
an in situ conversion process may be used as a synthesis gas
generating fluid.
[0548] Reactions involved in the formation of synthesis gas may
include, but are not limited to:
C+H.sub.2OH.sub.2+CO (1)
C+2H.sub.2O2H.sub.2+CO.sub.2 (2)
C+CO.sub.22CO (3)
[0549] Thermodynamics allows the following reactions to
proceed:
2C+2H.sub.2OCH.sub.4+CO.sub.2 (4)
C+2H.sub.2CH.sub.4 (5)
[0550] However, kinetics of the reactions are slow in certain
embodiments so that relatively low amounts of methane are formed at
formation conditions from Reactions (4) and (5).
[0551] In the presence of oxygen, the following reaction may take
place to generate carbon dioxide and heat:
C+O.sub.2.fwdarw.CO.sub.2 (6)
[0552] Equilibrium gas phase compositions of coal in contact with
steam may provide an indication of the compositions of components
produced in a formation during synthesis gas generation.
Equilibrium composition data for H.sub.2 carbon monoxide, and
carbon dioxide may be used to determine appropriate operating
conditions such as temperature that may be used to produce a
synthesis gas having a selected composition. Equilibrium conditions
may be approached within a formation due to a high, substantially
uniform permeability of the formation. Composition data obtained
from synthesis gas production may in many instances deviate by less
than 10% from equilibrium values.
[0553] In one embodiment, a composition of the produced synthesis
gas can be changed by injecting additional components into the
formation along with steam. Carbon dioxide may be provided in the
synthesis gas generating fluid to substantially inhibit production
of carbon dioxide produced from the formation during synthesis gas
generation. The carbon dioxide may shift the equilibrium of
reaction (2) to the left, thus reducing the amount of carbon
dioxide generated from formation carbon. The carbon dioxide may
also react with carbon in the formation to generate carbon
monoxide. Carbon dioxide may be separated from the synthesis gas
and may be re-injected into the formation with the synthesis gas
generating fluid. Addition of carbon dioxide in the synthesis gas
generating fluid may, however, reduce the production of
hydrogen.
[0554] FIG. 29 depicts a schematic diagram of use of water
recovered from pyrolysis fluid production being used to generate
synthesis gas. Heat source 801 with electric heater 803 produces
pyrolysis fluid 807 from first section 805 of the formation.
Produced pyrolysis fluid 807 may be sent to separator 809.
Separator 809 may include a number of individual separation units
and processing units that produce aqueous stream 811, vapor stream
813, and hydrocarbon condensate stream 815. Aqueous stream 811 from
the separator 809 may be combined with synthesis gas generating
fluid 818 to form synthesis gas generating fluid 821. Synthesis gas
generating fluid 821 may be provided to injection well 817 and
introduced to second portion 819 of the formation. Synthesis gas
823 may be produced from synthesis gas production well 825.
[0555] FIG. 30 depicts a schematic diagram of an embodiment of a
system for synthesis gas production in which carbon dioxide from
produced synthesis gas is injected into a formation. Synthesis gas
830 may be produced from formation 832 through production well 834.
Gas separation unit 836 may separate a portion of carbon dioxide
from the synthesis gas 830 to produce CO.sub.2 stream 838 and
remaining synthesis gas stream 840. The CO.sub.2 stream 838 may be
mixed with synthesis gas producing fluid stream 842 that is
introduced into the formation 832 through injection well 837,
and/or the CO.sub.2 may be separately introduced into the
formation. This may limit conversion of carbon within the formation
to CO.sub.2 and/or may increase an amount of CO generated within
the formation.
[0556] Synthesis gas generating fluid may be introduced into a
formation in a variety of different ways. Steam may be injected
into a heated coal formation at a lowermost portion of the heated
formation. Alternatively, in a steeply dipping formation, steam may
be injected up dip with synthesis gas production down dip. The
injected steam may pass through the remaining coal formation to a
production well. In addition, endothermic heat of reaction may be
provided to the formation with heat sources disposed along a path
of the injected steam. In alternate embodiments, steam may be
injected at a plurality of locations along the coal formation to
increase penetration of the steam throughout the formation. A line
drive pattern of locations may also be utilized. The line drive
pattern may include alternating rows of steam injection wells and
synthesis gas production wells.
[0557] At relatively low pressures, and temperatures below about
400.degree. C., synthesis gas reactions are relatively slow. At
relatively low pressures, and temperatures between about
400.degree. C. and about 700.degree. C., Reaction (2) tends to be
the predominate reaction and the synthesis gas composition is
primarily hydrogen and carbon dioxide. At relatively low pressures,
and temperatures greater than about 700.degree. C., Reaction (1)
tends to be the predominate reaction and the synthesis gas
composition is primarily hydrogen and carbon monoxide.
[0558] Advantages of a lower temperature synthesis gas reaction may
include lower heat requirements, cheaper metallurgy and less
endothermic reactions (especially when methane formation takes
place). An advantage of a higher temperature synthesis gas reaction
is that hydrogen and carbon monoxide may be used as feedstock for
other processes (e.g., Fischer-Tropsch processes).
[0559] A pressure of the coal formation may be maintained at
relatively high pressures during synthesis gas production. The
pressure may range from atmospheric pressure to a lithostatic
pressure of the formation. Higher formation pressures may allow
generation of electricity by passing produced synthesis gas through
a turbine. Higher formation pressures may allow for smaller
collection conduits to transport produced synthesis gas, and
reduced downstream compression requirements on the surface.
[0560] In some embodiments, synthesis gas may be produced from a
portion of a formation in a substantially continuous manner. The
portion may be heated to a desired synthesis gas generating
temperature. A synthesis gas generating fluid may be introduced
into the portion. Heat may be added to, or generated within, the
portion of the formation during introduction of the synthesis gas
generating fluid to the portion. The added heat compensates for the
loss of heat due to the endothermic synthesis gas reactions as well
as heat losses to the top and bottom layers, etc. In other
embodiments, synthesis gas may be produced in a substantially batch
manner. The portion of the formation may be heated, or heat may be
generated within the portion, to raise a temperature of the portion
to a high synthesis gas generating temperature. Synthesis gas
generating fluid may then be added to the portion until generation
of synthesis gas reduces the temperature of the formation below a
temperature that produces a desired synthesis gas composition.
Introduction of the synthesis gas generating fluid may then be
stopped. The cycle may be repeated by reheating the portion of the
formation to the high synthesis gas generating temperature and
adding synthesis gas generating fluid after obtaining the high
synthesis gas generating temperature. Composition of generated
synthesis gas may be monitored to determine when addition of
synthesis gas generating fluid to the formation should be
stopped.
[0561] FIG. 31 illustrates a schematic of an embodiment of a
continuous synthesis gas production system. FIG. 31 includes a
formation with heat injection wellbore 850 and heat injection
wellbore 852. The wellbores may be members of a larger pattern of
wellbores placed throughout a portion of the formation. A portion
of a formation may be heated to synthesis gas generating
temperatures by heating the formation with heat sources, by
injecting an oxidizing fluid, or by a combination thereof.
Oxidizing fluid 854, such as air or oxygen, and synthesis gas
generating fluid 856, such as steam, may be injected into wellbore
850. In one embodiment, the ratio of oxygen to steam may be
approximately 1:2 to approximately 1:10, or approximately 1:3 to
approximately 1:7 (e.g., about 1:4).
[0562] In situ combustion of hydrocarbons may heat region 858 of
the formation between wellbores 850 and 852. Injection of the
oxidizing fluid may heat region 858 to a particular temperature
range, for example, between about 600.degree. C. and about
700.degree. C. The temperature may vary, however, depending on a
desired composition of the synthesis gas. An advantage of the
continuous production method may be that the temperature across
region 858 may be substantially uniform and substantially constant
with time once the formation has reached substantial thermal
equilibrium. Continuous production may also eliminate a need for
use of valves to reverse injection directions on a substantially
frequent basis. Further, continuous production may reduce
temperatures near the injections wells due to endothermic cooling
from the synthesis gas reaction that may occur in the same region
as oxidative heating. The substantially constant temperature may
allow for control of synthesis gas composition. Produced synthesis
gas 860 may exit continuously from wellbore 852.
[0563] In an embodiment, it may be desirable to use oxygen rather
than air as oxidizing fluid 854 in continuous production. If air is
used, nitrogen may need to be separated from the synthesis gas. The
use of oxygen as oxidizing fluid 854 may increase a cost of
production due to the cost of obtaining substantially pure oxygen.
The cryogenic nitrogen by-product obtained from an air separation
plant used to produce the required oxygen may, however, be used in
a heat exchanger to condense hydrocarbons from a hot vapor stream
produced during pyrolysis of hydrocarbons. The pure nitrogen may
also be used for ammonia production.
[0564] FIG. 32 illustrates a schematic of an embodiment of a batch
production of synthesis gas in a coal formation. Wellbore 870 and
wellbore 872 may be located within a portion of the formation. The
wellbores may be members of a larger pattern of wellbores
throughout the portion of the formation. Oxidizing fluid 874, such
as air or oxygen, may be injected into wellbore 870. Oxidation of
hydrocarbons may heat region 876 of a formation between wellbores
870 and 872. Injection of air or oxygen may continue until an
average temperature of region 876 is at a desired temperature
(e.g., between about 900.degree. C. and about 1000.degree. C.).
Higher or lower temperatures may also be developed. A temperature
gradient may be formed in region 876 between wellbore 870 and
wellbore 872. The highest temperature of the gradient may be
located proximate to the injection wellbore 870.
[0565] When a desired temperature has been reached, or when
oxidizing fluid has been injected for a desired period of time,
oxidizing fluid injection may be lessened and/or ceased. A
synthesis gas generating fluid 877, such as steam or water, may be
injected into the injection wellbore 872 to produce synthesis gas.
A back pressure of the injected steam or water in the injection
wellbore may force the synthesis gas produced and un-reacted steam
across region 876. A decrease in average temperature of region 876
caused by the endothermic synthesis gas reaction may be partially
offset by the temperature gradient in region 876 in a direction
indicated by arrow 878. Product stream 880 may be produced through
heat source wellbore 870. If the composition of the product
deviates substantially from a desired composition, then steam
injection may cease, and air or oxygen injection may be
reinitiated.
[0566] In one embodiment, synthesis gas of a selected composition
may be produced by blending synthesis gas produced from different
portions of the formation. A first portion of a formation may be
heated by one or more heat sources to a first temperature
sufficient to allow generation of synthesis gas having a H.sub.2 to
carbon monoxide ratio of less than the selected H.sub.2 to carbon
monoxide ratio (e.g., about 1 or 2). A first synthesis gas
generating fluid may be provided to the first portion to generate a
first synthesis gas. The first synthesis gas may be produced from
the formation. A second portion of the formation may be heated by
one or more heat sources to a second temperature sufficient to
allow generation of synthesis gas having a H.sub.2 to carbon
monoxide ratio of greater than the selected H.sub.2 to carbon
monoxide ratio (e.g., a ratio of 3 or more). A second synthesis gas
generating fluid may be provided to the second portion to generate
a second synthesis gas. The second synthesis gas may be produced
from the formation. The first synthesis gas may be blended with the
second synthesis gas to produce a blend synthesis gas having a
desired H.sub.2 to carbon monoxide ratio.
[0567] The first temperature may be substantially different than
the second temperature. Alternatively, the first and second
temperatures may be approximately the same temperature. For
example, a temperature sufficient to allow generation of synthesis
gas having different compositions may vary depending on
compositions of the first and second portions and/or prior
pyrolysis of hydrocarbons within the first and second portions. The
first synthesis gas generating fluid may have substantially the
same composition as the second synthesis gas generating fluid.
Alternatively, the first synthesis gas generating fluid may have a
different composition than the second synthesis gas generating
fluid. Appropriate first and second synthesis generating fluids may
vary depending upon, for example, temperatures of the first and
second portions, compositions of the first and second portions, and
prior pyrolysis of hydrocarbons within the first and second
portions.
[0568] In addition, synthesis gas having a selected ratio of
H.sub.2 to carbon monoxide may be obtained by controlling the
temperature of the formation. In one embodiment, the temperature of
an entire portion or section of the formation may be controlled to
yield synthesis gas with a selected ratio. Alternatively, the
temperature in or proximate to a synthesis gas production well may
be controlled to yield synthesis gas with the selected ratio.
[0569] In one embodiment, synthesis gas having a selected ratio of
H.sub.2 to carbon monoxide may be obtained by treating produced
synthesis gas at the surface. First, the temperature of the
formation may be controlled to yield synthesis gas with a ratio
different than a selected ratio. For example, the formation may be
maintained at a relatively high temperature to generate a synthesis
gas with a relatively low H.sub.2 to carbon monoxide ratio (e.g.,
the ratio may approach 1 under certain conditions). Some or all of
the produced synthesis gas may then be provided to a shift reactor
(shift process) at the surface. Carbon monoxide reacts with water
in the shift process to produce H.sub.2 and carbon dioxide.
Therefore, the shift process increases the H.sub.2 to carbon
monoxide ratio. The carbon dioxide may then be separated to obtain
a synthesis gas having a selected H.sub.2 to carbon monoxide
ratio.
[0570] In one embodiment, produced synthesis gas 918 may be used
for production of energy. In FIG. 33, treated gases 920 may be
routed from treatment section 900 to energy generation unit 902 for
extraction of useful energy. Energy may be extracted from the
combustible gases generally by oxidizing the gases to produce heat
and converting a portion of the heat into mechanical and/or
electrical energy. Alternatively, energy generation unit 902 may
include a fuel cell that produces electrical energy. In addition,
energy generation unit 902 may include, for example, a molten
carbonate fuel cell or another type of fuel cell, a turbine, a
boiler firebox, or a down hole gas heater. Produced electrical
energy 904 may be supplied to power grid 906. A portion of the
produced electricity 908 may be used to supply energy to electrical
heating elements 910 that heat formation 912.
[0571] In one embodiment, energy generation unit 902 may be a
boiler firebox. A firebox may include a small refractory-lined
chamber, built wholly or partly in the wall of a kiln, for
combustion of fuel. Air or oxygen 914 may be supplied to energy
generation unit 902 to oxidize the produced synthesis gas. Water
916 produced by oxidation of the synthesis gas may be recycled to
the formation to produce additional synthesis gas.
[0572] The produced synthesis gas may also be used as a fuel in
down hole gas heaters. Down hole gas heaters, such as a flameless
combustor as disclosed herein, may be configured to heat a coal
formation. In this manner, a thermal conduction process may be
substantially self-reliant and/or may substantially reduce or
eliminate a need for electricity. Because flameless combustors may
have a thermal efficiency approaching 90%, an amount of carbon
dioxide released to the environment may be less than an amount of
carbon dioxide released to the environment from a process using
fossil-fuel generated electricity to heat the coal formation.
[0573] Carbon dioxide may be produced by both pyrolysis and
synthesis gas generation. Carbon dioxide may also be produced by
energy generation processes and/or combustion processes. Net
release of carbon dioxide to the atmosphere from an in situ
conversion process for coal may be reduced by utilizing the
produced carbon dioxide and/or by storing carbon dioxide within the
formation. For example, a portion of carbon dioxide produced from
the formation may be utilized as a flooding agent or as a feedstock
for producing chemicals.
[0574] In one embodiment, the energy generation process may produce
a reduced amount of emissions by sequestering carbon dioxide
produced during extraction of useful energy. For example, emissions
from an energy generation process may be reduced by storing an
amount of carbon dioxide within a coal formation. The amount of
stored carbon dioxide may be approximately equivalent to that in an
exit stream from the formation.
[0575] FIG. 33 illustrates a reduced emission energy process.
Carbon dioxide 928 produced by energy generation unit 902 may be
separated from fluids exiting the energy generation unit. Carbon
dioxide may be separated from H.sub.2 at high temperatures by using
a hot palladium film supported on porous stainless steel or a
ceramic substrate, or high temperature pressure swing adsorption.
The carbon dioxide may be sequestered in spent coal formation 922,
injected into oil producing fields 924 for enhanced oil recovery by
improving mobility and production of oil in such fields,
sequestered into a deep coal formation 926 containing methane by
adsorption and subsequent desorption of methane, or re-injected 928
into a section of the formation through a synthesis gas production
well to produce carbon monoxide. Carbon dioxide leaving the energy
generation unit may be sequestered in a dewatered coal bed methane
reservoir. The water for synthesis gas generation may come from
dewatering a coal bed methane reservoir. Additional methane can
also be produced by alternating carbon dioxide and nitrogen. An
example of a method for sequestering carbon dioxide is illustrated
in U.S. Pat. No. 5,566,756 to Chaback et al., which is incorporated
by reference as if fully set forth herein. Additional energy may be
utilized by removing heat from the carbon dioxide stream leaving
the energy generation unit.
[0576] In one embodiment, it may be desirable to cool a hot spent
formation before sequestration of carbon dioxide. For example, a
higher quantity of carbon dioxide may be adsorbed in a coal
formation at lower temperatures. In addition, cooling a formation
may strengthen a formation. The spent formation may be cooled by
introducing water into the formation. The steam produced may be
removed from the formation. The generated steam may be used for any
desired process. For example, the steam may be provided to an
adjacent portion of a formation to heat the adjacent portion or to
generate synthesis gas.
[0577] In one embodiment, a spent coal formation may be mined. The
mined material may in some embodiments be used for metallurgical
purposes such as a fuel for generating high temperatures during
production of steel. Pyrolysis of a coal formation may
substantially increase a rank of the coal. After pyrolysis, the
coal may be substantially transformed to a coal having
characteristics of anthracite. A spent coal formation may have a
thickness of 30 m or more. Anthracite coal seams, which are
typically mined for metallurgical uses, may be only about one meter
in thickness.
[0578] FIG. 34 illustrates an embodiment in which fluid produced
from pyrolysis may be separated into a fuel cell feed stream and
fed into a fuel cell to produce electricity. The embodiment may
include carbon containing formation 940 with producing well 942
configured to produce synthesis gas and heater well 944 with
electric heater 946 configured to produced pyrolysis fluid 948. In
one embodiment, pyrolysis fluid may include H.sub.2 and
hydrocarbons with carbon numbers less than 5. Pyrolysis fluid 948
produced from heater well 944 may be fed to gas membrane separation
system 950 to separate H.sub.2 and hydrocarbons with carbon numbers
less than 5. Fuel cell feed stream 952, which may be substantially
composed of H.sub.2, may be fed into fuel cell 954. Air feed stream
956 may be fed into fuel cell 954. Nitrogen stream 958 may be
vented from fuel cell 954. Electricity 960 produced from the fuel
cell may be routed to a power grid. Electricity 962 may also be
used to power electric heaters 946 in heater wells 944. Carbon
dioxide 965 may be injected into formation 940.
[0579] Hydrocarbons having carbon numbers of 4, 3, and 1 typically
have fairly high market values. Separation and selling of these
hydrocarbons may be desirable. Typically ethane may not be
sufficiently valuable to separate and sell in some markets. Ethane
may be sent as part of a fuel stream to a fuel cell or ethane may
be used as a hydrocarbon fluid component of a synthesis gas
generating fluid. Ethane may also be used as a feedstock to produce
ethene. In some markets, there may be no market for any
hydrocarbons having carbon numbers less than 5. In such a
situation, all of the hydrocarbon gases produced during pyrolysis
may be sent to fuel cells or be used as hydrocarbon fluid
components of a synthesis gas generating fluid.
