U.S. patent application number 09/875658 was filed with the patent office on 2001-11-29 for enhanced coalbed gas production system.
This patent application is currently assigned to The University of Wyoming Research Corporation, d/b/a Western Research Institute, The University of Wyoming Research Corporation, d/b/a Western Research Institute. Invention is credited to Mones, Charles G..
Application Number | 20010045291 09/875658 |
Document ID | / |
Family ID | 23324220 |
Filed Date | 2001-11-29 |
United States Patent
Application |
20010045291 |
Kind Code |
A1 |
Mones, Charles G. |
November 29, 2001 |
Enhanced coalbed gas production system
Abstract
A method of stimulating coalbed methane production by injecting
gas into a producer and subsequently placing the producer back on
production is described. A decrease in water production may also
result. The increase in gas production and decrease in water
production may result from: (1) the displacement of water from the
producer by gas; (2) the establishment of a mobile gas saturation
at an extended distance into the coalbed, extending outward from
the producer; and (3) the reduction in coalbed methane partial
pressure between the coal matrix and the coal's cleat system.
Inventors: |
Mones, Charles G.;
(Cheyenne, WY) |
Correspondence
Address: |
Santangelo Law Offices, P.C.
Third Floor
125 South Howes
Fort Collins
CO
80521
US
|
Assignee: |
The University of Wyoming Research
Corporation, d/b/a Western Research Institute
365 North 9th Street
Laramie
WY
82072
|
Family ID: |
23324220 |
Appl. No.: |
09/875658 |
Filed: |
June 6, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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09875658 |
Jun 6, 2001 |
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09338295 |
Jun 23, 1999 |
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6244338 |
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60090306 |
Jun 23, 1998 |
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Current U.S.
Class: |
166/400 ;
166/275 |
Current CPC
Class: |
E21B 43/006
20130101 |
Class at
Publication: |
166/400 ;
166/275 |
International
Class: |
E21B 043/16 |
Claims
1. An apparatus for coalbed gas production, comprising: a. a
coalbed; b. coalbed gas sorbed to coal in said coalbed; c. water
associated with at least a part of said coalbed; d. at least one
production well which communicates with said coalbed gas; e. a
coalbed stimulation gas; f. a stimulation gas transfer element; g.
a production well coupling element responsive to said stimulation
gas transfer element which delivers said stimulation gas to said
coalbed within the vicinity of said at least one production well;
h. a water displacement perimeter surrounding said at least one
production well; i. a stimulated coalbed gas reservoir; j. at least
one water confinement well communicating with said coalbed located
a distance from said at least one production well; k. at least one
water transfer element; l. at water confinement well coupling
element responsive to said water transfer element and to said at
least one water confinement well; m. coalbed gas desorbed into said
stimulated coalbed gas reservoir; n. at least one coalbed gas
removal element; o. at least one coalbed gas removal element
coupler responsive to said at least one coalbed gas removal element
and said production well; and p. at least coalbed gas removed from
said stimulated coalbed reservoir through said at least one
production well.
2. An apparatus for coalbed gas production as described in claim 1,
wherein said water associated with at least a part of said coalbed
has a hydrostatic pressure and wherein said coalbed stimulation gas
has a pressure greater than said hydrostatic pressure which
displaces said water.
3. An apparatus for coalbed gas production as described in claim 2,
wherein said coalbed stimulation gas has a water displacement
pressure not substantially larger than said hydrostatic
pressure.
4. An apparatus for coalbed gas production as described in claim 3,
wherein said at least one water confinement well removes at least a
portion of said displaced water encroaching upon said at least one
production well.
5. An apparatus for coalbed gas production as described in claim 4,
wherein said at least one water confinement well has a location on
about said water displacement perimeter surrounding said production
well.
6. An apparatus for coalbed gas production as described in claim 4,
wherein said at least one production well has a location at about a
centroid of an approximately 40 to 320 acre tract of land.
7. An apparatus for coalbed gas production as described in claim 6,
wherein said approximately 40 to 320 acre tract of land has a
substantially square perimeter.
8. An apparatus for coalbed gas production as described in claim 7,
wherein said approximately 40 to 320 acre tract of land having a
substantially square perimeter is adjacent to a another
approximately 40 to 320 acre tract of land having a substantially
square perimeter having a production well.
9. An apparatus for coalbed gas production as described in claim 6,
wherein said at least one water confinement well has a location at
the extent of said approximately 40 to 320 acre tract of land.
10. An apparatus for coalbed gas production as described in claim
4, wherein said at least one production well farther comprising a
drainage radius and said at least one confinement well has a
location at about a boundary of said drainage radius.
11. An apparatus for coalbed gas production as described in claim
4, wherein said stimulated coalbed gas reservoir has determined
characteristics used to calculate an appropriate amount of coalbed
stimulation gas to stimulate said coalbed gas reservoir having said
determined characteristics so as to produce coalbed as containing
less than four percent stimulation gas per unit volume under
stabilized coalbed gas removal conditions.
12. An apparatus for coalbed gas production as described in claim
4, wherein said coalbed stimulation gas is an amount appropriate to
stimulate said coalbed gas reservoir having said determined
characteristics so as to produce coalbed gas containing less than
ten percent stimulation gas per unit volume under stabilized
coalbed gas removal conditions.
13. An apparatus for coalbed gas production as described in claim
11, wherein said coalbed stimulation gas transfer element delivers
said coalbed stimulation gas to said coalbed in a vicinity of said
at least one production well for a duration of about eight to
thirty days.
14. An apparatus for coalbed gas production as described in claim
11, further comprising a calculated coalbed gas desorption rate at
which said coalbed gas desorbs from said coal and wherein said
coalbed gas removal element has an calculated average coalbed gas
removal rate which is never less than said calculated coalbed gas
desorption rate.
15. An apparatus for coalbed gas production as described in claim
14, further comprising at least one coalbed gas removal element
fluidically coupled to said at least one confinement well which
assists said at least one coalbed gas removal element to remove
coalbed gas at said calculated coalbed gas removal rate.
16. An apparatus for coalbed gas production as described in claim
15, wherein said coalbed stimulation gas has a pressure calculated
to avoid altering the structure of said coalbed and wherein said
stimulation gas pressure induces a reduced water permeability to
said stimulated coalbed gas reservoir.
17. An apparatus for coalbed gas production as described in claim
16, farther comprising a coalbed structure alteration element which
acts after a portion of said coalbed gas is removed from said
stimulated coalbed reservoir.
18. An apparatus for coalbed gas production as described in claims
1, 3, 4, 11, 14, 16, wherein said coalbed stimulation gas is
selected from a group consisting of nitrogen, carbon dioxide, air
or a gas less sorptive to coal than methane.
19. An apparatus for coalbed gas production as described in claim
18, wherein said coalbed has previously had coalbed gas removed
prior to delivery of said coalbed stimulation gas to said
coalbed.
20. A method of producing coalbed gas, which comprises the steps
of: a. locating a coalbed having, coalbed gas sorbed to coal; b.
establishing at least one production well communicating with said
coalbed; c. establishing at least one water confinement well
communicating with said coalbed at a distance from said at least
one production well; d. injecting a coalbed stimulation gas to said
coalbed through said production well; e. displacing water in said
coalbed surrounding said production well with said coalbed
stimulation gas; f. establishing a water displacement perimeter
surrounding said at least one production well; g. stimulating said
coalbed within said water displacement perimeter with said
stimulation gas; h. desorbing said coalbed gas sorbed to said
coalbed; and i. confining said water displaced from said coalbed
surrounding said at least one production well; and j. removing at
least said desorbed coalbed gas from said coalbed through said at
least one production well.
21. A method of producing coalbed gas as described in claim 20,
wherein said steps a to j occur in that order.
22. A method of producing coalbed gas as described in claim 21,
wherein said steps g, h, i and j occur about simultaneously.
23. A method of producing coalbed gas as described in claim 20,
wherein said step of displacing water in said coalbed surrounding
said production well with said coalbed stimulation gas comprises
using coalbed stimulation gas having a water displacement pressure
not substantially larger than said hydrostatic pressure
24. A method of producing coalbed gas as described in claim 23,
wherein said step of establishing said at least one water
confinement well communicating with said coalbed at a distance from
said at least one production well.
25. A method of producing coalbed gas as described in claim 23,
wherein said step of establishing said at least one water
confinement well communicating with said coalbed at a distance from
said at least one production well comprises locating said at least
one water confinement well at a boundary of a production well
drainage radius for said at least one production well.
26. A method of producing coalbed gas as described in claim 23,
wherein said step of establishing at least one production well
comprises locating said at least one production well at about a
centroid of an approximately 40 to 320 acre tract of land.
27. A method of producing coalbed gas as described in claim 25,
wherein said establishing said at least one production well at
about said centroid of said approximately 320 acres comprises
establishing a substantially square perimeter and establishing said
at least one water confinement wells at each corner of said
substantially square perimeter.
28. A method of producing coalbed gas as described in claim 24,
which further comprises the steps of: a. determining a
characteristic of said stimulated coalbed; and b. calculating an
appropriate amount of coalbed stimulation gas so as to produce
coalbed gas containing less than about four percent stimulation gas
per unit volume under stabilized coalbed gas removal
conditions.
29. A method of producing coalbed gas as described in claim 28,
wherein said step of calculating an appropriate amount of coalbed
stimulation gas comprises calculating said appropriate amount of
coalbed stimulation gas to produce coalbed gas with less than about
ten percent stimulation gas per unit volume under stabilized
coalbed gas removal conditions.
30. A method of producing coalbed gas as described in claim 28,
wherein said step of calculating an appropriate amount of coalbed
stimulation gas comprises calculating said appropriate amount of
coalbed stimulation gas to produce coalbed gas with less than about
ten percent stimulation gas per unit volume under stabilized
coalbed gas removal conditions.
31. A method of producing coalbed gas as described in claim 28,
farther comprising a calculated coalbed gas desorption rate at
which said coalbed gas desorbs from said coal and wherein said
coalbed gas removal element has a calculated average coalbed gas
removal rate which is never less than said calculated coalbed gas
desorption rate.
32. A method of producing coalbed gas as described in claim 31,
which further comprises the steps of: a. injecting a gas into said
coalbed through said production well having an injection gas
pressure sufficient to reduce the water permeability of said
coalbed; b. displacing said water from at least a portion of said
coalbed without substantially altering said coalbed structure; c.
reducing the water permeability of said coalbed; d. excluding at
least a portion of said water from entering to said reduced
permeability coalbed.
33. A method of producing coalbed gas as described in claim 32,
which further comprises the steps of injecting a gas into said
coalbed through said production well having an injection gas
pressure sufficient to cavitate said coalbed.
34. A method of producing coalbed gas as described in claim 20,
which further comprises repeating steps a through j on the same
production well.
35. A method of producing coalbed gas as described in claims 20,
22, 23, 28, 30, or 32, wherein said coalbed stimulation gas is
selected from a group consisting of nitrogen, carbon dioxide, air
or a gas less sorptive to coal than methane.
36. A coalbed gas produced in accordance with the method of claims
20, 22, 23, 28, 30, or 32.
37. An apparatus for coalbed gas production, comprising: a. a
coalbed; b. coalbed gas sorbed to coal in said coalbed; c. at least
one production well which communicates with said coalbed gas; d. a
coalbed gas reservoir having determined characteristics; e. a
coalbed stimulation gas of having an amount appropriate to said
determined characteristics of said coalbed gas reservoir; f. a
coalbed stimulation gas transfer element; g. a production well
coupling element responsive to said stimulation gas transfer
element which delivers said stimulation gas to said coalbed in a
vicinity of said at least one production well; h. desorbed coalbed
gas from said coal in said coalbed gas reservoir; i. a coalbed gas
removal element; and j. at least clean coalbed gas.
38. An apparatus for coalbed gas production as described in claim
37, wherein said coalbed stimulation gas is an amount appropriate
to stimulate said coalbed gas reservoir having said determined
characteristics so as to produce coalbed gas containing less than
about four percent stimulation gas per unit volume under stabilized
coalbed gas removal conditions.
39. An apparatus for coalbed gas production as described in claim
38, wherein said coalbed stimulation gas is an amount appropriate
to stimulate said coalbed gas reservoir having said determined
characteristics so as to produce coalbed gas containing less than
about ten percent stimulation gas per unit volume under stabilized
coalbed gas removal conditions.
40. An apparatus for coalbed gas production as described in claim
35, further comprising a calculated coalbed gas desorption rate at
which said coalbed gas desorbs from said coal and wherein said
coalbed gas removal element has a calculated average coalbed gas
removal rate which is never less than said calculated coalbed gas
desorption rate.
41. An apparatus for coalbed gas production as described in claim
40, further comprising a. water in at least a portion of said
coalbed gas reservoir; b. a water displacement perimeter; and c. at
least one water confinement well which communicates with said
coalbed to remove water encroaching on said water displacement
perimeter.