[0580] Pyrolysis fluid 964, which may be substantially composed of
hydrocarbons with carbon numbers less than 5, may be injected into
formation 940. When the hydrocarbons contact the formation,
hydrocarbons may crack within the formation to produce methane,
H.sub.2, coke, and olefins such as ethene and propylene. In one
embodiment, the production of olefins may be increased by heating
the temperature of the formation to the upper end of the pyrolysis
temperature range and by injecting hydrocarbon fluid at a
relatively high rate. In this manner, residence time of the
hydrocarbons in the formation may be reduced and dehydrogenated
hydrocarbons may tend to form olefins rather than cracking to form
H.sub.2 and coke. Olefin production may also be increased by
reducing formation pressure.
[0581] In one embodiment, electric heater 946 may be a flameless
distributed combustor. At least a portion of H.sub.2 produced from
the formation may be used as fuel for the flameless distributed
combustor.
[0582] In addition, in some embodiments, heater well 944 may heat
the formation to a synthesis gas generating temperature range.
Pyrolysis fluid 964, which may be substantially composed of
hydrocarbons with carbon numbers less than 5, may be injected into
the formation 940. When the hydrocarbons contact the formation, the
hydrocarbons may crack within the formation to produce methane,
H.sub.2, and coke.
[0583] FIG. 35 depicts an embodiment of a synthesis gas generating
process from coal formation 976 with flameless distributed
combustor 996. Synthesis gas 980 produced from production well 978
may be fed into gas separation plant 984 where carbon dioxide 986
may be separated from synthesis gas 980. First portion 990 of
carbon dioxide may be routed to a formation for sequestration.
Second portion 992 of carbon dioxide may also be injected into the
formation with synthesis gas generating fluid. Portion 993 of
synthesis gas 988 may be fed to heater well 994 for combustion in
distributed burner 996 to produce heat for the formation. Portion
998 of synthesis gas 988 may be fed to fuel cell 1000 for the
production of electricity. Electricity 1002 may be routed to a
power grid. Steam 1004 produced in the fuel cell and steam 1006
produced from combustion in the distributed burner may be fed to
the formation for generation of synthesis gas.
[0584] In one embodiment, carbon dioxide generated with pyrolysis
fluids as described herein may be sequestered in a coal formation.
FIG. 36 illustrates in situ pyrolysis in coal formation 1020.
Heater well 1022 with electric heater 1024 may be disposed in
formation 1020. Pyrolysis fluids 1026 may be produced from
formation 1020 and fed into gas separation unit 1028 where carbon
dioxide 1030 may be separated from pyrolysis fluids 1032. Portion
1034 of carbon dioxide 1030 may be stored in formation 1036. The
carbon dioxide may be sequestered in spent coal formation 1038,
injected into oil producing fields 1040 for enhanced oil recovery,
or sequestered into coal bed 1042. Alternatively, carbon dioxide
may also be re-injected 1044 into a section of formation 1020
through a synthesis gas production well to produce carbon monoxide.
At least a portion of electricity 1035 may be used to power one or
more electric heaters.
[0585] In one embodiment, fluid produced from pyrolysis of at least
some hydrocarbons in a formation may be fed into a reformer to
produce synthesis gas. The synthesis gas may be fed into a fuel
cell to produce electricity. In addition, carbon dioxide generated
by the fuel cell may be sequestered to reduce an amount of
emissions generated by the process.
[0586] As shown in FIG. 37, heater well 1060 may be located within
coal formation 1062. Additional heater wells may also be located
within the formation. Heater well 1060 may include electric heater
1064. Pyrolysis fluid 1066 produced from the formation may be fed
to a reformer, such as steam reformer 1068, to produce synthesis
gas 1070. A portion of the pyrolysis products may be used as fuel
in the reformer. Steam reformer 1068 may include a catalyst
material that promotes the reforming reaction and a burner to
supply heat for the endothermic reforming reaction. A steam source
may be connected to the reformer section to provide steam for the
reforming reaction. The burner may operate at temperatures well
above that required by the reforming reaction and well above the
operating temperatures of fuel cells. As such, it may be desirable
to operate the burner as a separate unit independent of the fuel
cell.
[0587] Alternatively, a reformer may include multiple tubes that
may be made of refractory metal alloys. Each tube may include a
packed granular or pelletized material having a reforming catalyst
as a surface coating. A diameter of the tubes may vary from between
about 9 cm and about 16 cm, and the heated length of the tube may
normally be between about 6 m and about 12 m. A combustion zone may
be provided external to the tubes, and may be formed in the burner.
A surface temperature of the tubes may be maintained by the burner
at a temperature of about 900.degree. C. to ensure that the
hydrocarbon fluid flowing inside the tube is properly catalyzed
with steam at a temperature between about 500.degree. C. and about
700.degree. C. A traditional tube reformer may rely upon conduction
and convection heat transfer within the tube to distribute heat for
reforming.
[0588] In addition, hydrocarbon fluids, such as pyrolysis fluids,
may be pre-processed prior to being fed to a reformer. The reformer
may be configured to transform the pyrolysis fluids into simpler
reactants prior to introduction to a fuel cell. For example,
pyrolysis fluids may be pre-processed in a desulfurization unit.
Subsequent to pre-processing, the pyrolysis fluids may be provided
to a reformer and a shift reactor to produce a suitable fuel stock
for a H.sub.2 fueled fuel cell.
[0589] The synthesis gas produced by the reformer may include any
of the components described above, such as methane. The produced
synthesis gas 1070 may be fed to fuel cell 1072. A portion of
electricity 1074 produced by the fuel cell may be sent to a power
grid. In addition, a portion of electricity 1076 may be used to
power electric heater 1064. Carbon dioxide 1078 exiting the fuel
cell may be routed to sequestration area 1080.
[0590] Alternatively, in one embodiment, pyrolysis fluids 1066
produced from the formation may be fed to reformer 1068 that
produces carbon dioxide stream 1082 and H.sub.2 stream 1070. For
example, the reformer may include a flameless distributed combustor
for a core, and, a membrane. The membrane may allow only H.sub.2 to
pass through the membrane resulting in separation of the H.sub.2
and carbon dioxide. The carbon dioxide may be routed to
sequestration area 1080.
[0591] Synthesis gas produced from a formation may be converted to
heavier condensable hydrocarbons. For example, a Fischer-Tropsch
hydrocarbon synthesis process may be used for conversion of
synthesis gas. A Fischer-Tropsch process may include converting
synthesis gas to hydrocarbons. The process may use elevated
temperatures, normal or elevated pressures, and a catalyst, such as
magnetic iron oxide or a cobalt catalyst. Products produced from a
Fischer-Tropsch process may include hydrocarbons having a broad
molecular weight distribution and may include branched and
unbranched paraffins. Products from a Fischer-Tropsch process may
also include considerable quantities of olefins and
oxygen-containing organic compounds. An example of a
Fischer-Tropsch reaction may be illustrated by the following:
(n+2)CO+(2n+5)H.sub.2CH.sub.3(--CH.sub.2--)nCH.sub.3+(n+2)H.sub.2O
(7)
[0592] A hydrogen to carbon monoxide ratio for synthesis gas used
as a feed gas for a Fischer-Tropsch reaction may be about 2:1. In
certain embodiments the ratio may range from approximately 1.8:1 to
2.2:1. Higher or lower ratios may be accommodated by certain
Fischer-Tropsch systems.
[0593] FIG. 38 illustrates a flowchart of a Fischer-Tropsch process
that uses synthesis gas produced from a coal formation as a feed
stream. Hot formation 1090 may be used to produce synthesis gas
having a H.sub.2 to CO ratio of approximately 2:1. The proper ratio
may be produced by operating synthesis production wells at
approximately 700.degree. C., or by blending synthesis gas produced
from different sections of formation to obtain a synthesis gas
having approximately a 2:1 H.sub.2 to CO ratio. Synthesis gas
generating fluid 1092 may be fed into the hot formation 1090 to
generate synthesis gas. H.sub.2 and CO may be separated from the
synthesis gas produced from the hot formation 1090 to form feed
stream 1094. Feed stream 1094 may be sent to Fischer-Tropsch plant
1096. Feed stream 1094 may supplement or replace synthesis gas 1098
produced from catalytic methane reformer 1100.
[0594] Fischer-Tropsch plant 1096 may produce wax feed stream 1102.
The Fischer-Tropsch synthesis process that produces wax feed stream
1102 is an exothermic process. Steam 1104 may be generated during
the Fischer-Tropsch process. Steam 1104 may be used as a portion of
synthesis gas generating fluid 1092.
[0595] Wax feed stream 1102 produced from Fischer-Tropsch plant
1096 may be sent to hydrocracker 1106. The hydrocracker may produce
product stream 1108. The product stream may include diesel, jet
fuel, and/or naphtha products. Examples of methods for conversion
of synthesis gas to hydrocarbons in a Fischer-Tropsch process are
illustrated in U.S. Pat. No. 4,096,163 to Chang et al., U.S. Pat.
No. 6,085,512 to Agee et al., and U.S. Pat. No. 6,172,124 to
Wolflick et al., which are incorporated by reference as if fully
set forth herein.
[0596] FIG. 39 depicts an embodiment of in situ synthesis gas
production integrated with a Shell Middle Distillates Synthesis
(SMDS) Fischer-Tropsch and wax cracking process. An example of a
SMDS process is illustrated in U.S. Pat. No. 4,594,468 to
Minderhoud, and is incorporated by reference as if fully set forth
herein. A middle distillates hydrocarbon mixture may also be
produced from produced synthesis gas using the SMDS process as
illustrated in FIG. 39. Middle distillates may designate
hydrocarbon mixtures with a boiling point range that may correspond
substantially with that of kerosene and gas oil fractions obtained
in a conventional atmospheric distillation of crude oil material.
The middle distillate boiling point range may include temperatures
between about 150.degree. C. and about 360.degree. C., with a
fractions boiling point between about 200.degree. C. and about
360.degree. C., and may be referred to as gas oil. FIG. 39 depicts
synthesis gas 1120, having a H.sub.2 to carbon monoxide ratio of
about 2:1, that may exit production well 1128 and may be fed into
SMDS plant 1122. In certain embodiments the ratio may range from
approximately 1.8:1 to 2.2:1. Products of the SMDS plant include
organic liquid product 1124 and steam 1126. Steam 1126 may be
supplied to injection wells 1127. In this manner, steam may be used
as a feed for synthesis gas production. Hydrocarbon vapors may in
some circumstances be added to the steam.
[0597] FIG. 40 depicts an embodiment of in situ synthesis gas
production integrated with a catalytic methanation process. For
example, synthesis gas 1140 exiting production well 1142 may be
supplied to catalytic methanation plant 1144. In some embodiments,
it may be desirable for the composition of produced synthesis gas,
which may be used as a feed gas for a catalytic methanation
process, to have a H.sub.2 to carbon monoxide ratio of about three
to one. Methane 1146 may be produced by catalytic methanation plant
1144. Steam 1148 produced by plant 1144 may be supplied to
injection well 1141 for production of synthesis gas. Examples of a
catalytic methanation process are illustrated in U.S. Pat. No.
3,992,148 to Child, U.S. Pat. No. 4,130,575 to Jorn et al., and
U.S. Pat. No. 4,133,825 to Stroud et al., which are incorporated by
reference as if fully set forth herein.
[0598] The synthesis gas produced may also be used as a feed for a
process for production of methanol. Examples of processes for
production of methanol are illustrated in U.S. Pat. No. 4,407,973
to van Dijk et al., U.S. Pat. No. 4,927,857 to McShea, III et al.,
and U.S. Pat. No. 4,994,093 to Wetzel et al., which are
incorporated by reference as if fully set forth herein. The
produced synthesis gas may also be used as a feed gas for a process
that may convert synthesis gas to gasoline and a process that may
convert synthesis gas to diesel fuel. Examples of process for
producing engine fuels are illustrated in U.S. Pat. No. 4,076,761
to Chang et al., U.S. Pat. No. 4,138,442 to Chang et al., and U.S.
Pat. No. 4,605,680 to Beuther et al., which are incorporated by
reference as if fully set forth herein.
[0599] In one embodiment, produced synthesis gas may be used as a
feed gas for production of ammonia and urea as illustrated by FIGS.
41 and 42. Ammonia may be synthesized by the Haber-Bosch process,
which involves synthesis directly from N.sub.2 and H.sub.2
according to the reaction:
N.sub.2+3H.sub.22NH.sub.3 (8)
[0600] The N.sub.2 and H.sub.2 may be combined, compressed to high
pressure (e.g., from about 80 bars to about 220 bars) and heated to
a relatively high temperature. The reaction mixture may be passed
over a catalyst composed substantially of iron, where ammonia
production may occur. During ammonia synthesis, the reactants
(i.e., N.sub.2 and H.sub.2) and the product (i.e., ammonia) may be
in equilibrium. In this manner, the total amount of ammonia
produced may be increased by shifting the equilibrium towards
product formation. Equilibrium may be shifted to product formation
by removing ammonia from the reaction mixture as it is
produced.
[0601] Removal of the ammonia may be accomplished by cooling the
gas mixture to a temperature between about (-5).degree. C. to about
25.degree. C. In this temperature range, a two-phase mixture may be
formed with ammonia in the liquid phase and N.sub.2 and H.sub.2 in
the gas phase. The ammonia may be separated from other components
of the mixture. The nitrogen and hydrogen may be subsequently
reheated to the operating temperature for ammonia conversion and
passed through the reactor again.
[0602] Urea may be prepared by introducing ammonia and carbon
dioxide into a reactor at a suitable pressure (e.g., from about 125
bars absolute to about 350 bars absolute) and at a suitable
temperature (e.g., from about 160.degree. C. to about 250.degree.
C.). Ammonium carbamate may be formed according to the following
reaction:
2NH.sub.3+CO.sub.2.fwdarw.NH.sub.2(CO.sub.2)NH.sub.4 (9)
[0603] Urea may be subsequently formed by dehydrating the ammonium
carbamate according to the following equilibrium reaction:
NH.sub.2(CO.sub.2)NH.sub.4NH.sub.2(CO)NH.sub.2+H.sub.2O (10)
[0604] The degree to which the ammonia conversion takes place may
depend on, for example, the temperature and the amount of excess
ammonia. The solution obtained as the reaction product may
substantially include urea, water, ammonium carbamate and unbound
ammonia. The ammonium carbamate and the ammonia may need to be
removed from the solution. Once removed, they may be returned to
the reactor. The reactor may include separate zones for the
formation of ammonium carbamate and urea. However, these zones may
also be combined into one piece of equipment.
[0605] According to one embodiment, a high pressure urea plant may
operate such that the decomposition of the ammonium carbamate that
has not been converted into urea and the expulsion of the excess
ammonia may be conducted at a pressure between 15 bars absolute and
100 bars absolute. This may be considerably lower than the pressure
in the urea synthesis reactor. The synthesis reactor may be
operated at a temperature of about 180.degree. C. to about
210.degree. C. and at a pressure of about 180 bars absolute to
about 300 bars absolute. Ammonia and carbon dioxide may be directly
fed to the urea reactor. The NH.sub.3/CO.sub.2 molar ratio (N/C
molar ratio) in the urea synthesis may generally be between about 3
and about 5. The unconverted reactants may be recycled to the urea
synthesis reactor following expansion, dissociation, and/or
condensation.
[0606] In one embodiment, an ammonia feed stream having a selected
ratio of H.sub.2 to N.sub.2 may be generated from a formation using
enriched air. A synthesis gas generating fluid and an enriched air
stream may be provided to the formation. The composition of the
enriched air may be selected to generate synthesis gas having the
selected ratio of H.sub.2 to N.sub.2. In one embodiment, the
temperature of the formation may be controlled to generate
synthesis gas having the selected ratio.
[0607] In one embodiment, the H.sub.2 to N.sub.2 ratio of the feed
stream provided to the ammonia synthesis process may be
approximately 3:1. In other embodiments, the ratio may range from
approximately 2.8:1 to 3.2:1. An ammonia synthesis feed stream
having a selected H.sub.2 to N.sub.2 ratio may be obtained by
blending feed streams produced from different portions of the
formation.
[0608] In one embodiment, ammonia from the ammonia synthesis
process may be provided to a urea synthesis process to generate
urea. Ammonia produced during pyrolysis may be added to the ammonia
generated from the ammonia synthesis process. In another
embodiment, ammonia produced during hydrotreating may be added to
the ammonia generated from the ammonia synthesis process. Some of
the carbon monoxide in the synthesis gas may be converted to carbon
dioxide in a shift process. The carbon dioxide from the shift
process may be fed to the urea synthesis process. Carbon dioxide
generated from treatment of the formation may also be fed, in some
instances, to the urea synthesis process.
[0609] FIG. 41 illustrates an embodiment of a method for production
of ammonia and urea from synthesis gas using membrane-enriched air.
Enriched air 1170 and steam, or water, 1172 may be fed into hot
carbon containing formation 1174 to produce synthesis gas 1176 in a
wet oxidation mode as described herein.
[0610] In certain embodiments, enriched air 1170 is blended from
air and oxygen streams such that the nitrogen to hydrogen ratio in
the produced synthesis gas is about 1:3. The synthesis gas may be
at a correct ratio of nitrogen and hydrogen to form ammonia. For
example, it has been calculated that for a formation temperature of
700.degree. C. and a pressure of 3 bar absolute, and with 13,231
tons/day of char that will be converted into synthesis gas, one
could inject 14.7 kilotons/day of air, 6.2 kilotons/day of oxygen,
and 21.2 kilotons/day of steam. This would result in production of
2 billion cubic feet/day of synthesis gas including 5689 tons/day
of steam, 16,778 tons/day of carbon monoxide, 1406 tons/day of
hydrogen, 18,689 tons/day of carbon dioxide, 1258 tons/day of
methane, and 11,398 tons/day of nitrogen. After a shift reaction
(to shift the carbon monoxide to carbon dioxide, and to produce
additional hydrogen), the carbon dioxide may be removed, the
product stream may be methanated (to remove residual carbon
monoxide), and then one can theoretically produce 13,840 tons/day
of ammonia and 1258 tons/day of methane. This calculation includes
the products produced from Reactions (4) and (5) above.
[0611] Enriched air may be produced from a membrane separation
unit. Membrane separation of air may be primarily a physical
process. Based upon specific characteristics of each molecule, such
as size and permeation rate, the molecules in air may be separated
to form substantially pure forms of nitrogen, oxygen, or
combinations thereof.
[0612] In one embodiment, a membrane system may include a hollow
tube filled with a plurality of very thin membrane fibers. Each
membrane fiber may be another hollow tube in which air flows. The
walls of the membrane fiber may be porous and may be configured
such that oxygen may permeate through the wall at a faster rate
than nitrogen. In this manner, a nitrogen rich stream may be
allowed to flow out the other end of the fiber. Air outside the
fiber and in the hollow tube may be oxygen enriched. Such air may
be separated for subsequent uses such as production of synthesis
gas from a formation.