42. An apparatus for coalbed gas production as described in claim
41, wherein said at least one water confinement well which
communicates with said coal is located at said water displacement
perimeter.
43. An apparatus for coalbed gas production as described in claim
41, wherein said at least one coalbed gas removal element coupled
to said at least one confinement well assists said at least one
coalbed gas removal element to remove coalbed gas at said
calculated coalbed gas removal rate which is never less than said
calculated coalbed gas desorption rate.
44. An apparatus for coalbed gas production as described in claim
43, wherein said at least one production well has a location at
about a centroid of an approximately 40 to 320 acre tract of
land.
45. An apparatus for coalbed gas production as described in claim
44, wherein said at least one water confinement well has a location
at the extent of said approximately 40 to 320 acre tract of
land.
46. An apparatus for coalbed gas production as described in claim
41, wherein said at least one water confinement well has a location
at about a boundary of a production well drainage radius for said
at least one production well.
47. An apparatus for coalbed gas production as described in claim
41, wherein said coalbed stimulation gas has a pressure calculated
to avoid altering the structure of said coalbed and wherein said
stimulation gas pressure induces a reduced water permeability to
said stimulated coalbed as reservoir.
48. An apparatus for coalbed gas production as described in claim
47, further comprising a coalbed structure alteration element which
acts after a portion of said coalbed gas is removed from said
stimulated coalbed reservoir.
49. An apparatus for coalbed gas production as described in claim
45, wherein said approximately 40 to 320 acre tract of land has a
substantially square perimeter.
50. An apparatus for coalbed gas production as described in claim
49, wherein said approximately 40 to 320 acre tract of land having
a substantially square perimeter is adjacent to a another
approximately 40 to 320 acre tract of land having a substantially
square perimeter having a production well.
51. An apparatus for coalbed gas production as described in claim
37, 38, 40, 41, 42 or 43, wherein said coalbed stimulation gas is
selected from a group consisting of nitrogen, carbon dioxide, air,
or a gas less sorptive to coal than methane.
52. A method of producing coalbed gas, which comprises the steps
of: a. locating a coalbed having coalbed gas sorbed to coal; b.
establishing at least one production well to communicate with said
coalbed gas; c. determining a characteristic of said coalbed; d.
calculating an appropriate volume of a coalbed stimulation gas to
inject into said coalbed having said characteristic; e. injecting
said calculated volume of said simulating gas into said coalbed
reservoir; d. stimulating said coalbed gas reservoir; f. desorbing
at least a portion of said coalbed gas sorbed onto said coal in
said stimulated coalbed reservoir; and g. removing coalbed gas from
said coalbed reservoir.
53. A method of producing coalbed gas as described in claim 52,
wherein said step of calculating said appropriate volume of said
stimulation gas to inject into said coalbed gas reservoir comprises
calculating said volume of said stimulation gas which results in
produced coalbed gas from said production well having less than
about ten percent stimulation gas per unit volume of produced
coalbed gas.
54. A method of producing coalbed gas as described in claim 52,
wherein said step of calculating said appropriate volume of said
stimulation gas to inject into said coalbed gas reservoir comprises
calculating said volume of said stimulation gas which results in
produced coalbed gas from said production well having less than
about four percent stimulation gas per unit volume of produced
coalbed gas.
55. A method of producing coalbed gas as described in claim 54,
further comprising the step of using a stimulation gas amount
calculation element:
56. A method of producing coalbed gas as described in claim 54,
which further comprises the steps of calculating a coalbed gas
desorption rate at which said coalbed gas desorbs from said coal
and wherein said step of removing coalbed gas from said coalbed
reservoir has a calculated average rate which is never less than
said calculated coalbed gas desorption rate.
57. A method of producing coalbed gas as described in claim 56,
wherein said step of removing coalbed gas from said coalbed
reservoir at said calculated coalbed gas removal rate comprises
removing coalbed gas from said water confinement wells.
58. A method of producing coalbed gas as described in claim 57,
wherein said step of calculating said desorption rate at which said
coalbed gas desorbs from said coal further comprises using a
desorption rate calculation element.
59. A method of producing coalbed gas as described in claim 57,
wherein said step of removing coalbed gas from said coalbed
reservoir further comprises calculating a coalbed gas removal rate
using a gas removal rate calculation element:
60. A method of producing coalbed gas as described in claim 50,
which further comprises the steps of: a. locating water in at least
a portion of said coalbed gas reservoir; b. calculating a water
displacement pressure not substantially larger than said
hydrostatic pressure to displace at least a portion of said water
from said coalbed gas reservoir; c. displacing said water in said
at least a portion of said coalbed gas reservoir; d. establishing a
water displacement perimeter; e. establishing at least one water
confinement well to communicate with said water located at about
said water displacement perimeter; and f. maintaining said water
displacement perimeter by removing said water encroaching upon said
water displacement perimeter.
61. A method of producing coalbed gas as described in claim 60,
wherein said step of calculating said water displacement pressure
not substantially larger than said hydrostatic pressure to displace
said water comprises using a water displacement calculation
element.
62. A method of producing coalbed gas as described in claim 60,
which further comprises the steps of: a. injecting a gas into said
coalbed having an injection gas pressure sufficient to reduce the
water permeability of said coalbed; b. displacing said water from
at least a portion of said coalbed without substantially altering
said coalbed structure; c. reducing the water permeability of said
coalbed; d. excluding at least a portion of said water from
entering to said reduced permeability coalbed.
63. A method of producing coalbed gas as described in claim 62,
wherein said step of injecting a gas into said coalbed having an
injection gas pressure sufficient to reduce the water permeability
of said coalbed comprises calculating a approximate minimum
stimulation gas pressure to reduce the water permeability of said
coalbed reservoir.
64. A method of producing coalbed gas as described in claim 63,
wherein said step of calculating a minimum stimulation gas pressure
to reduce the water permeability of said coalbed reservoir
comprises using a reduced permeability gas pressure calculation
element:
65. A method of producing coalbed gas as described in claim 63,
which farther comprises the step of cavitating the coalbed gas
reservoir.
66. A coalbed gas produced in accordance with the method of claims
52, 54, 56, 60, 62, or 65.
67. A method of producing coalbed gas as described in claim 52, 54,
56, 60, 62, or 65, wherein said step of establishing at least one
production well comprises locating said at least one production
well at about a centroid of an approximately 40 acre to 320 acre
tract of land.