[0613] In one embodiment, the purity of the nitrogen generated may
be controlled by variation of the flow rate and/or pressure of air
through the membrane. Increasing air pressure may increase
permeation of oxygen molecules through a fiber wall. Decreasing
flow rate may increase the residence time of oxygen in the membrane
and, thus, may increase permeation through the fiber wall. Air
pressure and flow rate may be adjusted to allow a system operator
to vary the amount and purity of the nitrogen generated in a
relatively short amount of time.
[0614] The amount of N.sub.2 in the enriched air may be adjusted to
provide a N:H ratio of about 3:1 for ammonia production. It may be
desirable to generate synthesis gas at a temperature that may favor
the production of carbon dioxide over carbon monoxide. It may be
advantageous for the temperature of the formation to be between
about 400.degree. C. and about 550.degree. C. In another
embodiment, it may be desirable for the temperature of the
formation to be between about 400.degree. C. and about 450.degree.
C. Synthesis gas produced at such low temperatures may be
substantially composed of N.sub.2, H.sub.2, and carbon dioxide with
little carbon monoxide.
[0615] As illustrated in FIG. 41, a feed stream for ammonia
production may be prepared by first feeding synthesis gas stream
1176 into ammonia feed stream gas processing unit 1178. In ammonia
feed stream gas processing unit 1178 the feed stream may undergo a
shift reaction (to shift the carbon monoxide to carbon dioxide, and
to produce additional hydrogen). Carbon dioxide can also be removed
from the feed stream, and the feed stream can be methanated (to
remove residual carbon monoxide).
[0616] In certain embodiments carbon dioxide may be separated from
the feed stream (or any gas stream) by absorption in an amine unit.
Membranes or other carbon dioxide separation techniques/equipment
may also be used to separate carbon dioxide from a feed stream.
[0617] Ammonia feed stream 1180 may be fed to ammonia production
facility 1182 to produce ammonia 1184. Carbon dioxide 1186 exiting
the gas separation unit 1178 (and/or carbon dioxide from other
sources) may be fed, with ammonia 1184, into urea production
facility 1188 to produce urea 1190.
[0618] Ammonia and urea may be produced using a carbon containing
formation, and using an O.sub.2 rich stream and a N.sub.2 rich
stream. The O.sub.2 rich stream and synthesis gas generating fluid
may be provided to a formation. The formation may be heated, or
partially heated, by oxidation of carbon in the formation with the
O.sub.2 rich stream. H.sub.2 in the synthesis gas, and N.sub.2 from
the N.sub.2 rich stream, may be provided to an ammonia synthesis
process to generate ammonia.
[0619] FIG. 42 illustrates a flowchart of an embodiment for
production of ammonia and urea from synthesis gas using
cryogenically separated air. Air 2000 may be fed into cryogenic air
separation unit 2002. Cryogenic separation involves a distillation
process that may occur at temperatures between about (-168).degree.
C. and (-172).degree. C. In other embodiments, the distillation
process may occur at temperatures between about (-165).degree. C.
and (-175).degree. C. Air may liquefy in these temperature ranges.
The distillation process may be operated at a pressure between
about 8 bars absolute and about 10 bars absolute. High pressures
may be achieved by compressing air and exchanging heat with cold
air exiting the column. Nitrogen is more volatile than oxygen and
may come off as a distillate product. N.sub.2 2004 exiting the
separator may be utilized in heat exchanger 2006 to condense higher
molecular weight hydrocarbons from pyrolysis stream 2008 to remove
lower molecular weight hydrocarbons from the gas phase into a
liquid oil phase. Upgraded gas stream 2010 containing a higher
composition of lower molecular weight hydrocarbons than stream 2008
and liquid stream 2012, which includes condensed hydrocarbons, may
exit heat exchanger 2006.
[0620] Oxygen 2014 from cryogenic separation unit 2002 and steam
20l6, or water, may be fed into hot carbon containing formation
2018 to produce synthesis gas 2020 in a continuous process as
described herein. It is desirable to generate synthesis gas at a
temperature that favors the formation of carbon dioxide over carbon
monoxide. It may be advantageous for the temperature of the
formation to be between about 400.degree. C. and about 550.degree.
C. In another embodiment, it may be desirable for the temperature
of the formation to be between about 400.degree. C. and about
450.degree. C. Synthesis gas 2020 may be substantially composed of
H.sub.2 and carbon dioxide. Carbon dioxide may be removed from
synthesis gas 2020 to prepare a feed stream for ammonia production
using amine gas separation unit 2022. H.sub.2 stream 2024 from the
gas separation unit and N.sub.2 stream 2026 from the heat exchanger
may be fed into ammonia production facility 2028 to produce ammonia
2030. Carbon dioxide 2032 exiting the gas separation unit and
ammonia 2030 may be fed into urea production facility 2034 to
produce urea 2036.
[0621] In one embodiment, an ammonia synthesis process feed stream
may be generated by feeding a gas containing N.sub.2 and carbon
dioxide to a carbon containing formation. The gas may be flue gas
or it may be gas generated by an oxidation reaction of O.sub.2 with
carbon in another portion of the formation. The gas containing
N.sub.2 and carbon dioxide may be provided to a carbon containing
formation. The carbon dioxide in the gas may adsorb in the
formation and be sequestered therein. An exit stream may be
produced from the formation. The exit stream may have a
substantially lower percentage of carbon dioxide than the gas
entering the formation. The nitrogen in the exit gas may be
provided to an ammonia synthesis process. H.sub.2 in synthesis gas
from another portion of the formation may be provided to the
ammonia synthesis process.
[0622] FIG. 43 illustrates an embodiment of a method for preparing
a nitrogen stream for an ammonia and urea process. Air 2060 may be
injected into hot carbon containing formation 2062 to produce
carbon dioxide by oxidation of carbon in the formation. In an
embodiment, a heater may be configured to heat at least a portion
of the carbon containing formation to a temperature sufficient to
support oxidation of the carbon. The temperature sufficient to
support oxidation may be, for example, about 260.degree. C. for
coal. Stream 2064 exiting the hot formation may be composed
substantially of carbon dioxide and nitrogen. Nitrogen may be
separated from carbon dioxide by passing the stream through cold
spent carbon containing formation 2066. Carbon may be
preferentially adsorbed versus nitrogen in the cold spent formation
2066. For example, at 50.degree. C. and 0.35 bars, the adsorption
of carbon dioxide on a spent portion of coal may be about 72
m.sup.3/metric ton compared to about 15.4 m.sup.3/metric ton for
nitrogen. Nitrogen 2068 exiting the cold spent portion 2066 may be
supplied to ammonia production facility 2070 with H.sub.2 stream
2072 to produce ammonia 2074. The H.sub.2 stream may be obtained by
methods disclosed herein, for example, the methods described in
FIGS. 41 and 42.
[0623] Several patterns of heat sources arranged in rings around
production wells may be utilized to create a radial pyrolysis
region in coal formations. Various patterns shown in FIGS. 44-57
are described herein. FIG. 44 illustrates an embodiment of a
pattern of heat sources 2705 that may create a radial pyrolysis
zone. Production well 2701 may be surrounded by concentric rings
2702, 2703, and 2704 of heat sources 2705. Heat sources 2705 in
ring 2702 may heat the formation to create radial pyrolysis zone
2710. Fluids may be produced through production well 2701. In one
embodiment, an average distance between heat sources may be between
about 2 m and about 20 m. Alternatively, the average distance may
be between about 10 m and about 30 m.
[0624] As in other embodiments, it may be desirable to create
pyrolysis zones sequentially. Heat sources 2705 nearest production
well 2701 may be activated first, for example, heat sources 2705 in
ring 2702. A substantially uniform temperature pyrolysis zone may
be established after a period of time. Fluids that flow through the
pyrolysis zone may undergo pyrolysis and vaporization. Fluid may
flow inward towards production well 2701 due to a pressure
differential between a zone around the production well and the
pyrolysis zone, as indicated by the arrows.
[0625] A larger low viscosity zone may be developed by repeatedly
activating heat sources farther away from the fracture, for
example, heat sources 2705 in ring 2704.
[0626] Several patterns of heat sources and production wells may be
utilized in embodiments of radial heating zones. The heat sources
may be arranged in rings around the production wells. The pattern
around each production well may be a hexagon that may contain a
number of heat sources.
[0627] In FIG. 45, production well 2701 and heat source 2712 may be
located at the apices of a triangular grid. The triangular grid may
be an equilateral triangular grid with sides of length s.
Production wells 2701 may be spaced at a distance of about
1.732(s). Production well 2701 may be disposed at a center of a
hexagonal pattern with one ring 2713 of six heat sources 2712. Each
heat source 2712 may provide substantially equal amounts of heat to
three production wells. Therefore, each ring 2713 of six heat
sources 2712 may contribute approximately two equivalent heat
sources per production well 2701.
[0628] FIG. 46 illustrates a pattern of production wells 2701 with
an inner hexagonal ring 2713 and an outer hexagonal ring 2715 of
heat sources 2712. In this pattern, production wells 2701 may be
spaced at a distance of about 2 (1.732)s. Heat sources 2712 may be
located at all other grid positions. This pattern may result in a
ratio of equivalent heat sources to production wells that may
approach eleven.
[0629] FIG. 47 illustrates three rings of heat sources 2712
surrounding production well 2701. Production well 2701 may be
surrounded by ring 2713 of six heat sources 2712. Second
hexagonally shaped ring 2716 of twelve heat sources 2712 may
surround ring 2713. Third ring 2718 of heat sources 2712 may
include twelve heat sources that may provide substantially equal
amounts of heat to two production wells and six heat sources that
may provide substantially equal amounts of heat to three production
wells. Therefore, a total of eight equivalent heat sources may be
disposed on third ring 2718. Production well 2701 may be provided
heat from an equivalent of about twenty-six heat sources. FIG. 48
illustrates an even larger pattern that may have a greater spacing
between production wells 2701.
[0630] Alternatively, square patterns may be provided with
production wells placed, for example, in the center of each third
square, resulting in four heat sources for each production well.
Production wells may be placed within each fifth square in a square
pattern, which may result in sixteen heat sources for each
production well.
[0631] FIGS. 49, 50, 51, and 52 illustrate alternate embodiments in
which both production wells and heat sources may be located at the
apices of a triangular grid. In FIG. 49, a triangular grid, with a
spacing of s, may have production wells 2701 spaced at a distance
of 2 s. A hexagonal pattern may include one ring 2730 of six heat
sources 2732. Each heat source 2732 may provide substantially equal
amounts of heat to two production wells 2701. Therefore, each ring
2730 of six heat sources 2732 contributes approximately three
equivalent heat sources per production well 2701.
[0632] FIG. 50 illustrates a pattern of production wells 2701 with
inner hexagonal ring 2734 and outer hexagonal ring 2736. Production
wells 2701 may be spaced at a distance of 3 s. Heat sources 2732
may be located at apices of hexagonal ring 2734 and hexagonal ring
2736. Hexagonal ring 2734 and hexagonal ring 2736 may include six
heat sources each. The pattern in FIG. 50 may result in a ratio of
heat sources 2732 to production well 2701 of eight.
[0633] FIG. 51 illustrates a pattern of production wells 2701 also
with two hexagonal rings of heat sources surrounding each
production well. Production well 2701 may be surrounded by ring
2738 of six heat sources 2732. Production wells 2701 may be spaced
at a distance of 4 s. Second hexagonally shaped ring 2740 may
surround ring 2738. Second hexagonally shaped ring 2740 may include
twelve heat sources 2732. This pattern may result in a ratio of
heat sources 2732 to production wells 2701 that may approach
fifteen.
[0634] FIG. 52 illustrates a pattern of heat sources 2732 with
three rings of heat sources 2732 surrounding each production well
2701. Production wells 2701 may be surrounded by ring 2742 of six
heat sources 2732. Second ring 2744 of twelve heat sources 2732 may
surround ring 2742. Third ring 2746 of heat sources 2732 may
surround second ring 2744. Third ring 2746 may include 6 equivalent
heat sources. This pattern may result in a ratio of heat sources
2732 to production wells 2701 that is about 24:1.
[0635] FIGS. 53, 54, 55, and 56 illustrate patterns in which the
production well may be disposed at a center of a triangular grid
such that the production well may be equidistant from the apices of
the triangular grid. In FIG. 53, the triangular grid of heater
wells with a spacing of s may include production wells 2760 spaced
at a distance of s. Each production well 2760 may be surrounded by
ring 2764 of three heat sources 2762. Each heat source 2762 may
provide substantially equal amounts of heat to three production
wells 2760. Therefore, each ring 2764 of three heat sources 2762
may contribute one equivalent heat source per production well
2760.
[0636] FIG. 54 illustrates a pattern of production wells 2760 with
inner triangular ring 2766 and outer ring 2768. In this pattern,
production wells 2760 may be spaced at a distance of 2 s. Heat
sources 2762 may be located at apices of inner ring 2766 and outer
ring 2768. Inner ring may contribute three equivalent heat sources
per production well 2760. Outer hexagonal ring 2768 containing
three heater wells may contribute one equivalent heat source per
production well 2760. Thus, a total of four equivalent heat sources
may provide heat to production well 2760.
[0637] FIG. 55 illustrates a pattern of production wells with one
inner triangular ring of heat sources surrounding each production
well, one inverted triangular ring, and one irregular hexagonal
outer ring. Production wells 2760 may be surrounded by ring 2770 of
three heat sources 2762. Production wells 2760 may be spaced at a
distance of 3 s. Irregular hexagonally shaped ring 2772 of nine
heat sources 2762 may surround ring 2770. This pattern may result
in a ratio of heat sources 2762 to production wells 2760 of
three.
[0638] FIG. 56 illustrates triangular patterns of heat sources with
three rings of heat sources surrounding each production well.
Production wells 2760 may be surrounded by ring 2774 of three heat
sources 2762. Irregular hexagon pattern 2776 of nine heat sources
2762 may surround ring 2774. Third set 2778 of heat sources 2762
may surround hexagonal pattern 2776. Third set 2778 may contribute
four equivalent heat sources to production well 2760. A ratio of
equivalent heat sources to production well 2760 may be sixteen.
[0639] One embodiment for treating at least a portion of a coal
formation may include heating the formation from three or more heat
sources. At least three of the heat sources may be arranged in a
substantially triangular pattern. At least some hydrocarbons in a
selected section of the formation may be pyrolyzed by the heat from
the three or more heat sources. Pyrolyzation fluids generated by
pyrolysis of hydrocarbons in the formation may be produced from the
formation. In one embodiment, fluids may be produced through at
least one production well disposed in the formation.
[0640] FIG. 57 depicts an embodiment of a pattern of heat sources
2705 arranged in a triangular pattern. Production well 2701 may be
surrounded by triangles 2780, 2782, and 2784 of heat sources 2705.
Heat sources 2705 in triangles 2780, 2782, and 2784 may provide
heat to the formation. The provided heat may raise an average
temperature of the formation to a pyrolysis temperature.
Pyrolyzation fluids may flow to production well 2701. Formation
fluids may be produced in production well 2701.
[0641] FIG. 58 illustrates a schematic diagram of an embodiment of
surface facilities 2800 that may be configured to treat a formation
fluid. The formation fluid may be produced though a production well
as described herein. The formation fluid may include any of a
formation fluid produced by any of the methods as described herein.
As shown in FIG. 58, surface facilities 2800 may be coupled to well
head 2802. Well head 2802 may also be coupled to a production well
formed in a formation. For example, the well head may be coupled to
a production well by various mechanical devices proximate an upper
surface of the formation. Therefore, a formation fluid produced
through a production well may also flow through well head 2802.
Well head 2802 may be configured to separate the formation fluid
into gas stream 2804, liquid hydrocarbon condensate stream 2806,
and water stream 2808.
[0642] Surface facilities 2800 may be configured such that water
stream 2808 may flow from well head 2802 to a portion of a
formation, to a containment system, or to a processing unit. For
example, water stream 2808 may flow from well head 2802 to an
ammonia production unit. The surface facilities may be configured
such that ammonia produced in the ammonia production unit may flow
to an ammonium sulfate unit. The ammonium sulfate unit may be
configured to combine the ammonia with H.sub.2SO.sub.4 or
SO.sub.2/SO.sub.3 to produce ammonium sulfate. In addition, the
surface facilities may be configured such that ammonia produced in
the ammonia production unit may flow to a urea production unit. The
urea production unit may be configured to combine carbon dioxide
with the ammonia to produce urea.
[0643] Surface facilities 2800 may be configured such that gas
stream 2804 may flow through a conduit from well head 2802 to gas
treatment unit 2810. The conduit may include a pipe or any other
fluid communication mechanism known in the art. The gas treatment
unit may be configured to separate various components of gas stream
2804. For example, the gas treatment unit may be configured to
separate gas stream 2804 into carbon dioxide stream 2812, hydrogen
sulfide stream 2814, hydrogen stream 2816, and stream 2818 that may
include, but may not be limited to, methane, ethane, propane,
butanes (including n-butane or iso-butane), pentane, ethene,
propene, butene, pentene, water or combinations thereof.
[0644] Surface facilities 2800 may be configured such that the
carbon dioxide stream may flow through a conduit to a formation, to
a containment system, to a disposal unit, and/or to another
processing unit. In addition, the facilities may be configured such
that the hydrogen sulfide stream may also flow through a conduit to
a containment system and/or to another processing unit. For
example, the hydrogen sulfide stream may be converted into
elemental sulfur in a Claus process unit. The gas treatment unit
may also be configured to separate gas stream 2804 into stream 2819
that may include heavier hydrocarbon components from gas stream
2804. Heavier hydrocarbon components may include, for example,
hydrocarbons having a carbon number of greater than about 5.
Surface facilities 2800 may be configured such that heavier
hydrocarbon components in stream 2819 may be provided to liquid
hydrocarbon condensate stream 2806.
[0645] Surface facilities 2800 may also include processing unit
2821. Processing unit 2821 may be configured to separate stream
2818 into a number of streams. Each of the number of streams may be
rich in a predetermined component or a predetermined number of
compounds. For example, processing unit 2821 may separate stream
2818 into first portion 2820 of stream 2818, second portion 2823 of
stream 2818, third portion 2825 of stream 2818, and fourth portion
2831 of stream 2818. First portion 2820 of stream 2818 may include
lighter hydrocarbon components such as methane and ethane. The
surface facilities may be configured such that first portion 2820
of stream 2818 may flow from gas treatment unit 2810 to power
generation unit 2822.
[0646] Power generation unit 2822 may be configured for extracting
useable energy from the first portion of stream 2818. For example,
stream 2818 may be produced under pressure. In this manner, power
generation unit may include a turbine configured to generate
electricity from the first portion of stream 2818. The power
generation unit may also include, for example, a molten carbonate
fuel cell, a solid oxide fuel cell, or other type of fuel cell. The
facilities may be further configured such that the extracted
useable energy may be provided to user 2824. User 2824 may include,
for example, surface facilities 2800, a heat source disposed within
a formation, and/or a consumer of useable energy.
[0647] Second portion 2823 of stream 2818 may also include light
hydrocarbon components. For example, second portion 2823 of stream
2818 may include, but may not be limited to, methane and ethane.
Surface facilities 2800 may also be configured such that second
portion 2823 of stream 2818 may be provided to natural gas grid
2827. Alternatively, surface facilities may also be configured such
that second portion 2823 of stream 2818 may be provided to a local
market. The local market may include a consumer market or a
commercial market. In this manner, the second portion 2823 of
stream 2818 may be used as an end product or an intermediate
product depending on, for example, a composition of the light
hydrocarbon components.
[0648] Third portion 2825 of stream 2818 may include liquefied
petroleum gas ("LPG"). Major constituents of LPG may include
hydrocarbons containing three or four carbon atoms such as propane
and butane. Butane may include n-butane or iso-butane. LPG may also
include relatively small concentrations of other hydrocarbons such
as ethene, propene, butene, and pentene. Depending on the source of
LPG and how it has been produced, however, LPG may also include
additional components. LPG may be a gas at atmospheric pressure and
normal ambient temperatures. LPG may be liquefied, however, when
moderate pressure is applied or when the temperature is
sufficiently reduced. When such moderate pressure is released, LPG
gas may have about 250 times a volume of LPG liquid. Therefore,
large amounts of energy may be stored and transported compactly as
LPG.
[0649] Surface facilities 2800 may also be configured such that
third portion 2825 of stream 2818 maybe provided to local market
2829. The local market may include a consumer market or a
commercial market. In this manner, the third portion 2825 of stream
2818 may be used as an end product or an intermediate product
depending on, for example, a composition of the LPG. For example,
LPG may be used in applications, such as food processing, aerosol
propellants, and automotive fuel. LPG may usually be available in
one or two forms for standard heating and cooking purposes:
commercial propane and commercial butane. Propane may be more
versatile for general use than butane because, for example, propane
has a lower boiling point than butane.
[0650] Surface facilities 2800 may also be configured such that
fourth portion 2831 of stream 2818 may flow from the gas treatment
unit to hydrogen manufacturing unit 2828. Hydrogen containing
stream 2830 is shown exiting hydrogen manufacturing unit 2828.
Examples of hydrogen manufacturing unit 2828 may include a steam
reformer and a catalytic flameless distributed combustor with a
hydrogen separation membrane. FIG. 59 illustrates an embodiment of
a catalytic flameless distributed combustor. An example of a
catalytic flameless distributed combustor with a hydrogen
separation membrane is illustrated in U.S. patent application Ser.
No. 60/273,354, filed on Mar. 5, 2001, which is incorporated by
reference as if fully set forth herein. A catalytic flameless
distributed combustor may include fuel line 2850, oxidant line
2852, catalyst 2854, and membrane 2856. Fourth portion 2831 of
stream 2818 may be provided to hydrogen manufacturing unit 2828 as
fuel 2858. Fuel 2858 within fuel line 2850 may mix within reaction
zone in annular space 2859 between the fuel line and the oxidant
line. Reaction of the fuel with the oxidant in the presence of
catalyst 2854 may produce reaction products that include H.sub.2.
Membrane 2856 may allow a portion of the generated H.sub.2 to pass
into annular space 2860 between outer wall 2862 of oxidant line
2852 and membrane 2856. Excess fuel passing out of fuel line 2850
may be circulated back to entrance of hydrogen manufacturing unit
2828. Combustion products leaving oxidant line 2852 may include
carbon dioxide and other reactions products as well as some fuel
and oxidant. The fuel and oxidant may be separated and recirculated
back to the hydrogen manufacturing unit. Carbon dioxide may be
separated from the exit stream. The carbon dioxide may be
sequestered within a portion of a formation or used for an
alternate purpose.
[0651] Fuel line 2850 may be concentrically positioned within
oxidant line 2852. Critical flow orifices within fuel line 2850 may
be configured to allow fuel to enter into a reaction zone in
annular space 2859 between the fuel line and oxidant line 2852. The
fuel line may carry a mixture of water and vaporized hydrocarbons
such as, but not limited to, methane, ethane, propane, butane,
methanol, ethanol, or combinations thereof. The oxidant line may
carry an oxidant such as, but not limited to, air, oxygen enriched
air, oxygen, hydrogen peroxide, or combinations thereof.
[0652] Catalyst 2854 may be located in the reaction zone to allow
reactions that produce H.sub.2 to proceed at relatively low
temperatures. Without a catalyst and without membrane separation of
H.sub.2 a steam reformation reaction may need to be conducted in a
series of reactors with temperatures for a shift reaction occurring
in excess of 980.degree. C. With a catalyst and with separation of
H.sub.2 from the reaction stream, the reaction may occur at
temperatures within a range from about 300.degree. C. to about
600.degree. C., or within a range from about 400.degree. C. to
about 500.degree. C. Catalyst 2854 may be any steam reforming
catalyst. In selected embodiments, catalyst 2854 is a group VIII
transition metal, such as nickel. The catalyst may be supported on
porous substrate 2864. The substrate may include group III or group
IV elements, such as, but not limited to, aluminum, silicon,
titanium, or zirconium. In an embodiment, the substrate is alumina
(Al.sub.2O.sub.3).
[0653] Membrane 2856 may remove H.sub.2 from a reaction stream
within a reaction zone of a hydrogen manufacturing unit 2828. When
H.sub.2 is removed from the reaction stream, reactions within the
reaction zone may generate additional H.sub.2. A vacuum may draw
H.sub.2 from an annular region between membrane 2856 and wall 2862
of oxidant line 2852. Alternately, H.sub.2 may be removed from the
annular region in a carrier gas. Membrane 2856 may separate H.sub.2
from other components within the reaction stream. The other
components may include, but are not limited to, reaction products,
fuel, water, and hydrogen sulfide. The membrane may be a
hydrogen-permeable and hydrogen selective material such as, but not
limited to, a ceramic, carbon, metal, or combination thereof. The
membrane may include, but is not limited to, metals of group VIII,
V, III, or I such as palladium, platinum, nickel, silver, tantalum,
vanadium, yttrium, and/or niobium. The membrane may be supported on
a porous substrate such as alumina. The support may separate the
membrane 2856 from catalyst 2854. The separation distance and
insulation properties of the support may help to maintain the
membrane within a desired temperature range. In this manner,
hydrogen manufacturing unit 2828 may be configured to produce
hydrogen-rich stream 2830 from the second portion stream 2818. The
surface facilities may also be configured such that hydrogen-rich
stream 2830 may flow into hydrogen stream 2816 to form stream 2832.
In this manner, stream 2832 may include a larger volume of hydrogen
than either hydrogen-rich stream 2830 or hydrogen stream 2816.
[0654] Surface facilities 2800 may be configured such that
hydrocarbon condensate stream 2806 may flow through a conduit from
well head 2802 to hydrotreating unit 2834. Hydrotreating unit 2834
may be configured to hydrogenate hydrocarbon condensate stream 2806
to form hydrogenated hydrocarbon condensate stream 2836. The
hydrotreater may be configured to upgrade and swell the hydrocarbon
condensate. For example, surface facilities 2800 may also be
configured to provide stream 2832 (which includes a relatively high
concentration of hydrogen) to hydrotreating unit 2834. In this
manner, H.sub.2 in stream 2832 may hydrogenate a double bond of the
hydrocarbon condensate, thereby reducing a potential for
polymerization of the hydrocarbon condensate. In addition, hydrogen
may also neutralize radicals in the hydrocarbon condensate. In this
manner, the hydrogenated hydrocarbon condensate may include
relatively short chain hydrocarbon fluids. Furthermore,
hydrotreating unit 2834 may be configured to reduce sulfur,
nitrogen, and aromatic hydrocarbons in hydrocarbon condensate
stream 2806. Hydrotreating unit 2834 may be a deep hydrotreating
unit or a mild hydrotreating unit. An appropriate hydrotreating
unit may vary depending on, for example, a composition of stream
2832, a composition of the hydrocarbon condensate stream, and/or a
selected composition of the hydrogenated hydrocarbon condensate
stream.
[0655] Surface facilities 2800 may be configured such that
hydrogenated hydrocarbon condensate stream 2836 may flow from
hydrotreating unit 2834 to transportation unit 2838. Transportation
unit 2838 may be configured to collect a volume of the hydrogenated
hydrocarbon condensate and/or to transport the hydrogenated
hydrocarbon condensate to market center 2840. For example, market
center 2840 may include, but may not be limited to, a consumer
marketplace or a commercial marketplace. A commercial marketplace
may include, but may not be limited to, a refinery. In this manner,
the hydrogenated hydrocarbon condensate may be used as an end
product or an intermediate product depending on, for example, a
composition of the hydrogenated hydrocarbon condensate.
[0656] Alternatively, surface facilities 2800 may be configured
such that hydrogenated hydrocarbon condensate stream 2836 may flow
to a splitter or an ethene production unit. The splitter may be
configured to separate the hydrogenated hydrocarbon condensate
stream into a hydrocarbon stream including components having carbon
numbers of 5 or 6, a naphtha stream, a kerosene stream, and a
diesel stream. Streams exiting the splitter may be fed to the
ethene production unit. In addition, the hydrocarbon condensate
stream and the hydrogenated hydrocarbon condensate stream may be
fed to the ethene production unit. Ethene produced by the ethene
production unit may be fed to a petrochemical complex to produce
base and industrial chemicals and polymers. Alternatively, the
streams exiting the splitter may be fed to a hydrogen conversion
unit. A recycle stream may be configured to flow from the hydrogen
conversion unit to the splitter. The hydrocarbon stream exiting the
splitter and the naphtha stream may be fed to a mogas production
unit. The kerosene stream and the diesel stream may be distributed
as product.
[0657] FIG. 60 illustrates an embodiment of an additional
processing unit that may be included in surface facilities such as
the facilities depicted in FIG. 58. Air separation unit 2900 may be
configured to generate nitrogen stream 2902 and oxygen stream 2905.
Oxygen stream 2905 and steam 2904 may be injected into exhausted
coal resource 2906 to generate synthesis gas 2907. Produced
synthesis gas 2907 may be provided to Shell Middle Distillates
process unit 2910 that may be configured to produce middle
distillates 2912. In addition, produced synthesis gas 2907 may be
provided to catalytic methanation process unit 2914 that may be
configured to produce natural gas 2916. Produced synthesis gas 2907
may also be provided to methanol production unit 2918 to produce
methanol 2920. Furthermore, produced synthesis gas 2907 may be
provided to process unit 2922 for production of ammonia and/or urea
2924, and fuel cell 2926 that may be configured to produce
electricity 2928. Synthesis gas 2907 may also be routed to power
generation unit 2930, such as a turbine or combustor, to produce
electricity 2932.
[0658] FIG. 61 illustrates an example of a square pattern of heat
sources 3000 and production wells 3002. Heat sources 3000 are
disposed at vertices of squares 3010. Production well 3002 is
placed in a center of every third square in both x- and
y-directions. Midlines 3006 are formed equidistant to two
production wells 3002, and perpendicular to a line connecting such
production wells. Intersections of midlines 3006 at vertices 3008
form unit cell 3012. Heat source 3000b and heat source 3000c are
only partially within unit cell 3012. Only the one-half fraction of
heat source 3000b and the one-quarter fraction of heat source 3000c
within unit cell 3012 are configured to provide heat within unit
cell 3012. The fraction of heat source 3000 outside of unit cell
3012 is configured to provide heat outside of unit cell 3012. The
number of heat sources 3000 within one unit cell 3012 is a ratio of
heat sources 3000 per production well 3002 within the
formation.
[0659] The total number of heat sources inside unit cell 3012 is
determined by the following method:
[0660] (a) 4 heat sources 3000a inside unit cell 3012 are counted
as one heat source each;
[0661] (b) 8 heat sources 3000b on midlines 3006 are counted as
one-half heat source each; and
[0662] (c) 4 heat sources 3000c at vertices 3008 are counted as
one-quarter heat source each.
[0663] The total number of heat sources is determined from adding
the heat sources counted by, (a) 4, (b) 8/2=4, and (c) 4/4=1, for a
total number of 9 heat sources 3000 in unit cell 3012. Therefore, a
ratio of heat sources 3000 to production wells 3002 is determined
as 9:1 for the pattern illustrated in FIG. 61.
[0664] FIG. 62 illustrates an example of another pattern of heat
sources 3000 and production wells 3002. Midlines 3006 are formed
equidistant from the two production wells 3002, and perpendicular
to a line connecting such production wells. Unit cell 3014 is
determined by intersection of midlines 3006 at vertices 3008.
Twelve heat sources 3000 are counted in unit cell 3014 by a method
as described in the above embodiments, of which are six are whole
sources of heat, and six are one third sources of heat (with the
other two thirds of heat from such six wells going to other
patterns). Thus, a ratio of heat sources 3000 to production wells
3002 is determined as 8:1 for the pattern illustrated in FIG. 62.
An example of a pattern of heat sources is illustrated in U.S. Pat.
No. 2,923,535 issued to Ljungstrom, which is incorporated by
reference as if fully set forth herein.
[0665] In certain embodiments, a triangular pattern of heat sources
may provide advantages when compared to alternative patterns of
heat sources, such as squares, hexagons, and hexagons with
additional heaters installed halfway between the hexagon corners
(12 to 1 pattern). Squares, hexagons, and the 12:1 patterns are
disclosed in U.S. Pat. No. 2,923,535 and/or in U.S. Pat. No.
4,886,118. For example, a triangular pattern of heat sources may
provide more uniform heating of a coal formation resulting from a
more uniform temperature distribution of an area of a formation
heated by the pattern of heat sources.
[0666] FIG. 63 illustrates an embodiment of triangular pattern 3100
of heat sources 3102. FIG. 64 illustrates an embodiment of square
pattern 3101 of heat sources 3103. FIG. 65 illustrates an
embodiment of hexagonal pattern 3104 of heat sources 3106. FIG. 66
illustrates an embodiment of 12 to 1 pattern 3105 of heat sources
3107. A temperature distribution for all patterns may be determined
by an analytical method. The analytical method may be simplified by
analyzing only temperature fields within "confined" patterns (e.g.,
hexagons), i.e., completely surrounded by others. In addition, the
temperature field may be estimated to be a superposition of
analytical solutions corresponding to a single heat source.
[0667] The comparisons of patterns of heat sources were evaluated
for the same heater well density and the same heating input regime.
For example, a number of heat sources per unit area in a triangular
pattern is the same as the number of heat sources per unit area in
the 10 m hexagonal pattern if the space between heat sources is
increased to about 12.2 m in the triangular pattern. The equivalent
spacing for a square pattern would be 11.3 m, while the equivalent
spacing for a 12 to 1 pattern would be 15.7 m.
[0668] A triangular pattern of heat sources may have, for example,
a shorter total process time than a square, hexagonal or 12 to 1
pattern of heat sources for the same heater well density. A total
process time may include a time required for an average temperature
of a heated portion of a formation to reach a target temperature
and a time required for a temperature at a coldest spot within the
heated portion to reach the target temperature. For example, heat
may be provided to the portion of the formation until an average
temperature of the heated portion reaches the target temperature.
After the average temperature of the heated portion reaches the
target temperature, an energy supply to the heat sources may be
reduced such that less or minimal heat may be provided to the
heated portion. An example of a target temperature may be
approximately 340.degree. C. The target temperature, however, may
vary depending on, for example, formation composition and/or
formation conditions such as pressure.
[0669] A spacing of heat sources in a triangular pattern, which may
yield the same process time as a hexagonal pattern having about a
10.0 m space between heat sources, may be equal to approximately
14.3 m. In this manner, the total process time of a hexagonal
pattern may be achieved by using about 26% less heat sources than
may be included in such a hexagonal pattern. In this manner, such a
triangular pattern may have substantially lower capital and
operating costs. As such, this triangular pattern may also be more
economical than a hexagonal pattern.
[0670] FIG. 12 depicts an embodiment of a natural distributed
combustor. In one experiment the embodiment schematically shown in
FIG. 12 was used to heat high volatile bituminous C coal in situ. A
heating well was configured to be heated with electrical resistance
heaters and/or a natural distributed combustor such as is
schematically shown in FIG. 12. Thermocouples were located every 2
feet along the length of the natural distributed combustor (along
conduit 532 as is schematically shown in FIG. 12). The coal was
first heated with electrical resistance heaters until pyrolysis was
complete proximate the well. FIG. 92 depicts square data points
measured during electrical resistance heating at various depths in
the coal after the temperature profile had stabilized (the coal
seam was about 16 feet thick starting at about 28 feet of depth).
At this point heat energy was being supplied at about 300 Watts per
foot. Air was subsequently injected via conduit 532 at gradually
increasing rates, and electric power was substantially
simultaneously decreased. Combustion products were removed from the
reaction zone in an annulus surrounding conduit 532 and the
electrical resistance heater. The electric power was decreased at
rates that would approximately offset heating provided by the
combustion of the coal caused by the natural distributed combustor.
Air rates were increased, and power rates were decreased, over a
period of about 2 hours until no electric power was being supplied.
FIG. 92 depicts diamond data points measured during natural
distributed combustion heating (without any electrical resistance
heating) at various depths in the coal after the temperature
profile had stabilized. As can be seen in FIG. 92, the natural
distributed combustion heating provided a temperature profile that
is comparable to the electrical resistance temperature profile.
This experiment demonstrated that natural distributed combustors
can provide formation heating that is comparable to the formation
heating provided by electrical resistance heaters. This experiment
was repeated at different temperatures, and in two other wells, all
with similar results.
[0671] Numerical calculations have been made for a natural
distributed combustor system configured to heat a coal formation. A
commercially available program called PRO-II was used to make
example calculations based on a conduit of diameter 6.03 cm with a
wall thickness of 0.39 cm. The conduit was disposed in an opening
in the formation with a diameter of 14.4 cm. The conduit had
critical flow orifices of 1.27 mm diameter spaced 183 cm apart. The
conduit was configured to heat a formation of 91.4 meters thick. A
flow rate of air was 1.70 standard cubic meters per minute through
the critical flow orifices. A pressure of air at the inlet of the
conduit was 7 bars absolute. Exhaust gases had a pressure of 3.3
bars absolute. A heating output of 1066 watts per meter was used. A
temperature in the opening was set at 760.degree. C. The
calculations determined a minimal pressure drop within the conduit
of about 0.023 bar. The pressure drop within the opening was less
than 0.0013 bar.