68. A method of producing coalbed gas as described in claim 67,
wherein said step of establishing at least one water confinement
well comprises locating four water confinement wells located at the
corners of a substantially square perimeter encompassing said
approximately 40 acre to 320 acre tract of land.
69. A method of producing coalbed gas as described in claim 68,
which further comprises the step of locating said at least one
production well adjacent to another approximately 40 acre to 320
acre tract of land having a production well.
70. A method of producing coalbed gas as described in claim 69,
wherein said step of injecting a stimulation gas into said coalbed
reservoir comprises injecting stimulation gas selected from a group
consisting of nitrogen gas, carbon dioxide gas, air, or a gas less
sorptive to coal than methane.
71. An apparatus for coalbed gas production, comprising: a. a
coalbed; b. coalbed gas sorbed to said coalbed; c. at least one
production well which communicates with said coalbed gas; d.
desorbed coalbed gas from said coalbed having a calculated gas
desorption rate; e. a desorbed coalbed gas removal system having a
coalbed gas removal rate which is never less than said coalbed gas
desorption rate; k. a production well coupling element responsive
to said desorbed gas removal element and said production well; and
l. coalbed gas removed from said coalbed gas reservoir.
72. An apparatus for coalbed gas production as described in claim
71, wherein said at least one production well has a location
approximately at a centroid of an approximately 40 acre to 320 acre
tract of land.
73. An apparatus for coalbed gas production as described in claim
72, wherein said approximately 40 acre to 320 acre tract of land
has a substantially square perimeter.
74. An apparatus for coalbed gas production as described in claim
73, wherein said approximately 40 acre to 320 acre tract of land
having said substantially square perimeter has a location adjacent
to another approximately 40 acre to 320 acre tract of land having a
production well.
75. An apparatus for coalbed gas production as described in claim
74, wherein said injecting a coalbed stimulation gas into said
coalbed reservoir comprises injecting a coalbed stimulation gas
selected from a group consisting of nitrogen gas, carbon dioxide
gas, air, a gas less sorptive to coal than methane.
76. An apparatus for coalbed gas production as described in claim
71, further comprising: a. a coalbed stimulation gas; b. a coalbed
stimulation gas transfer element to deliver said stimulation gas to
said at least one production well; and c. a stimulated coalbed gas
reservoir.
77. An apparatus for coalbed gas production as described in claim
76, further comprising: a. water in at least a portion of said
coalbed gas reservoir; b. a calculated water displacement pressure
not substantially larger than said hydrostatic pressure to displace
at least a portion of said water from said coalbed gas reservoir;
c. a water displacement perimeter; and d. at least one water
confinement well to communicate with said water located at about
said water displacement perimeter.
78. An apparatus for coalbed gas production as described in claim
77, wherein said at least one confinement well has a location at
about said water displacement perimeter assists said production
well to remove coalbed gas at said coalbed gas removal rate which
is never less than said coalbed gas desorption rate.
79. An apparatus for coalbed gas production as described in claim
78, wherein said at least one water confinement well comprises
locating four water confinement wells located at corners of said
substantially square perimeter around said tract of land.
80. An apparatus for coalbed gas production as described in claim
77, further comprising: a. a characteristic of said coalbed; b. an
appropriate volume of a coalbed stimulation gas based upon said
coalbed characteristic;
81. An apparatus for coalbed gas production as described in claim
80, wherein said appropriate volume of a coalbed stimulation gas
based upon said coalbed characteristic results in coalbed gas
removed from said stimulated coalbed gas reservoir which contains
less than four percent stimulation gas per unit volume.
82. An apparatus for coalbed gas production as described in claim
81, wherein said coalbed stimulation gas has a pressure calculated
to avoid altering the structure of said coalbed and wherein said
stimulation gas pressure induces a reduced water permeability to
said stimulated coalbed gas reservoir.
83. A method of producing coalbed gas, which comprises the steps
of: a. locating a coalbed having coalbed gas sorbed to coal; b.
establishing at least one production well to communicate with said
coalbed gas; c. injecting a stimulation gas into said coalbed; d.
terminating injection of said gas to said coal; e. desorbing said
coalbed gas sorbed onto said coal; f. calculating a desorption rate
at which said coalbed gas desorbs from said coal; and g.
establishing a coalbed gas removal rate which is never less than
said calculated desorption rate.
84. A method of producing coalbed gas as described in claim 83,
wherein calculating said desorption rate at which said coalbed gas
desorbs from said coal comprises using a desorption rate
calculation element.
85. A method of producing coalbed gas as described in claim 84,
wherein establishing said coalbed gas removal rate which is never
less than said calculated desorption rate further comprises using a
coalbed gas removal rate calculation element.
86. A method of producing coalbed gas as described in claim 85,
which farther comprises the steps of: a. locating water in at least
a portion of said coalbed gas reservoir: b. calculating a water
displacement pressure not substantially larger than said
hydrostatic pressure to displace at least a portion of said water
from said coalbed gas reservoir; c. displacing said water in said
at least a portion of said coalbed gas reservoir; d. establishing a
water displacement perimeter; e. establishing at least one water
confinement well to communicate with said water located at about
said water displacement perimeter; and f. maintaining said water
displacement perimeter by removing said water encroaching upon said
water displacement perimeter.
87. A method of producing coalbed gas as described in claim 86,
wherein said step of establishing a coalbed gas removal rate which
is never less than said calculated desorption rate further
comprises removing said coalbed gas through said confinement
wells.
88. A method of producing coalbed gas as described in claim 86,
which further comprises the step of calculating an appropriate
volume of said coalbed stimulation gas to inject into said coalbed
based upon a characteristic of said coalbed which results in
produced coalbed gas from said production well having less than
four percent stimulation gas per unit volume of produced coalbed
gas.
89. A method of producing coalbed gas as described in claim 86,
which further comprises the step of calculating an appropriate
volume of said coalbed stimulation gas to inject into said coalbed
based upon a characteristic of said coalbed which results in
produced coalbed gas from said production well having less than ten
percent stimulation gas per unit volume of produced coalbed
gas.
90. A method of producing coalbed gas as described in claim 89,
which further comprises the step of: a. injecting a gas into said
coalbed having an injection gas pressure sufficient to reduce the
water permeability of said coalbed; b. displacing said water from
at least a portion of said coalbed without substantially altering
said coalbed structure; c. reducing the water permeability of said
coalbed; d. excluding at least a portion of said water from
entering to said reduced permeability coalbed.
91. A coalbed gas produced in accordance with the method of claims
83, 86, 88 or 90.
92. A method of producing coalbed gas as described in claim 83, 86,
88 or 90, wherein said step of injecting a stimulation gas into
said coalbed comprises injecting a gas selected from a group
consisting of nitrogen gas, carbon dioxide, air, a gas less
sorptive to coal than methane.
93. A method of producing coalbed gas as described in claim 90,
wherein said step of drilling at least one production well
comprises locating said production well approximately at a centroid
of an approximately 40 acre to 320 acre tract of land.
94. A method of producing coalbed gas as described in claim 93,
wherein said locating said production well approximately at said
centroid of said approximately 320 acre tract of land comprises
establishing a substantially square perimeter and further
comprising having said at least one confinement well at about each
corner of said square perimeter.
95. A method of producing coalbed gas as described in claim 94,
which further comprising the step of locating said at least one
production well at a centroid of an approximately 40 acre to 320
acre tract adjacent to an approximately 40 acre to 320 acre tract
having a production well.
96. An apparatus for coalbed gas production, comprising: a. a
coalbed structure having a permeability characteristic; b. at least
one production well which communicates with said coalbed structure;
c. an stimulation gas having a pressure in a range which alters
said permeability characteristic of said coalbed and which avoids
disruption of said coalbed structure; d. an stimulation gas
transfer element; e. a production well coupling element responsive
to said injection gas transfer element and said production well;
and f. a reduced water permeability coalbed.
97. An apparatus for coalbed gas production as described in claim
96, wherein said injection gas having said pressure in a range
which alters said permeability characteristic of said coalbed and
which avoids disruption of said coalbed structure is not greater
than a pressure necessary to reduce said water permeability of said
coalbed.
98. An apparatus for coalbed gas production as described in claim
97, further comprising: a. coalbed gas sorbed on said coalbed
structure; b. desorbed coalbed gas from said reduced water
permeability coalbed; c. a desorbed coalbed gas removal system; and
d. desorbed coalbed gas removed from said reduced water
permeability coalbed through said production well.
99. An apparatus for coalbed gas production as described in claim
98, further comprising: a. water in at least a portion of said
coalbed gas reservoir; b. a calculated water displacement pressure
not substantially larger than said hydrostatic pressure to displace
at least a portion of said water from said coalbed gas reservoir;
c. a water displacement perimeter; d. at least one water
confinement well to communicate with said water located at about
said water displacement perimeter; and
100. An apparatus for coalbed gas production as described in claim
99, wherein said at least one confinement well has a location at
about said water displacement perimeter assists said production
well to remove coalbed gas at said rate which is never less than a
desorption rate of said coalbed.
101. An apparatus for coalbed gas production as described in claim
100, further comprising: a. a characteristic of said coalbed; b. an
appropriate volume of a coalbed stimulation gas based upon said
coalbed characteristic;
102. An apparatus for coalbed gas production as described in claim
101, wherein said appropriate volume of a coalbed stimulation gas
based upon said coalbed characteristic results in coalbed gas
removed from said stimulated coalbed gas reservoir which contains
less than four percent stimulation gas per unit volume.
103. An apparatus for coalbed gas production as described in claim
102, further comprising a calculated coalbed gas desorption rate at
which said coalbed gas desorbs from said coal and wherein said
coalbed gas removal element has a calculated coalbed gas removal
rate which is never less than said calculated coalbed gas
desorption rate.
104. An apparatus for coalbed gas production as described in claim
103, wherein said at least one production well has a location
approximately at a centroid of an approximately 40 acre to 320 acre
tract of land.
105. An apparatus for coalbed gas production as described in claim
104, wherein said approximately 40 acre to 320 acre tract of land
has a substantially square perimeter.
106. An apparatus for coalbed gas production as described in claim
105, wherein said at least one water confinement well comprises
locating four water confinement wells located at corners of said
substantially square perimeter around said tract of land.
107. An apparatus for coalbed gas production as described in claim
106, wherein said approximately 40 acre to 320 acre tract of land
having said substantially square perimeter has a location adjacent
to another approximately 40 acre to 320 acre tract of land having a
production well.
108. An apparatus for coalbed gas production as described in claims
96, 98, 100, 101, and 103, wherein said stimulation gas is selected
from a group consisting of nitrogen, carbon dioxide, air, a gas
less sorptive to coal than methane.
109. A method of producing coalbed gas, which comprises the steps
of: a. locating a coalbed structure having a water permeability
characteristic; b. establishing at least one production well to
communicate with said coalbed structure; c. providing a stimulation
gas; d. injecting said stimulation gas in a manner which avoids
disturbing said coalbed structure; and e. altering said water
permeability characteristic of said coalbed structure through
injection of said stimulation gas in a vicinity of said at least
one production well.
110. A method of producing coalbed gas as described in claim 109,
wherein said step of providing said stimulation gas comprises
providing stimulation gas having a pressure which is not greater
than a pressure necessary to reduce said water permeability of said
coalbed structure.
111. A method of producing coalbed gas as described in claim 110,
which further comprises the steps of: a. locating coalbed gas
sorbed on said coalbed structure; b. desorbing coalbed gas from
said coalbed having said water permeability characteristic altered
by said stimulation gas; and c. removing desorbed coalbed gas from
said coalbed structure.
112. A method of producing coalbed gas as described in claim 111,
wherein said step of providing said stimulation gas comprises
providing stimulation gas having a pressure which is not greater
than a pressure necessary to reduce said water permeability of said
coalbed structure further comprises using a stimulation gas
pressure calculation element.
113. A method of producing coalbed gas as described in claim 111,
which further comprises the step of calculating an appropriate
volume of said coalbed stimulation gas to inject into said coalbed
based upon a characteristic of said coalbed which results in
produced coalbed gas from said production well having less than
four percent stimulation gas per unit volume of produced coalbed
gas.
114. A method of producing coalbed gas as described in claim 113,
which further comprises the step of calculating an appropriate
volume of said coalbed stimulation gas to inject into said coalbed
based upon a characteristic of said coalbed which results in
produced coalbed gas from said production well having less than ten
percent stimulation gas per unit volume of produced coalbed
gas.
115. A method of producing coalbed gas as described in claim 114,
which further comprises the steps of: a. locating water in at least
a portion of said coalbed gas reservoir; b. calculating a water
displacement pressure not substantially larger than said
hydrostatic pressure to displace at least a portion of said water
from said coalbed gas reservoir; c. displacing said water in said
at least a portion of said coalbed gas reservoir; d. establishing a
water displacement perimeter; e. establishing at least one water
confinement well to communicate with said water located at about
said water displacement perimeter; and f. maintaining said water
displacement perimeter by removing said water encroaching upon said
water displacement perimeter.