[0672] FIG. 67 illustrates extension (in meters) of a reaction zone
within a coal formation over time (in years) according to the
parameters set in the calculations. The width of the reaction zone
increases with time as the carbon was oxidized proximate to the
center. Numerical calculations have been made for heat transfer
using a conductor-in-conduit heater. Calculations were made for a
conductor having a diameter of about 1 inch (2.54 cm) disposed in a
conduit having a diameter of about 3 inches (7.62 cm). The
conductor-in-conduit heater was disposed in an opening of a carbon
containing formation having a diameter of about 6 inches (15.24
cm). An emissivity of the carbon containing formation was
maintained at a value of 0.9, which is expected for geological
materials. The conductor and the conduit were given alternate
emissivity values of high emissivity (0.86), which is common for
oxidized metal surfaces, and low emissivity (0.1), which is for
polished and/or un-oxidized metal surfaces. The conduit was filled
with either air or helium. Helium is known to be a more thermally
conductive gas than air. The space between the conduit and the
opening was filled with a gas mixture of methane, carbon dioxide,
and hydrogen gases. Two different gas mixtures were used. The first
gas mixture had mole fractions of 0.5 for methane, 0.3 for carbon
dioxide, and 0.2 for hydrogen. The second gas mixture had mole
fractions of 0.2 for methane, 0.2 for carbon dioxide, and 0.6 for
hydrogen.
[0673] FIG. 68 illustrates a calculated ratio of conductive heat
transfer to radiative heat transfer versus a temperature of a face
of the coal formation in the opening for an air filled conduit. The
temperature of the conduit was increased linearly from 93.degree.
C. to 871.degree. C. The ratio of conductive to radiative heat
transfer was calculated based on emissivity values, thermal
conductivities, dimensions of the conductor, conduit, and opening,
and the temperature of the conduit. Line 3204 is calculated for the
low emissivity value (0.1). Line 3206 is calculated for the high
emissivity value (0.86). A lower emissivity for the conductor and
the conduit provides for a higher ratio of conductive to radiative
heat transfer to the formation. The decrease in the ratio with an
increase in temperature may be due to a reduction of conductive
heat transfer with increasing temperature. As the temperature on
the face of the formation increases, a temperature difference
between the face and the heater is reduced, thus reducing a
temperature gradient that drives conductive heat transfer.
[0674] FIG. 69 illustrates a calculated ratio of conductive heat
transfer to radiative heat transfer versus a temperature at a face
of the coal formation in the opening for a helium filled conduit.
The temperature of the conduit was increased linearly from
93.degree. C. to 871.degree. C. The ratio of conductive to
radiative heat transfer was calculated based on emissivity values;
thermal conductivities; dimensions of the conductor, conduit, and
opening; and the temperature of the conduit. Line 3208 is
calculated for the low emissivity value (0.1). Line 3210 is
calculated for the high emissivity value (0.86). A lower emissivity
for the conductor and the conduit again provides for a higher ratio
of conductive to radiative heat transfer to the formation. The use
of helium instead of air in the conduit significantly increases the
ratio of conductive heat transfer to radiative heat transfer. This
may be due to a thermal conductivity of helium being about 5.2 to
about 5.3 times greater than a thermal conductivity of air.
[0675] FIG. 70 illustrates temperatures of the conductor, the
conduit, and the opening versus a temperature at a face of the coal
formation for a helium filled conduit and a high emissivity of
0.86. The opening has a gas mixture equivalent to the second
mixture described above having a hydrogen mole fraction of 0.6.
Opening temperature 3216 was linearly increased from 93.degree. C.
to 871.degree. C. Opening temperature 3216 was assumed to be the
same as the temperature at the face of the coal formation.
Conductor temperature 3212 and conduit temperature 3214 were
calculated from opening temperature 3216 using the dimensions of
the conductor, conduit, and opening, values of emissivities for the
conductor, conduit, and face, and thermal conductivities for gases
(helium, methane, carbon dioxide, and hydrogen). It may be seen
from the plots of temperatures of the conductor, conduit, and
opening for the conduit filled with helium, that at higher
temperatures approaching 871.degree. C., the temperatures of the
conductor, conduit, and opening begin to substantially
equilibrate.
[0676] FIG. 71 illustrates temperatures of the conductor, the
conduit, and the opening versus a temperature at a face of the coal
formation for an air filled conduit and a high emissivity of 0.86.
The opening has a gas mixture equivalent to the second mixture
described above having a hydrogen mole fraction of 0.6. Opening
temperature 3216 was linearly increased from 93.degree. C. to
871.degree. C. Opening temperature 3216 was assumed to be the same
as the temperature at the face of the coal formation. Conductor
temperature 3212 and conduit temperature 3214 were calculated from
opening temperature 3216 using the dimensions of the conductor,
conduit, and opening, values of emissivities for the conductor,
conduit, and face, and thermal conductivities for gases (air,
methane, carbon dioxide, and hydrogen). It may be seen from the
plots of temperatures of the conductor, conduit, and opening for
the conduit filled with air, that at higher temperatures
approaching 871.degree. C., the temperatures of the conductor,
conduit, and opening begin to substantially equilibrate, as seen
for the helium filled conduit with high emissivity.
[0677] FIG. 72 illustrates temperatures of the conductor, the
conduit, and the opening versus a temperature at a face of the coal
formation for a helium filled conduit and a low emissivity of 0.1.
The opening has a gas mixture equivalent to the second mixture
described above having a hydrogen mole fraction of 0.6. Opening
temperature 3216 was linearly increased from 93.degree. C. to
871.degree. C. Opening temperature 3216 was assumed to be the same
as the temperature at the face of the coal formation. Conductor
temperature 3212 and conduit temperature 3214 were calculated from
opening temperature 3216 using the dimensions of the conductor,
conduit, and opening, values of emissivities for the conductor,
conduit, and face, and thermal conductivities for gases (helium,
methane, carbon dioxide, and hydrogen). It may be seen from the
plots of temperatures of the conductor, conduit, and opening for
the conduit filled with helium, that at higher temperatures
approaching 871.degree. C., the temperatures of the conductor,
conduit, and opening do not begin to substantially equilibrate as
seen for the high emissivity example shown in FIG. 70. Also, higher
temperatures in the conductor and the conduit are needed for an
opening and face temperature of 871.degree. C. than as for the
example shown in FIG. 70. Thus, increasing an emissivity of the
conductor and the conduit may be advantageous in reducing operating
temperatures needed to produce a desired temperature in a coal
formation. Such reduced operating temperatures may allow for the
use of less expensive alloys for metallic conduits.
[0678] FIG. 73 illustrates temperatures of the conductor, the
conduit, and the opening versus a temperature at a face of the coal
formation for an air filled conduit and a low emissivity of 0.1.
The opening has a gas mixture equivalent to the second mixture
described above having a hydrogen mole fraction of 0.6. Opening
temperature 3216 was linearly increased from 93.degree. C. to
871.degree. C. Opening temperature 3216 was assumed to be the same
as the temperature at the face of the coal formation. Conductor
temperature 3212 and conduit temperature 3214 were calculated from
opening temperature 3216 using the dimensions of the conductor,
conduit, and opening, values of emissivities for the conductor,
conduit, and face, and thermal conductivities for gases (air,
methane, carbon dioxide, and hydrogen). It may be seen from the
plots of temperatures of the conductor, conduit, and opening for
the conduit filled with helium, that at higher temperatures
approaching 871.degree. C., the temperatures of the conductor,
conduit, and opening do not begin to substantially equilibrate as
seen for the high emissivity example shown in FIG. 71. Also, higher
temperatures in the conductor and the conduit are needed for an
opening and face temperature of 871.degree. C. than as for the
example shown in FIG. 71. Thus, increasing an emissivity of the
conductor and the conduit may be advantageous in reducing operating
temperatures needed to produce a desired temperature in a coal
formation. Such reduced operating temperatures may provide for a
lesser metallurgical cost associated with materials that require
less substantial temperature resistance (e.g., a lower melting
point).
[0679] Calculations were also made using the first mixture of gas
having a hydrogen mole fraction of 0.2. The calculations resulted
in substantially similar results to those for a hydrogen mole
fraction of 0.6.
[0680] A series of experiments was conducted to determine the
effects of various properties of coal formations on properties of
fluids produced from such coal formations. The fluids may be
produced according to any of the embodiments as described herein.
The series of experiments included organic petrography,
proximate/ultimate analyses, Rock-Eval pyrolysis, Leco Total
Organic Carbon ("TOC"), Fischer Assay, and pyrolysis-gas
chromatography. Such a combination of petrographic and chemical
techniques may provide a quick and inexpensive method for
determining physical and chemical properties of coal and for
providing a comprehensive understanding of the effect of
geochemical parameters on potential oil and gas production from
coal pyrolysis. The series of experiments were conducted on
forty-five cubes of coals to determine source rock properties of
each coal and to assess potential oil and gas production from each
coal.
[0681] Organic petrology is the study, mostly under the microscope,
of the organic constituents of coal and other rocks. The
petrography of coal is important since it affects the physical and
chemical nature of the coal. The ultimate analysis refers to a
series of defined methods that are used to determine the carbon,
hydrogen, sulfur, nitrogen, ash, oxygen, and the heating value of a
coal. Proximate analysis is the measurement of the moisture, ash,
volatile matter, and fixed carbon content of a coal.
[0682] Rock-Eval pyrolysis is a petroleum exploration tool
developed to assess the generative potential and thermal maturity
of prospective source rocks. A ground sample may be pyrolyzed in a
helium atmosphere. For example, the sample may be initially heated
and held at a temperature of 300.degree. C. for 5 minutes. The
sample may be further heated at a rate of 25.degree. C./min to a
final temperature of 600.degree. C. The final temperature may be
maintained for 1 minute. The products of pyrolysis may be oxidized
in a separate chamber at 580.degree. C. to determined the total
organic carbon content. All components generated may be split into
two streams passing through a flame ionization detector, which may
measure hydrocarbon and a thermal conductivity detector, which may
measure CO.sub.2.
[0683] Leco Total Organic Carbon ("TOC") involves combustion of
coal. For example, a small sample (about 1 gram) is heated to
1500.degree. C. in a high-frequency electrical field under an
oxygen atmosphere. Conversion of carbon to carbon dioxide is
measured volumetrically. Pyrolysis-gas chromatography may be used
for quantitative and qualitative analysis of pyrolysis gas.
[0684] Coals of different ranks and vitrinite reflectances were
treated in a laboratory to simulate an in situ conversion process.
The different coal samples were heated at a rate of about 2.degree.
C./day and at a pressure of 1 bar or 4.4 bars absolute. FIG. 77
shows weight percents of paraffins plotted against vitrinite
reflectance. As shown in FIG. 77 weight percent of paraffins in the
produced oil increases at vitrinite reflectances of the coal below
about 0.9%. In addition, a weight percent of paraffins in the
produced oil approaches maximum at a vitrinite reflectance of about
0.9%. FIG. 78 depicts weight percent of in the produced oil plotted
versus vitrinite reflectance. As shown in FIG. 78 a weight percent
of cycloalkanes in the oil produced increased as vitrinite
reflectance increased. Weight percentages of a sum of paraffins and
cycloalkanes is plotted versus vitrinite reflectance in FIG. 79. In
some embodiments, an in situ conversion process may be utilized to
produce phenol. Phenol generation may increase when a fluid
pressure within the formation is maintained at a lower pressure.
Phenol weight percent in the produced oil is depicted in FIG. 80. A
weight percent of phenol in the produced oil decreases as the
vitrinite reflectance increases. FIG. 81 illustrates a weight
percentage of aromatics in the hydrocarbon fluids plotted against
vitrinite reflectance. As shown in FIG. 81, a weight percent of
aromatics in the produced oil decreases below a vitrinite
reflectance of about 0.9%. A weight percent of aromatics in the
produced oil increases above a vitrinite reflectance of about 0.9%.
FIG. 82 depicts a ratio of paraffins to aromatics 3680 and a ratio
of aliphatics to aromatics 3682 plotted versus vitrinite
reflectance. Both ratios increase to a maximum at a vitrinite
reflectance between about 0.7% and about 0.9%. Above a vitrinite
reflectance of about 0.9%, both ratios decrease as vitrinite
reflectance increases.
[0685] FIG. 96 depicts the condensable hydrocarbon compositions,
and condensable hydrocarbon API gravities, that were produced when
various ranks of coal were treated as is described above for FIGS.
77-82. In FIG. 96, "SubC" means a rank of sub-bituminous C coal,
"SubB" means a rank of sub-bituminous B coal, "SubA" means a rank
of sub-bituminous A coal, "HVC" means a rank of high volatile
bituminous C coal, "HVB/A" means a rank of high volatile bituminous
coal at the border between B and A rank coal, "MV" means a rank
medium volatile bituminous coal, and "Ro" means vitrinite
reflectance. As can be seen in FIG. 96, certain ranks of coal will
produce different compositions when treated in certain embodiments
described herein. For instance, in many circumstances it may be
desirable to treat coal having a rank of HVB/A because such coal,
when treated, has the highest API gravity, the highest weight
percent of paraffins, and the highest weight percent of the sum of
paraffins and cycloalkanes.
[0686] Results were also displayed as a yield of products. FIGS.
83-86 illustrate the yields of components in terms of m.sup.3 of
product per kg of coal formation, when measured on a dry, ash free
basis. As illustrated in FIG. 83 the yield of paraffins increased
as the vitrinite reflectance of the coal increased. However, for
coals with a vitrinite reflectance greater than about 0.7-0.8% the
yield of paraffins fell off dramatically. In addition, a yield of
cycloalkanes followed similar trends as the paraffins, increasing
as the vitrinite reflectance of coal increased and decreasing for
coals with a vitrinite reflectance greater than about 0.7% or 0.8%
as illustrated in FIG. 84. FIG. 85 illustrates the increase of both
paraffins and cycloalkanes as the vitrinite reflectance of coal
increases to about 0.7% or 0.8%. As illustrated in FIG. 86 the
yield of phenols may be relatively low for coal containing material
with a vitrinite reflectance of less than about 0.3% and greater
than about 1.25%. Production of phenols may be desired due to the
value of phenol as a feedstock for chemical synthesis.
[0687] As demonstrated in FIG. 87, the API gravity appears to
increase significantly when the vitrinite reflectance is greater
than about 0.40%. In FIG. 88 the relationship between coal rank,
i.e., vitrinite reflectance, and a yield of condensable
hydrocarbons (in gallons per ton on a dry ash free basis) from a
coal formation. The yield in this experiment appears to be in an
optimal range when the coal has a vitrinite reflectance greater
than about 0.4% to less than about 1.3%.
[0688] FIG. 89 illustrates a plot of CO.sub.2 yield of coal having
various vitrinite reflectances. In FIGS. 89 and 90, CO.sub.2 yield
is set forth in weight percent on a dry ash free basis. As shown in
FIG. 89, at least some CO.sub.2 was released from all of the coal
samples. Such CO.sub.2 production may correspond to various
oxygenated functional groups present in the initial coal samples. A
yield of CO.sub.2 produced from low-rank coal samples was
significantly higher than a production from high-rank coal samples.
Low-rank coals may include lignite and sub-bituminous brown coals.
High-rank coals may include semi-anthracite and anthracite coal.
FIG. 90 illustrates a plot of CO.sub.2 yield from a portion of a
coal formation versus the atomic O/C ratio within a portion of a
coal formation. As O/C atomic ratio increases, a CO.sub.2 yield
increases.
[0689] A slow heating process may produce condensed hydrocarbon
fluids having API gravities in a range of 22 to 50, and average
molecular weights of about 150 g/gmol to about 250 g/gmol. These
properties may be compared to properties of condensed hydrocarbon
fluids produced by ex situ retorting of coal as reported in Great
Britain Published Patent Application No. GB 2,068,014 A, which is
incorporated by reference as if fully set forth herein. For
example, properties of condensed hydrocarbon fluids produced by an
ex situ retort process include API gravities of 1.9 to 7.9 produced
at temperature of 521.degree. C. and 427.degree. C.,
respectively.
[0690] Table 4 shows a comparison of gas compositions, in percent
volume, obtained from in situ gasification of coal using air
injection to heat the coal, in situ gasification of coal using
oxygen injection to heat the coal, and in situ gasification of coal
in a reducing atmosphere by thermal pyrolysis heating as described
in embodiments herein.
1 TABLE 4 Gasification Gasification Thermal Pyrolysis With Air With
Oxygen Heating H.sub.2 18.6% 35.5% 16.7% Methane 3.6% 6.9% 61.9%
Nitrogen and Argon 47.5% 0.0 0.0 Carbon Monoxide 16.5% 31.5% 0.9%
Carbon Dioxide 13.1% 25.0% 5.3% Ethane 0.6% 1.1% 15.2%
[0691] As shown in Table 4, gas produced according to an embodiment
described herein may be treated and sold through existing natural
gas systems. In contrast, gas produced by typical in situ
gasification processes may not be treated and sold through existing
natural gas systems. For example, a heating value of the gas
produced by gasification with air was 6000 KJ/m.sup.3, and a
heating value of gas produced by gasification with oxygen was
11,439 KJ/m. In contrast, a heating value of the gas produced by
thermal conductive heating was 39,159 KJ/m.sup.3.
[0692] Experiments were conducted to determine the difference
between treating relatively large solid blocks of coal versus
treating relatively small loosely packed particles of coal.
[0693] As illustrated in FIG. 91, coal 3700 in the shape of a cube
was heated to pyrolyze the coal. Heat was provided to cube 3700
from heat source 3704 inserted into the center of the cube and also
from heat sources 3702 located on the sides of the cube. The cube
was surrounded by insulation 3705. The temperature was raised
simultaneously using heat sources 3704, 3702 at a rate of about
2.degree. C./day at atmospheric pressure. Measurements from
temperature gauges 3706 were used to determine an average
temperature of cube 3700. Pressure in cube 3700 was monitored with
pressure gauge 3708. The fluids produced from the cube of coal were
collected and routed through conduit 3709. Temperature of the
product fluids was monitored with temperature gauge 3706 on conduit
3709. A pressure of the product fluids was monitored with pressure
gauge 3708 on conduit 3709. A hydrocarbon condensate was separated
from a non-condensable fluid in separator 3710. Pressure in
separator 3710 was monitored with pressure gauge 3708. A portion of
the non-condensable fluid was routed through conduit 3711 to gas
analyzers 3712 for characterization. Grab samples were taken from a
grab sample port 3714. Temperature of the non-condensable fluids
was monitored with temperature gauge 3706 on conduit 3711. A
pressure of the non-condensable fluids was monitored with pressure
gauge 3708 on conduit 3711. The remaining gas was routed through a
flow meter 3716, a carbon bed 3718, and vented to the atmosphere.
The produced hydrocarbon condensate was collected and analyzed to
determine the composition of the hydrocarbon condensate.
[0694] FIG. 75 illustrates a drum experimental apparatus. This
apparatus was used to test coal. Electrical heater 3404 and bead
heater 3402 were used to uniformly heat contents of drum 3400.
Insulation 3405 surrounds drum 3400. Contents of drum 3400 were
heated at a rate of about 2.degree. C./day at various pressures.