116. A method of producing coalbed gas as described in claim 115,
which further comprises the steps of calculating a coalbed gas
desorption rate at which said coalbed gas desorbs from said coal
and wherein said step of removing coalbed gas from said coalbed
reservoir has a rate which is never less than said calculated
coalbed gas desorption rate.
117. A method of producing coalbed gas as described in claim 116,
wherein said step of removing coalbed gas from said coalbed
reservoir at said calculated coalbed gas removal rate comprises
removing coalbed gas from said water confinement wells.
118. A coalbed gas produced in accordance with the method of claims
111, 113, 115, 116.
119. A method of producing coalbed gas as described in claim 118,
wherein said step of establishing said at least one production well
comprises locating said production well approximately at a centroid
of an approximately 40 acre to 320 acre tract of land.
120. A method of producing coalbed gas as described in claim 119,
wherein said locating said production well approximately at said
centroid of said approximately 320 acre tract of land comprises
establishing a substantially square perimeter having four
confinement wells located at about the corners of said
substantially square perimeter.
121. A method of producing coalbed gas as described in claim 120,
further comprising the step of locating said at least one
production well at a centroid of an approximately 40 acre to 320
acre tract adjacent to an approximately 40 acre to 320 acre tract
having a production well.
122. A method of producing coalbed gas as described in claim 111,
113, 115, 116, wherein said step of injecting a stimulation gas
into said coalbed comprises injecting a gas selected from a group
consisting of nitrogen, carbon dioxide, air, a gas less sorptive to
coal than methane.
Description
[0001] This application claims the benefit of the provisional
application S/N: 60/090,306 filed on Jun. 23, 1998.
BACKGROUND OF THE INVENTION
[0002] Generally, this invention relates to the improved production
of coalbed gas from substantially solid subterranean formations
including coalbeds. Specifically, this invention relates to the use
of a stimulation gas to manipulate the physical and chemical
properties of such subterranean formations and to increasing the
quantity, quality and rate of production of coalbed gases
associated with such subterranean formations.
[0003] A significant quantity of coalbed gas is physically bound
(or sorbed) within coalbeds. This coalbed gas, which was formed
during the conversion of vegetable material into coal, consists
primarily of methane. Because it is primarily methane, coal gas is
commonly termed coalbed methane. Typically, more than 95% of the
coalbed methane is physically bound (adsorbed) onto the surface of
the coalbed matrix.
[0004] Coal may be characterized as having a dual porosity
character, which consists of micropores and macropores. The
micropore system is contained within the coal matrix. The
micropores are thought to be impervious to water; however, the vast
majority of coalbed methane contained by the coalbed is adsorbed
onto the walls associated with the micropores. The macropores
represent the cleats within the coal seam. Face and butt cleats are
interspersed throughout the coal matrix and form a fracture system
within the coalbed. The face cleats are continuous and account for
the majority of the coalbed's permeability. Butt cleats are
generally orthogonal to the face cleats but are not continuous
within the coal. On production, the coalbed matrix feeds the cleat
system and the desorbed coalbed gas is subsequently removed from
the coalbed at production wells.
[0005] Several important problems limit the economic viability of
coalbed methane production. The first is the handling of produced
water from water-saturated coalbeds. The handling of produced water
can be a significant expense in coalbed methane recovery. In a
typical water-saturated reservoir, water must first be depleted to
some extent from the cleat system before significant coalbed
methane production commences. Water handling involves both pumping
and disposal costs. If the coalbed is significantly permeable and
fed by an active aquifer, it may be impossible to dewater the coal
and induce gas production. Production of significant quantities of
water from an active aquifer may be legally restricted and may
result in lawsuits from others who rely on the affected water
supply. Disposal of the produced water can present several
problems. The water may be discharged to the surface and allowed to
evaporate. If sufficiently clean, the water may be used for
agricultural purposes. Finally, the water may be reinjected into
the coal. All of these disposal methods require environmental
permitting and are subject to legal restrictions. Many conventional
coalbed gas production systems only displace water in the vicinity
of the production well which results in a short coalbed gas
production period which lasts only hours or a few days. One example
is disclosed in U.S. Pat. No. 4,544,037. Gas production stops when
the water returns to the coalbed surrounding the production
well.
[0006] The second problem which limits the economic viability of
coalbed gas production is maintaining the appropriate removal rate
of coalbed gas as it is desorbed from the coalbed. As the pressure
in the immediate vicinity of the producer decreases, a quantity of
gas desorbs from the coal and begins to fill the cleat system. If
the water is excluded from the coalbed surrounding coalbed gas
production well, and as gas desorption continues, the gas phase
becomes mobile and begins to flow to the low-pressured producer.
With the existence of a mobile gas phase, the pressure drawdown
established at the production well is more efficiently propagated
throughout the coalbed. Gas more efficiently propagates a pressure
wave compared to water because gas is significantly more
compressible. As the pressure decline within the coalbed continues,
gas desorption, and therefore gas production, accelerates.
[0007] There is an important relationship between these two present
production problems. The rate of gas diffusion from the coal can
only be maximized by maintaining the lowest possible production
well pressure, however, excessively low pressures increase water
production. Conventional production practices overcome the
diffusion-limited desorption of methane from the coal matrix by
using such excessively low production well pressures, or do not set
coalbed gas removal rates as disclosed in U.S. Pat. No. 4,544,037,
allowing rate-controlling diffusion of coalbed gas and water
encroachment to limit the economic life of the coalbed methane
production well.
[0008] A related problem is coalbed structure water permeability.
Increased water permeability allows water that is displaced from a
coalbed to return more rapidly which results in increased
waterhandling or a shorter economic lifespan of the coalbed
reservior. Conventional production techniques do not effectively
deal with the water permeability of the coalbed structure.
[0009] Another conventional coalbed gas production problem is the
contamination of the coalbed gas removed from the coalbed with
stimulation gas. As but one example, Amoco Production Co. (Amoco)
has developed a method of increasing coalbed methane production by
increasing the pressure difference between the coal matrix and the
cleat system (diffusional, partial-pressure driving force) (U.S.
Pat. No. 4,883,122). As that patent discloses, Amoco injects an
inert stimulation gas (such as nitrogen) into an injection well.
Nitrogen is less sorptive than coalbed methane and tends to remain
in the cleat space. The injected nitrogen drives the resulting gas
mixture to one or more producing wells, where the mixture is
recovered at the surface. By the end of a year's production, the
product gas may contain approximately 20 volume percent nitrogen.