Measurements from temperature gauges 3406 were used to determine an
average temperature in drum 3400. Pressure in the drum was
monitored with pressure gauge 3408. Product fluids were removed
from drum 3400 through conduit 3409. Temperature of the product
fluids was monitored with temperature gauge 3406 on conduit 3409. A
pressure of the product fluids was monitored with pressure gauge
3408 on conduit 3409. Product fluids were separated in separator
3410. Separator 3410 separated product fluids into condensable and
non-condensable products. Pressure in separator 3410 was monitored
with pressure gauge 3408. Non-condensable product fluids were
removed through conduit 3411. A composition of a portion of
non-condensable product fluids removed from separator 3410 was
determined by gas analyzer 3412. A portion of condensable product
fluids were removed from separator 3410. Compositions of the
portion of condensable product fluids collected were determined by
external analysis methods. Temperature of the non-condensable
fluids was monitored with temperature gauge 3406 on conduit 3411. A
pressure of the non-condensable fluids was monitored with pressure
gauge 3408 on conduit 3411. Flow of non-condensable fluids from
separator 3410 was determined by flow meter 3416. Fluids measured
in flow meter 3416 were collected and neutralized in carbon bed
3418. Gas samples were collected in gas container 3414.
[0695] A large block of high volatile bituminous B Fruitland coal
was separated into two portions. One portion (about 550 kg) was
ground into small pieces and tested in a coal drum. The coal was
ground to an approximate diameter of about 6.34.times.10.sup.-4 m.
The results of such testing are depicted with the circles in FIGS.
93 and 95. One portion (a cube having sides measuring 0.3048 m) was
tested in a coal cube experiment. The results of such testing are
depicted with the squares in FIGS. 93 and 95.
[0696] FIG. 93 is a plot of gas phase compositions from experiments
on a coal cube and a coal drum for H.sub.2 3724, methane 3726,
ethane 3780, propane 3781, n-butane 3782, and other hydrocarbons
3783 as a function of temperature. As can be seen for FIG. 93, the
non condensable fluids produced from pyrolysis of the cube and the
drum had similar concentrations of the various hydrocarbons
generated within the coal. In FIG. 93 these results were so similar
that only one line was drawn for ethane 3780, propane 3781,
n-butane 3782, and other hydrocarbons 3783 for both the cube and
the drum results, and the two lines that were drawn for H.sub.2
(3724a and 3724b) and the two lines drawn for methane (3726a and
3726b) were in both instances very close to each other. Crushing
the coal did not have an apparent effect on the pyrolysis of the
coal. The peak in methane production 3726 occurred at about
450.degree. C. At higher temperatures methane cracks to hydrogen,
so the methane concentration decreases while the hydrogen content
3724 increases.
[0697] FIG. 94 illustrates a plot of cumulative production of gas
as a function of temperature from heating coal in the cube and coal
in the drum. Line 3790 represents gas production from coal in the
drum and line 3791 represents gas production from coal in the cube.
As demonstrated by FIG. 94, the production of gas in both
experiments yielded similar results, even though the particle sizes
were dramatically different between the two experiments.
[0698] FIG. 95 illustrates cumulative condensable hydrocarbons
produced in the cube and drum experiments. Line 3720 represents
cumulative condensable hydrocarbons production from the cube
experiment, and line 3722 represents cumulative condensable
hydrocarbons production from the drum experiment. As demonstrated
by FIG. 95, the production of condensable hydrocarbons in both
experiments yielded similar results, even though the particle sizes
were dramatically different between the two experiments. Production
of condensable hydrocarbons is substantially complete when the
temperature reached about 390.degree. C. In both experiments the
condensable hydrocarbons had an API gravity of about 37
degrees.
[0699] As shown in FIG. 93, methane started to be produced at
temperatures at or above about 270.degree. C. Since the experiments
were conduced at atmospheric pressure, it is believed that the
methane is produced from the pyrolysis, and not from mere
desorption. Between about 270.degree. C. and about 400.degree. C.,
condensable hydrocarbons, methane and H.sub.2 were produced as
shown in FIGS. 93, 94, and 95. FIG. 93 shows that above a
temperature of about 400.degree. C. methane and H.sub.2 continue to
be produced. Above about 450.degree. C., however, methane
concentration decreased in the produced gases whereas the produced
gases contained increased amounts of H.sub.2. If heating were
continued, eventually all H.sub.2 remaining in the coal would be
depleted, and production of gas from the coal would cease. FIGS.
93-95 indicate that the ratio of a yield of gas to a yield of
condensable hydrocarbons will increase as the temperature increases
above about 390.degree. C.
[0700] FIGS. 93-95 demonstrate that particle size did not
substantially affect the quality of condensable hydrocarbons
produced from the treated coal, the quantity of condensable
hydrocarbons produced from the treated coal, the amount of gas
produced from the treated coal, the composition of the gas produced
from the treated coal, the time required to produce the condensable
hydrocarbons and gas from the treated coal, or the temperatures
required to produce the condensable hydrocarbons and gas from the
treated coal. In essence a block of coal yielded substantially the
same results from treatment as small particles of coal. As such, it
is believed that scale-up issues when treating coal will not
substantially affect treatment results.
[0701] An experiment was conducted to determine an effect of
heating on thermal conductivity and thermal diffusivity of a
portion of a coal formation. Thermal pulse tests performed in situ
in a high volatile bituminous C coal at the field pilot site showed
a thermal conductivity between 2.0.times.10.sup.-3
-2.39.times.10.sup.-3 cal/cm sec .degree. C. (0.85 to 1.0
W/(m.degree. K)) at 20.degree. C. Ranges in these values were due
to different measurements between different wells. The thermal
diffusivity was 4.8.times.10.sup.-3 cm.sup.2/s at 20.degree. C.
(the range was from about 4.1.times.10.sup.-3 to about
5.7.times.10.sup.-3 cm.sup.2/s at 20.degree. C.). It is believed
that these measured values for thermal conductivity and thermal
diffisivity are substantially higher than would be expected based
on literature sources (e.g., about three times higher in many
instances).
[0702] An initial value for thermal conductivity from the in situ
experiment is plotted versus temperature in FIG. 97 (this initial
value is point 3743 in FIG. 97). Additional points for thermal
conductivity (i.e., all of the other values for line 3742 shown in
FIG. 97) were assessed by calculating thermal conductivities using
temperature measurements in all of the wells shown in FIG. 99,
total heat input from all heaters shown in FIG. 99, measured heat
capacity and density for the coal being treated, gas and liquids
production data (e.g., composition, quantity, etc.), etc. For
comparison, these assessed thermal conductivity values (see line
3742) were plotted with data reported in two papers from S.
Badzioch, et al. (1964) and R. E. Glass (1984) (see line 3740). As
illustrated in FIG. 97, the assessed thermal conductivities from
the in situ experiment were higher than reported values for thermal
conductivities. The difference may be at least partially accounted
for if it is assumed that the reported values do not take into
consideration the confined nature of the coal in an in situ
application. Because the reported values for thermal conductivity
of coal are relatively low, they discourage the use of in situ
heating for coal.
[0703] FIG. 97 illustrates a decrease in the assessed thermal
conductivity values 3742 at about 100.degree. C. It is believed
that this decrease in thermal conductivity was caused by water
vaporizing in the cracks and void spaces (water vapor has a lower
thermal conductivity than liquid water). At about 350.degree. C.,
the thermal conductivity began to increase, and it increased
substantially as the temperature increased to 700.degree. C. It is
believed that the increases in thermal conductivity were the result
of molecular changes in the carbon structure. As the carbon was
heated it became more graphitic which is illustrated in Table 5 by
an increased vitrinite reflectance after pyrolysis. As void spaces
increased due to fluid production, heat was increasingly
transferred by radiation and/or convection. In addition,
concentrations of hydrogen in the void spaces were raised due to
pyrolysis and generation of synthesis gas.
[0704] Three data points 3744 of thermal conductivities under high
stress were derived from laboratory tests on the same high volatile
bituminous C coal used for the in situ field pilot site (see FIG.
97). In the laboratory tests a sample of such coal was stressed
from all directions, and heated relatively quickly. These thermal
conductivities were determined at higher stress (i.e., 27.6 bars
absolute), as compared to the stress in the in situ field pilot
(which were about 3 bars absolute). Thermal conductivity values
3744 demonstrate that the application of stress increased the
thermal conductivity of the coal at temperatures of 150.degree. C.,
250.degree. C., and 350.degree. C. It is believed that higher
thermal conductivity values were obtained from stressed coal
because the stress closed at least some cracks/void spaces and/or
prevented new cracks/void spaces from forming.
[0705] Using the reported values for thermal conductivity and
thermal diffusivity of coal and a 12 m heat source spacing on an
equilateral triangle pattern, calculations show that a heating
period of about ten years would be needed to raise an average
temperature of coal to about 350.degree. C. Such a heating period
may not be economically viable. Using experimental values for
thermal conductivity and thermal diffusivity and the same 12 m heat
source spacing, calculations show that the heating period to reach
an average temperature of 350.degree. C. would be about 3 years.
The elimination of about 7 years of heating a formation will in
many instances significantly improve the economic viability of an
in situ conversion process for coal.
[0706] Molecular hydrogen has a relatively high thermal
conductivity (e.g., the thermal conductivity of molecular hydrogen
is about 6 times the thermal conductivity of nitrogen or air).
Therefore it is believed that as the amount of hydrogen in the
formation void spaces increases, the thermal conductivity of the
formation will also increase. The increases in thermal conductivity
due to the presence of hydrogen in the void spaces somewhat offsets
decreases in thermal conductivity caused by the void spaces
themselves. It is believed that increases in thermal conductivity
due to the presence of hydrogen will be larger for coal formations
as compared to other hydrocarbon containing formations since the
amount of void spaces created during pyrolysis will be larger (coal
has a higher hydrocarbon density, so pyrolysis creates more void
spaces in coal).
[0707] Hydrocarbon fluids were produced from a portion of a coal
formation by an in situ experiment conducted in a portion of a coal
formation. The coal was high volatile bituminous C coal. It was
heated with electrical heaters. FIG. 98 illustrates a
cross-sectional view of the in situ experimental field test system.
As shown in FIG. 98, the experimental field test system included at
least coal formation 3802 within the ground and grout wall 3800.
Coal formation 3802 dipped at an angle of approximately 36.degree.
with a thickness of approximately 4.9 meters. FIG. 99 illustrates a
location of heat sources 3804a, 3804b, 3804c, production wells
3806a, 3806b, and temperature observation wells 3803a, 3808b,
3808c, 3808d used for the experimental field test system. The three
heat sources were disposed in a triangular configuration.
Production well 3806a was located proximate a center of the heat
source pattern and equidistant from each of the heat sources. A
second production well 3806b was located outside the heat source
pattern and spaced equidistant from the two closest heat sources.
Grout wall 3800 was formed around the heat source pattern and the
production wells. The grout wall may include pillars 1-24. Grout
wall 3800 was configured to inhibit an influx of water into the
portion during the in situ experiment. In addition, grout wall 3800
was configured to substantially inhibit loss of generated
hydrocarbon fluids to an unheated portion of the formation.
[0708] Temperatures were measured at various times during the
experiment at each of four temperature observation wells 3808a,
3808b, 3808c, 3808d located within and outside of the heat source
pattern as illustrated in FIG. 99. The temperatures measured (in
degrees Celsius) at each of the temperature observation wells are
displayed in FIG. 100 as a function of time. Temperatures at
observation wells 3808a (3820), 3808b (3822), and 3808c (3824) were
relatively close to each other. A temperature at temperature
observation well 3808d (3826) was significantly colder. This
temperature observation well was located outside of the heater well
triangle illustrated in FIG. 99. This data demonstrates that in
zones where there was little superposition of heat temperatures
were significantly lower. FIG. 101 illustrated temperature profiles
measured at the heat sources 3804a (3830), 3804b (3832), and 3804c
(3834). The temperature profiles were relatively uniform at the
heat sources.
[0709] FIG. 102 illustrates a plot of cumulative volume (m.sup.3)
of liquid hydrocarbons produced 3840 as a function of time days).
FIG. 111 illustrates a plot of cumulative volume of gas produced
3910 in standard cubic feet, produced as a function of time (in
days) for the same in situ experiment. Both FIG. 102 and FIG. 111
show the results during the pyrolysis stage only of the in situ
experiment.
[0710] FIG. 103 illustrates the carbon number distribution of
condensable hydrocarbons that were produced using the low
temperature retorting process as described above. As can be seen in
FIG. 103, relatively high quality products were produced during
treatment. The results in FIG. 103 are consistent with the results
set forth in FIG. 108, which show results from heating coal from
the same formation in the laboratory for similar ranges of heating
rates as were used in situ.
[0711] Table 5 illustrates the results from analyzing coal before
and after it was treated (including heating the temperatures set
forth in as is set forth in FIG. 101 (i.e., after pyrolysis and
production of synthesis gas) as described above. The coal was cored
at about 11-11.3 meters from the surface, midway into the coal bed,
in both the "before treatment" and "after treatment" examples. Both
cores were taken at about the same location. Both cores were taken
at about 0.66 meters from well 3804c (between the grout wall and
well 3804c) in FIG. 99. In the following Table 5 "FA" means Fisher
Assay, "as rec'd" means the sample was tested as it was received
and without any further treatment, "Py-Water" means the water
produced during pyrolysis, "H/C Atomic Ratio" means the atomic
ratio of hydrogen to carbon, "daf" means "dry ash free," "dmmf"
means "dry mineral matter free," and "mmf" means "mineral matter
free." The specific gravity of the "after treatment" core sample
was approximately 0.85 whereas the specific gravity of the "before
treatment" core sample was approximately 1.35.
2TABLE 5 After Analysis Before Treatment Treatment % Vitrinite
Reflectance 0.54 5.16 FA (gal/ton, as-rec'd) 11.81 0.17 FA(wt %, as
rec'd) 6.10 0.61 FA Py-Water (gal/ton, as-rec'd) 10.54 2.22 H/C
Atomic Ratio 0.85 0.06 H (wt %, dat) 5.31 0.44 O (wt %, dat) 17.08
3.06 N (wt %, dat) 1.43 1.35 Ash (wt %, as rec'd) 32.72 56.50 Fixed
Carbon (wt %, dmmf) 54.45 94.43 Volatile Matter (wt %, dmmf) 45.55
5.57 Heating Value (Btu/lb, moist, mmf) 12048 14281
[0712] Even though the cores were taken outside the areas within
the triangle formed by the three heaters in FIG. 99, nevertheless
the cores demonstrate that the coal remaining in the formation
changed significantly during treatment. The vitrinite reflectance
results shown in Table 5 demonstrate that the rank of the coal
remaining in the formation changed substantially during treatment.
The coal was a high volatile bituminous C coal before treatment.
After treatment, however, the coal was essentially anthracite. The
Fischer Assay results shown in Table 5 demonstrate that most of the
hydrocarbons in the coal had been removed during treatment. The H/C
Atomic Ratio demonstrates that most of the hydrogen in the coal had
been removed during treatment. A significant amount of nitrogen and
ash was left in the formation.
[0713] In sum, the results shown in Table 5 demonstrate that a
significant amount of hydrocarbons and hydrogen were removed during
treatment of the coal by pyrolysis and generation of synthesis gas.
Significant amounts of undesirable products (ash and nitrogen)
remain in the formation, while the significant amounts of desirable
products (e.g., condensable hydrocarbons and gas) were removed.
[0714] FIG. 104 illustrates a plot of weight percent of a
hydrocarbon produced versus carbon number distribution for two
laboratory experiments on coal from the field experiment site. The
coal was high volatile bituminous C coal. As shown in FIG. 104, a
carbon number distribution of fluids produced from a formation
varied depending on, for example, pressure. For example, first
pressure 3842 was about 1 bar absolute and second pressure 3844 was
about 8 bars absolute. The laboratory carbon number distribution
shown in FIG. 104 was similar to that produced in the field
experiment in FIG. 103 also at 1 bar absolute. As shown in FIG.
104, as pressure increased, a range of carbon numbers of the
hydrocarbon fluids decreased. An increase in products having carbon
numbers less than 20 was observed when operating at 8 bars
absolute. Increasing the pressure from 1 bar absolute to 8 bars
absolute also increased an API gravity of the condensed hydrocarbon
fluids. The API gravities of condensed hydrocarbon fluids produced
were approximately 23.1.degree. and approximately 31.3.degree.,
respectively. Such an increase in API gravity represents increased
production of more valuable products.
[0715] FIG. 105 illustrates a bar graph of fractions from a boiling
point separation of hydrocarbon liquids generated by a Fischer
assay and a boiling point separation of hydrocarbon liquids from
the coal cube experiment described herein (see, e.g., the system
shown in FIG. 91). The experiment was conducted at a much slower
heating rate (2 degrees Celsius per day) and the oil produced at a
lower final temperature than the Fischer Assay. FIG. 105 shows the
weight percent of various boiling point cuts of hydrocarbon liquids
produced from a Fruitland high volatile bituminous B coal.
Different boiling point cuts may represent different hydrocarbon
fluid compositions. The boiling point cuts illustrated include
naphtha 3860 (initial boiling point to 166.degree. C.), jet fuel
3862 (166.degree. C. to 249.degree. C.), diesel 3864 (249.degree.
C. to 370.degree. C.), and bottoms 3866 (boiling point greater than
370.degree. C.). The hydrocarbon liquids from the coal cube were
substantially more valuable products. The API gravity of such
hydrocarbon liquids was significantly greater than the API gravity
of the Fischer Assay liquid. The hydrocarbon liquids from the coal
cube also included significantly less residual bottoms than were
produced from the Fischer Assay hydrocarbon liquids.
[0716] FIG. 106 illustrates a plot of percentage ethene, which is
an olefin, to ethane produced from a coal formation as a function
of heating rate. Data points were derived from laboratory
experimental data (see system shown in FIG. 74 and associated text)
for slow heating of high volatile bituminous C coal at atmospheric
pressure, and from Fischer assay results. As illustrated in FIG.
106, the ratio of ethene to ethane increased as the heating rate
increased. As such, it is believed that decreasing the heating rate
of coal will decrease production of olefins. The heating rate of a
formation may be determined in part by the spacings of heat sources
within the formation, and by the amount of heat that is transferred
from the heat sources to the formation.
[0717] Formation pressure may also have a significant effect on
olefin production. A high formation pressure may tend to result in
the production of small quantities of olefins. High pressure within
a formation may result in a high H.sub.2 partial pressure within
the formation. The high H.sub.2 partial pressure may result in
hydrogenation of the fluid within the formation. Hydrogenation may
result in a reduction of olefins in a fluid produced from the
formation. A high pressure and high H.sub.2 partial pressure may
also result in inhibition of aromatization of hydrocarbons within
the formation. Aromatization may include formation of aromatic and
cyclic compounds from alkanes and/or alkenes within a hydrocarbon
mixture. If it is desirable to increase production of olefins from
a formation, the olefin content of fluid produced from the
formation may be increased by reducing pressure within the
formation. The pressure may be reduced by drawing off a larger
quantity of formation fluid from a portion of the formation that is
being produced. The pressure may be reduced by drawing a vacuum on
the portion of the formation being produced.
[0718] The system depicted in FIG. 74, and the method of using such
system, was used to conduct experiments on high volatile bituminous
C coal when such coal was heated at 5.degree. C./day at atmospheric
pressure. FIG. 76 depicts certain data points from such experiment
(the line depicted in FIG. 76 was produced from a linear regression
analysis of such data points). FIG. 76 illustrates the ethene to
ethane molar ratio as a function of hydrogen molar concentration in
non-condensable hydrocarbons produced from the coal during the
experiment. The ethene to ethane ratio in the non-condensable
hydrocarbons is reflective of olefin content in all hydrocarbons
produced from the coal. As can be seen in FIG. 76, as the
concentration of hydrogen autogenously increased during pyrolysis,
the ratio of ethene to ethane decreased. It is believed that
increases in the concentration (and partial pressure) of hydrogen
during pyrolysis causes the olefin concentration to decrease in the
fluids produced from pyrolysis.
[0719] FIG. 107 illustrates product quality, as measured by API
gravity, as a function of rate of temperature increase of fluids
produced from high volatile bituminous "C" coal. Data points were
derived from Fischer assay data and from laboratory experiments.
For the Fischer assay data, the rate of temperature increase was
approximately 17,100.degree. C./day and the resulting API gravity
was less than 11.degree.. For the relatively slow laboratory
experiments, the rate of temperature increase ranged from about
2.degree. C./day to about 10.degree. C./day, and the resulting API
gravities ranged from about 23.degree. to about 26.degree.. A
substantially linear decrease in quality (decrease in API gravity)
was exhibited as the logarithmic heating rate increased.
[0720] FIG. 108 illustrates weight percentages of various carbon
numbers products removed from high volatile bituminous "C" coal
when coal is heated at various heating rates. Data points were
derived from laboratory experiments and a Fischer assay. Curves for
heating at a rate of 2.degree. C./day 3870, 3.degree. C./day 3872,
5.degree. C./day 3874, and 10.degree. C./day 3876 provided for
similar carbon number distributions in the produced fluids. A coal
sample was also heated in a Fisher assay test at a rate of about
17,100.degree. C./day. The data from the Fischer assay test is
indicated by reference numeral 3878. Slow heating rates resulted in
less production of components having carbon numbers greater than 20
as compared to the Fischer assay results 3878. Lower heating rates
also produced higher weight percentages of components with carbon
numbers less than 20. The lower heating rates produced large
amounts of components having carbon numbers near 12. A peak in
carbon number distribution near 12 is typical of the in situ
conversion process for coal.
[0721] An experiment was conducted on the coal formation treated
according to the in situ conversion process to measure the uniform
permeability of the formation after pyrolysis. After heating a
portion of the coal formation, a ten minute pulse of CO.sub.2 was
injected into the formation at first production well 3806a and
produced at well 3804a, as shown in FIG. 99. The CO.sub.2 tracer
test was repeated from production well 3806a to well 3804b and from
production well 3806a to well 3804c. As described above, each of
the three different heat sources were located equidistant from the
production well. The CO.sub.2 was injected at a rate of 4.08
m.sup.3/hr (144 standard cubic feet per hour). As illustrated in
FIG. 109, the CO.sub.2 reached each of the three different heat
sources at approximately the same time. Line 3900 illustrates
production of CO.sub.2 at heat source 3804a, line 3902 illustrates
production of CO.sub.2 at heat source 3804b, and line 3904
illustrates production of CO.sub.2 at heat source 3804c. As shown
in FIG. 111, yield of CO.sub.2 from each of the three different
wells was also approximately equal over time. Such approximately
equivalent transfer of a tracer pulse of CO.sub.2 through the
formation and yield of CO.sub.2 from the formation indicated that
the formation was substantially uniformly permeable. The fact that
the first CO.sub.2 arrival only occurs approximately 18 minutes
after start of the CO.sub.2 pulse indicates that no preferential
paths had been created between well 3806a and 3804a, 3804b, and
3804c.
[0722] The in situ permeability was measured by injecting a gas
between different wells after the pyrolysis and synthesis gas
formation stages were complete. The measured permeability varied
from about 4.5 darcy to 39 darcy (with an average of about 20
darcy), thereby indicating that the permeability was high and
relatively uniform. The before-treatment permeability was only
about 50 millidarcy.
[0723] Synthesis gas was also produced in an in situ experiment
from the portion of the coal containing formation shown in FIG. 98
and FIG. 99. In this experiment, heater wells were also configured
to inject fluids. FIG. 110 is a plot of weight of produced
volatiles (oil and noncondensable gas) in kilograms as a function
of cumulative energy input in kilowatt hours with regard to the in
situ experimental field test. The figure illustrates the quantity
of pyrolysis fluids and synthesis gas produced from the
formation.
[0724] FIG. 112 is a plot of the volume of oil equivalent produced
(m.sup.3) as a function of energy input into the coal formation
(kW.multidot.hr) from the experimental field test. The volume of
oil equivalent in cubic meters was determined by converting the
energy content of the volume of produced oil plus gas to a volume
of oil with the same energy content.
[0725] The start of synthesis gas production, indicated by arrow
3912, was at an energy input of approximately 77,000
kW.multidot.hr. The average coal temperature in the pyrolysis
region had been raised to 620.degree. C. Because the average slope
of the curve in FIG. 112 in the pyrolysis region is greater than
the average slope of the curve in the synthesis gas region, FIG.
112 illustrates that the amount of useable energy contained in the
produced synthesis gas is less than that contained in the pyrolysis
fluids. Therefore, synthesis gas production is less energy
efficient than pyrolysis. There are two reasons for this result.
First, the two H.sub.2 molecules produced in the synthesis gas
reaction have a lower energy content than low carbon number
hydrocarbons produced in pyrolysis. Second, the endothermic
synthesis gas reaction consumes energy.
[0726] FIG. 113 is a plot of the total synthesis gas production
(m.sup.3/min) from the coal formation versus the total water inflow
(kg/hr) due to injection into the formation from the experimental
field test results facility. Synthesis gas may be generated in a
formation at a synthesis gas generating temperature before the
injection of water or steam due to the presence of natural water
inflow into hot coal formation. Natural water may come from below
the formation.
[0727] From FIG. 113, the maximum natural water inflow is
approximately 5 kg/h as indicated by arrow 3920. Arrows 3922, 3924,
and 3926 represent injected water rates of about 2.7 kg/hr, 5.4
kg/hr, and 11 kg/hr, respectively, into central well 3806a.
Production of synthesis gas is at heater wells 3804a, 3804b, and
3804c. FIG. 113 shows that the synthesis gas production per unit
volume of water injected decreases at arrow 3922 at approximately
2.7 kg/h of injected water or 7.7 kg/hr of total water inflow. The
reason for the decrease is that steam is flowing too fast through
the coal seam to allow the reactions to approach equilibrium
conditions.
[0728] FIG. 114 illustrates production rate of synthesis gas
(m.sup.3/min) as a function of steam injection rate (kg/h) in a
coal formation. Data 3930 for a first run corresponds to injection
at producer well 3806a in FIG. 99, and production of synthesis gas
at heater wells 3804a, 3804b, and 3804c. Data 3932 for a second run
corresponds to injection of steam at heater well 3804c, and
production of additional gas at a production well 3806a. Data 3930
for the first run corresponds to the data shown in FIG. 113. As
shown in FIG. 114, the injected water is in reaction equilibrium
with the formation to about 2.7 kg/hr of injected water. The second
run results in substantially the same amount of additional
synthesis gas produced, shown by data 3932, as the first run to
about 1.2 kg/hr of injected steam. At about 1.2 kg/hr, data 3930
starts to deviate from equilibrium conditions because the residence
time is insufficient for the additional water to react with the
coal. As temperature is increased, a greater amount of additional
synthesis gas is produced for a given injected water rate. The
reason is that at higher temperatures the reaction rate and
conversion of water into synthesis gas increases.
[0729] FIG. 115 is a plot that illustrates the effect of methane
injection into a heated coal formation in the experimental field
test (all of the units in FIGS. 115-118 are in m.sup.3 per hour).
FIG. 115 demonstrates hydrocarbons added to the synthesis gas
producing fluid are cracked within the formation. FIG. 99
illustrates the layout of the heater and production wells at the
field test facility. Methane was injected into production wells
3806a and 3806b and fluid was produced from heater wells 3804a,
3804b, and 3804c. The average temperatures measured at various
wells were as follows: 3804a (746.degree. C.), 3804b (746.degree.
C.), 3804c (767.degree. C.), 3808a (592.degree. C.), 3808b
(573.degree. C.), 3808c (606.degree. C.), and 3806a (769.degree.
C.). When the methane contacted the formation, it cracked within
the formation to produce H.sub.2 and coke. FIG. 115 shows that as
the methane injection rate increased, the production of H.sub.2
3940 increased. This indicated that methane was cracking to form
H.sub.2. Methane production 3942 also increased which indicates
that not all of the injected methane is cracked. The measured
compositions of ethane, ethene, propane, and butane were
negligible.
[0730] FIG. 116 is a plot that illustrates the effect of ethane
injection into a heated coal formation in the experimental field
test. Ethane was injected into production wells 3806a and 3806b and
fluid was produced from heater wells 3804a, 3804b, and 3804c. The
average temperatures measured at various wells were as follows:
3804a (742.degree. C.), 3804b (750.degree. C.), 3804c (744.degree.
C.), 3808a (611.degree. C.), 3808b (595.degree. C.), 3808c
(626.degree. C.), and 3806a (818.degree. C.). When ethane contacted
the formation, it cracked to produce H.sub.2, methane, ethene, and
coke. FIG. 116 shows that as the ethane injection rate increased,
the production of H.sub.2 3950, methane 3952, ethane 3954, and
ethene 3956 increased. This indicates that ethane is cracking to
form H.sub.2 and low molecular weight hydrocarbons. The production
rate of higher carbon number products (i.e., propane and propylene)
were unaffected by the injection of ethane.
[0731] FIG. 117 is a plot that illustrates the effect of propane
injection into a heated coal formation in the experimental field
test. Propane was injected into production wells 3806a and 3806b
and fluid was produced from heater wells 3804a, 3804b, and 3804c.
The average temperatures measured at various wells were as follows:
3804a (737.degree. C.), 3804b (753.degree. C.), 3804c (726.degree.
C.), 3808a (589.degree. C.), 3808b (573.degree. C.), 3808c
(606.degree. C.), and 3806a (769.degree. C.). When propane
contacted the formation, it cracked to produce H.sub.2 methane,
ethane, ethene, propylene and coke. FIG. 117 shows that as the
propane injection rate increased, the production of H.sub.2 3960,
methane 3962, ethane 3964, ethene 3966, propane 3968, and propylene
3969 increased. This indicates that propane is cracking to form
H.sub.2 and lower molecular weight components.
[0732] FIG. 118 is a plot that illustrates the effect of butane
injection into a heated coal formation in the experimental field
test. Butane was injected into production wells 3806a and 3806b and
fluid was produced from heater wells 3804a, 3804b, and 3804c. The
average temperature measured at various wells were as follows:
3804a (772.degree. C.), 3804b (764.degree. C.), 3804c (753.degree.
C.), 3808a (650.degree. C.), 3808b (591.degree. C.), 3808c
(624.degree. C.), and 3806a (830.degree. C.). When butane contacted
the formation, it cracked to produce H.sub.2 methane, ethane,
ethene, propane, propylene, and coke. FIG. 118 shows that as the
butane injection rate increased, the production of H.sub.2 3970,
methane 3972, ethane 3974, ethene 3976, propane 3978, and propylene
3979 increased. This indicates that butane is cracking to form
H.sub.2 and lower molecular weight components.
[0733] FIG. 119 is a plot of the composition of gas (in volume
percent) produced from the heated coal formation versus time in
days at the experimental field test. The species compositions
included 3980--methane, 3982--H.sub.2, 3984--carbon dioxide,
3986--hydrogen sulfide, and 3988--carbon monoxide. FIG. 119 shows a
dramatic increase in the H.sub.2 3982 concentration after about 150
days, or when synthesis gas production began.
[0734] FIG. 120 is a plot of synthesis gas conversion versus time
for synthesis gas generation runs in the experimental field test
performed on separate days. The temperature of the formation was
about 600.degree. C. The data demonstrates initial uncertainty in
measurements in the oil/water separator. Synthesis gas conversion
consistently approached a conversion of between about 40% and 50%
after about 2 hours of synthesis gas producing fluid injection. 10
Table 6 includes a composition of synthesis gas producing during a
run of the in situ coal field experiment.
3 TABLE 6 Component Mol % Wt % Methane 12.263 12.197 Ethane 0.281
0.525 Ethene 0.184 0.320 Acetylene 0.000 0.000 Propane 0.017 0.046
Propylene 0.026 0.067 Propadiene 0.001 0.004 Isobutane 0.001 0.004
n-Butane 0.000 0.001 1-Butene 0.001 0.003 Isobutene 0.000 0.000
cis-2-Butene 0.005 0.018 trans-2-Butene 0.001 0.003 1,3-Butadiene
0.001 0.005 Isopentane 0.001 0.002 n-Pentane 0.000 0.002 Pentene-1
0.000 0.000 T-2-Pentene 0.000 0.000 2-Methyl-2-Butene 0.000 0.000
C-2-Pentene 0.000 0.000 Hexanes 0.081 0.433 H.sub.2 51.247 6.405
Carbon monoxide 11.556 20.067 Carbon dioxide 17.520 47.799 Nitrogen
5.782 10.041 Oxygen 0.955 1.895 Hydrogen sulfide 0.077 0.163 Total
100.000 100.000
[0735] The experiment was performed in batch oxidation mode at
about 620.degree. C. The presence of nitrogen and oxygen is due to
contamination of the sample with air. The mole percent of H.sub.2,
carbon monoxide, and carbon dioxide, neglecting the composition of
all other species, may be determined for the above data. For
example, mole percent of H.sub.2, carbon monoxide, and carbon
dioxide may be increased proportionally such that the mole
percentages of the three components equals approximately 100%. In
this manner, the mole percent of H.sub.2, carbon monoxide, and
carbon dioxide, neglecting the composition of all other species,
were 63.8%, 14.4%, and 21.8%, respectively. The methane is believed
to come primarily from the pyrolysis region outside the triangle of
heaters. These values are in substantial agreement with the results
of equilibrium calculations shown in FIG. 121.
[0736] FIG. 121 is a plot of calculated equilibrium gas dry mole
fractions for a coal reaction with water. Methane reactions are not
included for FIGS. 121-122. The fractions are representative of a
synthesis gas that has been produced from a coal formation and has
been passed through a condenser to remove water from the produced
gas. Equilibrium gas dry mole fractions are shown in FIG. 121 for
H.sub.2 4000, carbon monoxide 4002, and carbon dioxide 4004 as a
function of temperature at a pressure of 2 bar absolute. As shown
in FIG. 121, at 390.degree. C., liquid production tends to cease,
and production of gases tends to commence. The gases produced at
this temperature include about 67% H.sub.2, and about 33% carbon
dioxide. Carbon monoxide is present in negligible quantities below
about 410.degree. C. At temperatures of about 500.degree. C.,
however, carbon monoxide is present in the produced gas in
measurable quantities. For example, at 500.degree. C., about 66.5%
H.sub.2, about 32% carbon dioxide, and about 2.5% carbon monoxide
are present. At 700.degree. C., the produced gas includes about
57.5% H.sub.2, about 15.5% carbon dioxide, and about 27% carbon
monoxide.
[0737] FIG. 122 is a plot of calculated equilibrium wet mole
fractions for a coal reaction with water. Equilibrium wet mole
fractions are shown for water 4006, H.sub.2 4008, carbon monoxide
4010, and carbon dioxide 4012 as a function of temperature at a
pressure of 2 bar absolute. At 390.degree. C., the produced gas
includes about 89% water, about 7% H.sub.2, and about 4% carbon
dioxide. At 500.degree. C., the produced gas includes about 66%
water, about 22% H.sub.2, about 11% carbon dioxide, and about 1%
carbon monoxide. At 700.degree. C., the produced gas include about
percent 18% water, about 47.5% H.sub.2 about 12% carbon dioxide,
and about 22.5% carbon monoxide.
[0738] FIG. 121 and FIG. 122 illustrate that at the lower end of
the temperature range at which synthesis gas may be produced (i.e.,
about 400.degree. C.) equilibrium gas phase fractions may not favor
production of H.sub.2 within a formation. As temperature increases,
the equilibrium gas phase fractions increasingly favor the
production of H.sub.2. For example, as shown in FIG. 122, the gas
phase equilibrium wet mole fraction of H.sub.2 increases from about
9% at 400.degree. C. to about 39% at 610.degree. C. and reaches 50%
at about 800.degree. C. FIG. 121 and FIG. 122 further illustrate
that at temperatures greater than about 660.degree. C., equilibrium
gas phase fractions tend to favor production of carbon monoxide
over carbon dioxide.
[0739] FIG. 121 and FIG. 122 illustrate that as the temperature
increases from between about 400.degree. C. to about 1000.degree.
C., the H.sub.2 to carbon monoxide ratio of produced synthesis gas
may continuously decrease throughout this range. For example, as
shown in FIG. 122, the equilibrium gas phase H.sub.2 to carbon
monoxide ratio at 500.degree. C., 660.degree. C., and 1000.degree.
C. is about 22:1, about 3:1, and about 1:1, respectively. FIG. 122
also indicates that produced synthesis gas at lower temperatures
may have a larger quantity of water and carbon dioxide than at
higher temperatures. As the temperature increases, the overall
percentage of carbon monoxide and hydrogen within the synthesis gas
may increase.
[0740] FIG. 123 is a flowchart of an example of a pyrolysis stage
4020 and synthesis gas production stage 4022 with heat and mass
balances in high volatile type A or B bituminous coal. In the
pyrolysis stage 4020, heat 4024 is supplied to the coal formation
4026. Liquid and gas products 4028 and water 4030 exit the
formation 4026. The portion of the formation subjected to pyrolysis
is composed substantially of char after undergoing pyrolysis
heating. Char refers to a solid carbonaceous residue that results
from pyrolysis of organic material. In the synthesis gas production
stage 4022, steam 4032 and heat 4034 are supplied to formation 4036
that has undergone pyrolysis and synthesis gas 4038 is
produced.
[0741] In the embodiments in FIGS. 124-126 the methane reactions in
Equations (4) and (5) are included. The calculations set forth
herein assume that char is only made of carbon and that there is an
excess of carbon to steam. About 890 MWe of energy 4024 is required
to pyrolyze about 105,800 metric tons per day of coal. The
pyrolysis products 4028 include liquids and gases with a production
of 23,000 cubic meters per day. The pyrolysis process also produces
about 7,160 metric tons per day of water 4030. In the synthesis gas
stage about 57,800 metric tons per day of char with injection of
23,000 metric tons per day of steam 4032 and 2,000 MWe of energy
4034 with a 20% conversion will produce 12,700 cubic meters
equivalent oil per day of synthesis gas 4038.
[0742] FIG. 124 is an example of a low temperature in situ
synthesis gas production that occurs at a temperature of about
450.degree. C. with heat and mass balances in a coal formation that
was previously pyrolyzed. A total of about 42,900 metric tons per
day of water is injected into formation 4100 which may be char.