The simulated production rate profiles resulting from a continuous
nitrogen injection are shown in FIG. 5. The point labeled P in FIG.
5 is the production rate immediately prior to application of the
stimulation gas enhanced method. As is evident, the increase in gas
production due to nitrogen injection is immediate and substantial.
Much of the dramatic increase in early-time gas production results
from the reduction in partial pressure of methane in the cleat
system. Part of the improved recovery results from the increase in
reservoir pressure that results from the injection of nitrogen into
the coalbed. However, much of the production over the long term
contains quantities of nitrogen which are substantially higher than
minimum standards for pipeline natural gas.
[0010] Similarly, other ECBM methods which are designed to desorb
gas by the injection of gas into an injection well and recover gas
mixtures at one or more producing wells have high levels of
contaminating stimulation gas in the coalbed gas removed at the
production well. These techniques generally employ the use of
CO.sub.2 or CO.sub.2-nitrogen mixtures as disclosed by U.S. Pat.
Nos. 5,454,666 and 4,043,395; and as disclosed in an Alberta
Research Council (press release). CO.sub.2 is more sorptive than
methane and tends to be adsorbed by the coal matrix. Therefore, the
response of methane at the producers is attenuated. However, as
with the above mentioned methods, these ECBM methods produce
coalbed gas with high levels of stimulation gas. Therefore, as with
the other above mentioned methods a gas cleanup process is
required.
[0011] Another problem with injection of stimulation gas into a
separate well located a distance from the production well is the
production of increased water. In fact, Amoco's ECBM technique may
increase overall water production because the increased quantity of
coalbed gas that results from this injection-desorption process may
tend to sweep additional quantities of water to the producer.
[0012] Yet another problem with convention coalbed gas production
is high cost. Many of the above mentioned methods use stimulation
gas at high pressure which requires the use of expensive,
high-capacity, multistage gas compressors. Similarly, other methods
also use high pressure as disclosed by U.S. Pat. No. 5,419,396;
5,417,286; and 5,494,108. High costs are also associated with the
use of carbon dioxide gas as disclosed by U.S. Pat. No. 4,043,395,
and in the continuous use of coalbed gases during coalbed gas
production as disclosed by U.S. Pat. No. 4,883,122; 5,014,785; and
4,043,395.
[0013] Each of these problems of conventional coalbed gas
production are addressed by the instant invention disclosed.
SUMMARY OF THE INVENTION
[0014] Accordingly, the broad goal of the instant invention to
increase coalbed gas recovery by stimulation of the coalbed
formation. The invention improves on the previously mentioned ECBM
recovery techniques. The present invention comprises a variety of
coalbed stimulation techniques which are applied to coalbed methane
production wells. The techniques serve to displace and confine
water, alter the permeability of coalbed fracture systems,
establish optimal coalbed stimulation gas amounts and coalbed gas
removal rates, and as a result operate to limit water production
rates in water-saturated coalbeds and reduce stimulation gas
content in produced coalbed gas. The methods are simple, economical
and time efficient. Naturally, as a result of these several
different and potentially independent aspects of the invention, the
objects of the invention are quite varied.
[0015] Another of the broad objects of the invention is to provide
a numerical simulator which simulates the flow of water and gas
phases around wells which communicate with coalbed gas. Simulation
of gas desorption and sorption between the coalbed and the cleat
system and the interrelated effects of pressure gradients, fluid
viscosity, absolute permeability and liquid-gas phase permeability
allows prediction of coalbed gas production. This allows various
aspects of the instant invention to be optimized which when used
separately or in combination increase coalbed gas production.
[0016] Yet another object of the invention is to eliminate the
necessity for separate coalbed gas stimulation injection wells and
coalbed gas production wells. As mentioned above most conventional
coalbed production practices use a separate stimulation injection
well and a separate coalbed gas production well. This practice
leads to a variety of problems with water handling-and
contamination of the coalbed gas produced. It is therefor desirable
to establish a method which uses the production well for both
stimulation gas injection and also for coalbed gas removal.
[0017] Another object of the invention is the convenient and
effective water displacement or confinement of water which
surrounds coalbed gas production wells. Water handling as mentioned
above is both costly and inconvenient. An effective method of
displacing water from a large area of the coalbed surrounding the
production well into the adjacent coalbed area would eliminate the
necessity of handling at least a portion of that coalbed water.
[0018] Another object of the invention is to establish a reduced
water permeability of the coalbed so as to exclude at least of
portion of the displaced water. A reduced water permeability
coalbed prevents or slows the rate of water encroachment around
production wells. From the point of commercializing production of
coalbed gas, having less water in the coalbed gas reservoir
translates into less water to handle and to dispose of, increased
coalbed gas recovery, and coalbed bed gas with less water content.
By eliminating the problems associated with coalbed water,
production rates are increased and there is less cost per unit
volume of production.
[0019] An additional object of the invention is to produce clean
coalbed gas from a stimulated coalbed. Coalbed gas containing less
than about four percent per unit volume of coalbed gas does not
have to be cleaned up before it is used. Clean coalbed gas, as a
result, costs less to produce per unit volume than coalbed gas
produced using conventional stimulation techniques. A predictable
method of producing clean coalbed gas is therefor highly
desirable.
[0020] Another object of the invention is to calculate the rate at
which coalbed gas should be removed from the coalbed or other
subterranean formation. Desorption of coalbed gas from coalbed
formations is a rate limiting step with regard to production.
Desorption of coalbed gas is increased when the coalbed is
stimulated and when the desorbed gas is removed. Optimal removal
rates of coalbed gas from the production well establishes a
desirable balance between a lowered pressure which induces
continual desorption of coalbed gas from the coal matrix and yet
not so low as to draw previously displaced water back into the
coalbed reservoir.
[0021] Another object of the invention is to reduce the cost of
coalbed gas production. Most conventional coalbed gas stimulation
techniques utilize continuous high pressure injection of
stimulation gas during the production of coalbed gas. Additionally,
many techniques utilize purified gas which necessitates
fractionation of atmospheric gas. This necessitates the long term
use of expensive multistage gas compressors and fractionation
equipment. Moreover, many techniques also require separate
injection wells and production wells and then subsequent
purification of the produced coalbed gas. As such, these techniques
may be prohibitively expensive to use. The instant invention,
eliminates many of these expensive features and steps allowing
coalbed gas to be produced at a considerably lower cost.