FIG. 124 illustrates that a portion of water 4102 at 25.degree. C.
is injected directly into the formation 4100. A portion of water
4102 is converted into steam 4104 at a temperature of about
130.degree. C. and a pressure at about 3 bar absolute using about
1227 MWe of energy 4106 and injected into formation 4100. A portion
of the remaining steam may be converted into steam 4108 at a
temperature of about 450.degree. C. and a pressure at about 3 bar
absolute using about 318 MWe of energy 4110. The synthesis gas
production involves about 23% conversion of 13,137 metric tons per
day of char to produce 56.6 millions of cubic meters per day of
synthesis gas with an energy content of 5,230 MW. About 238 MW of
energy 4112 is supplied to formation 4100 to account for the
endothermic heat of reaction of the synthesis gas reaction. The
product stream 4114 of the synthesis gas reaction includes 29,470
metric tons per day of water at 46 volume percent, 501 metric tons
per day carbon monoxide at 0.7 volume percent, 540 tons per day
H.sub.2 at 10.7 volume percent, 26,455 metric tons per day carbon
dioxide at 23.8 volume percent, and 7,610 metric tons per day
methane at 18.8 volume percent.
[0743] FIG. 125 is an example of a high temperature in situ
synthesis gas production that occurs at a temperature of about
650.degree. C. with heat and mass balances in a coal formation that
was previously pyrolyzed. A total of about 34,352 metric tons per
day of water is injected into formation 4200. FIG. 125 illustrates
that a portion of water 4202 at 25.degree. C. is injected directly
into formation 4200. A portion of water 4202 is converted into
steam 4204 at a temperature of about 130.degree. C. and a pressure
at about 3 bar absolute using about 982 MWe of energy 4206, and
injected into formation 4200. A portion of the remaining steam is
converted into steam 4208 at a temperature of about 650.degree. C.
and a pressure at about 3 bar absolute using about 413 MWe of
energy 4210. The synthesis gas production involves about 22%
conversion of 12,771 metric tons per day of char to produce 56.6
millions of cubic meters per day of synthesis gas with an energy
content of 5,699 MW. About 898 MW of energy 4212 is supplied to
formation 4200 to account for the endothermic heat of reaction of
the synthesis gas reaction. The product stream 4214 of the
synthesis gas reaction includes 10,413 metric tons per day of water
at 22.8 volume percent, 9,988 metric tons per day carbon monoxide
at 14.1 volume percent, 1771 metric tons per day H.sub.2 at 35
volume percent, 21,410 metric tons per day carbon dioxide at 19.3
volume percent, and 3535 metric tons per day methane at 8.7 volume
percent.
[0744] FIG. 126 is an example of an in situ synthesis gas
production in a coal formation with heat and mass balances.
Synthesis gas generating fluid that includes water 4302 is supplied
to the formation 4300. A total of about 22,000 metric tons per day
of water is required for a low temperature process and about 24,000
metric tons per day is required for a high temperature process. A
portion of the water may be introduced into the formation as steam.
Steam 4304 is produced by supplying heat to the water from an
external source. About 7,119 metric tons per day of steam is
provided for the low temperature process and about 6913 metric tons
per day of steam is provided for the high temperature process.
[0745] At least a portion of the aqueous fluid 4306 exiting
formation 4300 is recycled 4308 back into the formation for
generation of synthesis gas. For a low temperature process about
21,000 metric tons per day of aqueous fluids is recycled and for a
high temperature process about 10,000 metric tons per day of
aqueous fluids is recycled. The produced synthesis gas 4310
includes carbon monoxide, H.sub.2 and methane. The produced
synthesis gas has a heat content of about 430,000 MMBtu per day for
a low temperature process and a heat content of about 470,000 MMBtu
per day for a low temperature process. Carbon dioxide 4312 produced
in the synthesis gas process includes about 26,500 metric tons per
day in the low temperature process and about 21,500 metric tons per
day in the high temperature process. At least a portion of the
produced synthesis gas 4310 is used for combustion to heat the
formation. There is about 7,119 metric tons per day of carbon
dioxide in the steam 4308 for the low temperature process and about
6,913 metric tons per day of carbon dioxide in the steam for the
high temperature process. There is about 2,551 metric tons per day
of carbon dioxide in a heat reservoir for the low temperature
process and about 9,628 metric tons per day of carbon dioxide in a
heat reservoir for the high temperature process. There is about
14,571 metric tons per day of carbon dioxide in the combustion of
synthesis gas for the low temperature process and about 18,503
metric tons per day of carbon dioxide in produced combustion
synthesis gas for the high temperature process. The produced carbon
dioxide has a heat content of about 60 gigajoules ("GJ") per metric
ton for the low temperature process and about 6.3 GJ per metric ton
for the high temperature process.
[0746] Table 7 is an overview of the potential production volume of
applications of synthesis gas produced by wet oxidation. The
estimates are based on 56.6 million standard cubic meters of
synthesis gas produced per day at 700.degree. C.
4 TABLE 7 Production (main Appliction product) Power 2,720
Megawatts Hydrogen 2,700 metric tons/day NH.sub.3 13,800 metric
tons/day CH.sub.4 7,600 metric tons/day Methanol 13,300 metric
tons/day Shell Middle 5,300 metric tons/day Distillates
[0747] Experimental adsorption data has demonstrated that carbon
dioxide may be stored in coal that has been pyrolyzed. FIG. 127 is
a plot of the cumulative adsorbed methane and carbon dioxide in
cubic meters per metric ton versus pressure in bar absolute at
25.degree. C. on coal. The coal sample is sub-bituminous coal from
Gillette, Wyo. Data sets 4401, 4402, 4403, 4404, and 4405 are for
carbon dioxide adsorption on a post treatment coal sample that has
been pyrolyzed and has undergone synthesis gas generation. Data set
4406 is for adsorption on an unpyrolyzed coal sample from the same
formation. Data set 4401 is adsorption of methane at 25.degree. C.
Data sets 4402, 4403, 4404, and 4405 are adsorption of carbon
dioxide at 25.degree. C., 50.degree. C., 100.degree. C., and
150.degree. C., respectively. Data set 4406 is adsorption of carbon
dioxide at 25.degree. C. on the unpyrolyzed coal sample. FIG. 127
shows that carbon dioxide at temperatures between 25.degree. C. and
100.degree. C. is more strongly adsorbed than methane at 25.degree.
C. in the pyrolyzed coal. FIG. 127 demonstrates that a carbon
dioxide stream passed through post treatment coal tends to displace
methane from the post treatment coal.
[0748] Computer simulations have demonstrated that carbon dioxide
may be sequestered in both a deep coal formation and a post
treatment coal formation. The Comet2 Simulator determined the
amount of carbon dioxide that could be sequestered in a San Juan
Basin type deep coal formation and a post treatment coal formation.
The simulator also determined the amount of methane produced from
the San Juan Basin type deep coal formation due to the carbon
dioxide injection. The model employed for both the deep coal
formation and the post treatment coal formation was a 1.3 km.sup.2
area, with a repeating 5 spot well pattern. The 5 spot well pattern
included four injection wells arranged in a square and one
production well at the center of the square. The properties of the
San Juan Basin and the post treatment coal formations are shown in
Table 8. Additional details of simulations of carbon dioxide
sequestration in deep coal formations and comparisons with field
test results may be found in Pilot Test Demonstrates How Carbon
Dioxide Enhances Coal Bed Methane Recovery, Lanny Schoeling and
Michael McGovern, Petroleum Technology Digest, September 2000, p.
14-15.
5 TABLE 8 Post treatment coal Deep Coal formation Formation (San
(Post pyrolysis Juan Basin) process) Coal Thickness (in) 9 9 Coal
Depth (in) 990 460 Initial Pressure (bars abs.) 114 2 Initial
Temperature 25.degree. C. 25.degree. C. Permeability (md) 5.5
(horiz.), 10,000 (horiz.), 0 (vertical) 0 (vertical) Cleat porosity
0.2% 40%
[0749] The simulation model accounts for the matrix and dual
porosity nature of coal and post treatment coal. For example, coal
and post treatment coal are composed of matrix blocks. The spaces
between the blocks are called "cleats". Cleat porosity is a measure
of available space for flow of fluids in the formation. The
relative permeabilities of gases and water within the cleats
required for the simulation were derived from field data from the
San Juan coal. The same values for relative permeabilities were
used in the post treatment coal formation simulations. Carbon
dioxide and methane were assumed to have the same relative
permeability.
[0750] The cleat system of the deep coal formation was modeled as
initially saturated with water. Relative permeability data for
carbon dioxide and water demonstrate that high water saturation
inhibits absorption of carbon dioxide within cleats. Therefore,
water is removed from the formation before injecting carbon dioxide
into the formation.
[0751] In addition, the gases within the cleats may adsorb in the
coal matrix. The matrix porosity is a measure of the space
available for fluids to adsorb in the matrix. The matrix porosity
and surface area were taken into account with experimental mass
transfer and isotherm adsorption data for coal and post treatment
coal. Therefore, it is not necessary to specify a value of the
matrix porosity and surface area in the model.
[0752] The preferential adsorption of carbon dioxide over methane
on post treatment coal was incorporated into the model based on
experimental adsorption data. For example, FIG. 127 demonstrates
that carbon dioxide has a significantly higher cumulative
adsorption than methane over an entire range of pressures at a
specified temperature. Once the carbon dioxide enters in the cleat
system, methane diffuses out of and desorbs off the matrix.
Similarly, carbon dioxide diffuses into and adsorbs onto the
matrix. In addition, FIG. 127 also shows carbon dioxide may have a
higher cumulative adsorption on a pyrolyzed coal sample than an
unpyrolyzed coal.
[0753] The pressure-volume-temperature (PVT) properties and
viscosity required for the model were taken from literature data
for the pure component gases.
[0754] The simulation modeled a sequestration process over a time
period of about 3700 days for the deep coal formation model.
Removal of the water in the coal formation was simulated by
production from all five wells. The production rate of water was
about 40 m.sup.3/day for about the first 370 days. The production
rate of water decreased significantly after the first 370 days. It
continued to decrease through the remainder of the simulation run
to about zero at the end. Carbon dioxide injection was started at
approximately 370 days at a flow rate of about 113,000 standard (in
this context "standard" means 1 atmosphere pressure and 15.5
degrees Celsius) m.sup.3/day. The injection rate of carbon dioxide
was doubled to about 226,000 standard m.sup.3/day at approximately
1440 days. The injection rate remained at about 226,000 standard
m.sup.3/day until the end of the simulation run.
[0755] FIG. 130 illustrates the pressure at the wellhead of the
injection wells as a function of time during the simulation. The
pressure decreased from 114 bars absolute to about 20 bars absolute
over the first 370 days. The decrease in the pressure was due to
removal of water from the coal formation. Pressure then started to
increase substantially as carbon dioxide injection started at 370
days. The pressure reached a maximum of 98 bars. The pressure then
began to gradually decrease after 480 days. At about 1440 days, the
pressure increased again to about 143 bars absolute due to the
increase in the carbon dioxide injection rate. The pressure
gradually increased until about 3640 days. The pressure jumped at
about 3640 days because the production well was closed off.
[0756] FIG. 131 illustrates the production rate of carbon dioxide
5060 and methane 5070 as a function of time in the simulation. FIG.
131 shows that carbon dioxide was produced at a rate between about
0-10,000 m.sup.3/day during approximately the first 2400 days. The
production rate of carbon dioxide was significantly below the
injection rate. Therefore, the simulation predicts that most of the
injected carbon dioxide is being sequestered in the coal formation.
However, at about 2400 days, the production rate of carbon dioxide
started to rise significantly due to onset of saturation of the
coal formation.
[0757] In addition, FIG. 131 shows that methane was desorbing as
carbon dioxide was adsorbing in the coal formation. Between about
370-2400 days, the methane production rate 5070 increased from
about 60,000 to about 115,000 standard m.sup.3/day. The increase in
the methane production rate between about 1440-2400 days was caused
by the increase in carbon dioxide injection rate at about 1440
days. The production rate of methane started to decrease after
about 2400 days. This was due to the saturation of the coal
formation. The simulation predicted a 50% breakthrough at about
2700 days. "Breakthrough" is defined as the ratio of the flow rate
of carbon dioxide to the total flow rate of the total produced gas
times 100%. Also, the simulation predicted about a 90% breakthrough
at about 3600 days.
[0758] FIG. 132 illustrates cumulative methane produced 5090 and
the cumulative net carbon dioxide injected 5080 as a function of
time during the simulation. The cumulative net carbon dioxide
injected is the total carbon dioxide produced subtracted from the
total carbon dioxide injected. FIG. 132 shows that by the end of
the simulated injection about twice as much carbon dioxide was
stored than methane produced. In addition, the methane production
was about 0.24 billion standard m.sup.3 at 50% carbon dioxide
breakthrough. Also, the carbon dioxide sequestration was about 0.39
billion standard m.sup.3 at 50% carbon dioxide breakthrough. The
methane production was about 0.26 billion standard m.sup.3 at 90%
carbon dioxide breakthrough. Also, the carbon dioxide sequestration
was about 0.46 billion standard m.sup.3 at 90% carbon dioxide
breakthrough.
[0759] Table 8 shows that the permeability and porosity of the
simulation in the post treatment coal formation were both
significantly higher than in the deep coal formation prior to
treatment. Also, the initial pressure was much lower. The depth of
the post treatment coal formation was shallower than the deep coal
bed methane formation. The same relative permeability data and PVT
data used for the deep coal formation were used for the coal
formation simulation. The initial water saturation for the post
treatment coal formation was set at 70%. Water was present because
it is used to cool the hot spent coal formation to 25.degree. C.
The amount of methane initially stored in the post treatment coal
is very low.
[0760] The simulation modeled a sequestration process over a time
period of about 3800 days for the post treatment coal formation
model. The simulation modeled removal of water from the post
treatment coal formation with production from all five wells.
During about the first 200 days, the production rate of water was
about 680,000 standard m.sup.3/day. From about 200-3300 days the
water production rate was between about 210,000 to about 480,000
standard m.sup.3/day. Production rate of water was negligible after
about 3300 days. Carbon dioxide injection was started at
approximately 370 days at a flow rate of about 113,000 standard
m.sup.3/day. The injection rate of carbon dioxide was increased to
about 226,000 standard m.sup.3/day at approximately 1440 days. The
injection rate remained at 226,000 standard m.sup.3/day until the
end of the simulated injection.
[0761] FIG. 133 illustrates the pressure at the wellhead of the
injection wells as a function of time during the simulation of the
post treatment coal formation model. The pressure was relatively
constant up to about 370 days. The pressure increased through most
of the rest of the simulation run up to about 36 bars absolute. The
pressure rose steeply starting at about 3300 days because the
production well was closed off.
[0762] FIG. 134 illustrates the production rate of carbon dioxide
as a function of time in the simulation of the post treatment coal
formation model. FIG. 134 shows that the production rate of carbon
dioxide was almost negligible during approximately the first 2200
days. Therefore, the simulation predicts that nearly all of the
injected carbon dioxide is being sequestered in the post treatment
coal formation. However, at about 2240 days, the produced carbon
dioxide began to increase. The production rate of carbon dioxide
started to rise significantly due to onset of saturation of the
post treatment coal formation.
[0763] FIG. 135 illustrates cumulative net carbon dioxide injected
as a function of time during the simulation in the post treatment
coal formation model. The cumulative net carbon dioxide injected is
the total carbon dioxide produced subtracted from the total carbon
dioxide injected. FIG. 135 shows that the simulation predicts a
potential net sequestration of carbon dioxide of 0.56 Bm.sup.3.
This value is greater than the value of 0.46 Bm.sup.3 at 90% carbon
dioxide breakthrough in the deep coal formation. However,
comparison of FIG. 130 with FIG. 133 shows that sequestration
occurs at much lower pressures in the post treatment coal formation
model. Therefore, less compression energy was required for
sequestration in the post treatment coal formation.
[0764] The simulations show that large amounts of carbon dioxide
may be sequestered in both deep coal formations and in post
treatment coal formations that have been cooled.
[0765] Carbon dioxide may be sequestered in the post treatment coal
formation, in coal formations that have not been pyrolyzed, and/or
in both types of formations.
[0766] FIG. 128 is a flowchart of an embodiment of an in situ
synthesis gas production process integrated with a SMDS
Fischer-Tropsch and wax cracking process with heat and mass
balances. The synthesis gas generating fluid injected into the
formation includes about 24,000 metric tons per day of water 4530,
which includes about 5,500 metric tons per day of water 4540
recycled from the SMDS Fischer-Tropsch and wax cracking process
4520. A total of about 1700 MW of energy is supplied to the in situ
synthesis gas production process. About 1020 MW of energy 4535 of
the approximately 1700 MW of energy is supplied by in situ reaction
of an oxidizing fluid with the formation, and approximately 680 MW
of energy 4550 is supplied by the SMDS Fischer-Tropsch and wax
cracking process 4520 in the form of steam. About 12,700 cubic
meters equivalent oil per day of synthesis gas 4560 is used as feed
gas to the SMDS Fischer-Tropsch and wax cracking process 4520. The
SMDS Fischer-Tropsch and wax cracking process 4520 produces about
4,770 cubic meters per day of products 4570 that may include
naphtha, kerosene, diesel, and about 5,880 cubic meters equivalent
oil per day of off gas 4580 for a power generation facility.
[0767] FIG. 129 is a comparison between numerical simulation and
the in situ experimental coal field test composition of synthesis
gas produced as a function of time. The plot excludes nitrogen and
traces of oxygen that were contaminants during gas sampling.
Symbols represent experimental data and curves represent simulation
results. Hydrocarbons 4601 are methane since all other heavier
hydrocarbons have decomposed at the prevailing temperatures. The
simulation results are moving averages of raw results, which
exhibit peaks and troughs of approximately .+-.10 percent of the
averaged value. In the model, the peaks of H.sub.2 occurred when
fluids were injected into the coal seam, and coincided with lows in
CO.sub.2 and CO.
[0768] The simulation of H.sub.2 4604 provides a good fit to
observed fraction of H.sub.2 4603. The simulation of methane 4602
provides a good fit to observed fraction of methane 4601. The
simulation of carbon dioxide 4606 provides a good fit to observed
fraction of carbon dioxide 4605. The simulation of CO 4608
overestimated the fraction of CO 4607 by 4-5 percentage points.
Carbon monoxide is the most difficult of the synthesis gas
components to model. Also, the carbon monoxide discrepancy may be
due to fact that the pattern temperatures exceeded the 550.degree.
C., the upper limit at which the numerical model was
calibrated.
[0769] Other methods of producing synthesis gas were successfully
demonstrated at the experimental field test. These included
continuous injection of steam and air, steam and oxygen, water and
air, water and oxygen, steam, air and carbon dioxide. All these
injections successfully generated synthesis gas in the hot coke
formation.
[0770] Further modifications and alternative embodiments of various
aspects of the invention may be apparent to those skilled in the
art in view of this description. Accordingly, this description is
to be construed as illustrative only and is for the purpose of
teaching those skilled in the art the general manner of carrying
out the invention. It is to be understood that the forms of the
invention shown and described herein are to be taken as the
presently preferred embodiments. Elements and materials may be
substituted for those illustrated and described herein, parts and
processes may be reversed, and certain features of the invention
may be utilized independently, all as would be apparent to one
skilled in the art after having the benefit of this description of
the invention. Changes may be made in the elements described herein
without departing from the spirit and scope of the invention as
described in the following claims.
* * * * *