BRIEF DESCRIPTION OF FIGURES
[0022] FIG. 1 is a graph of typical coalbed production rates using
conventional recovery techniques.
[0023] FIG. 2 is a graph of typical sandstone production rates
using conventional recovery techniques.
[0024] FIG. 3 is a drawing of a particular embodiment of the
instant invention.
[0025] FIG. 4 is a graph of the relative ability of water and gas
to flow as a function of the water saturation of a coalbed.
[0026] FIG. 5 is a graph of a simulated conventional production
history of a coalbed continuously stimulated with nitrogen gas.
[0027] FIG. 6 is a depiction of the dual porosity structure of
coal.
[0028] FIG. 7 is a particular embodiment of the pattern of a
production well in relation to water confinement wells.
[0029] FIG. 8 is a graph which compares the coalbed gas production
from an unstimulated coalbed and a stimulated coalbed gas using a
particular embodiment of this invention with nitrogen.
[0030] FIG. 9 is a graph which compares the coalbed gas production
from a stimulated coalbed using the instant invention which was
previously produced by conventional unstimulated coalbed
methods.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0031] As can be easily understood, the basic concepts of the
present invention may be embodied in a variety of ways. It involves
both treatment techniques as well as devices to accomplish the
appropriate treatment. In this application, the treatment
techniques are disclosed as part of the results shown to be
achieved by the various devices described and as steps which are
inherent to utilization. They are simply the natural result of
utilizing the devices as intended and described. In addition, while
some devices are disclosed, it would be understood that these not
only accomplish certain methods but also can be varied in a number
of ways. Importantly, as to all of the foregoing, all of these
facets should be understood to be encompassed by this
disclosure.
[0032] FIGS. 1 and 2 are generally representative of conventional
gas production profiles for typical coalbed and sandstone
formations. Production from the coalbed formation (FIG. 1) is
characterized by an initial period of high water production and low
gas production. The gas production rate increases with the partial
depletion of water and the lowering of pressure in the coalbed. As
described earlier, the lowering of pressure results in the
desorption of coalbed methane from the coal matrix. The gas rate
falls off in the later stages of production. This decline in
production results from at least two factors: (1) a depletion of
sorbed methane from the coal and (2) a rate-controlling diffusion
of gas from the coal that is related to the difference in pressure
between the coal matrix and the cleat system.
[0033] In comparison, the gas production from a sandstone formation
is often related only to reservoir pressure (FIG. 2). The gas is
contained within the sandstone's pore space. Gas production is
highest initially because reservoir pressure and gas content are at
a maximum. Production rate declines as gas content and, therefore,
reservoir pressure declines. Water rate increases as pressure
declines, either because of water encroachment or because of an
increase in the permeability to water as the pore space collapses
as shown in FIG. 4.
[0034] The production of coalbed methane from a water-saturated
coal resource with the instant invention may involve displacing
water surrounding the production well or wells without disrupting
the coalbed structure or confinement of the displaced water so that
it does not encroach upon the dewatered coalbed gas reservoir
during coalbed gas production. This can be subsequently followed by
the following three steps: (1) production of gas and lowering of
pressure in the immediate vicinity of the wellbore; (2) the
desorption of coalbed methane from the coal matrix into the cleats
due to the pressure reduction; and (3) the accelerated production
of mobile coalbed methane gas from the coalbed as the radius of
influence of the pressure drawdown increases throughout the
coalbed. The present invention operates to improve the efficiency
of all these production steps and production mechanisms.
[0035] As depicted in FIG. 3, The present invention stimulates a
producer by injecting an appropriate quantity or amount of coalbed
stimulation gas (1) into at least one production well (2). This is
accomplished by using a compressor or other stimulation gas
transfer element (3) perhaps joined to the annular region
production well by a gas plenum having control valves or other
production well coupling element (4) responsive to both the
stimulation gas transfer element and the production well. The
injected stimulation gas flows into the coalbed (5) in the vicinity
of the production well. Conceivably, any gas can be used, but the
most preferable is a gas that is less sorptive than methane, such
as nitrogen but may also be carbon dioxide. The optimum injection
gas may be air because it's free and is 80% nitrogen. Water (6)
which is associated with the coalbed or a part of the coalbed
surrounding the production well has a hydrostatic pressure. The
coalbed stimulation gas (1) can be delivered to the coalbed at a
pressure greater than that of the hydrostatic pressure of the water
and the water is displaced a distance from the well. With continued
injection, a region of gas saturation is established at an extended
distance into the coalbed thereby establishing a water displacement
perimeter (7). This operation effectively partially de-waters the
coalbed without producing water to the surface. Optimally, the
pressure is not substantially larger than the hydrostatic pressure
of the water so as not to disrupt the coalbed structure. One or
more water confinement wells (8) may be established a distance from
the production well or at the water displacement perimeter or at
the production well drainage radius to remove water encroaching
upon the production well. Removal of water may be accomplished by
use of a pump or other water transfer element (9) coupled to the
confinement well through a variety of water confinement coupling
elements (10). At least water is removed from the confinement wells
although gas may also be removed from the stimulated coalbed
reservoir from the confinement well as necessary to assist the
production well in removal of coalbed gas from the coalbed gas
reservoir at the required removal rate through various coupling
elements (7). The area swept by the injected coalbed stimulation
gas by this method may be significantly greater than the radius of
pressure drawdown that results from initially de-watering a well by
conventional production methods. Assuming the injected gas is
composed substantially of nitrogen, the coalbed's cleat system is
initially occupied by a gas that contains little methane (15).
[0036] At the time the injection of coalbed stimulation gas ceases
and the production well is about to be placed on production by
lowering its pressure any of the following conditions have been
created by the stimulated coalbed gas reservoir (11) which should
improve gas production rate at the production well and reduce the
water production rate at the production well compared to
conventional production methods. First, at least a partial
saturation of coalbed stimulation gas has been established at an
extended distance into the coalbed. As a result, the partial
pressure driving force for coalbed methane desorption is high. This
saturation will also serve as an efficient medium for transferring
through the cleat system or drawdown the reduction in pressure of
water. This drawdown may be accomplished by a pump or water removal
element (12) coupled to the production well with any of a variety
of production well coupling elements (13) that results from
simultaneously removing coalbed gas and water from the coalbed by
means of the production well for producer.
[0037] Second, the water saturation has been decreased, which
reduces its ability to flow to the producer. The ability of water
to flow (water permeability of the coalbed) as a function of water
saturation is conceptually depicted in FIG. 4. In a gas-water
system, permeability to water drops as the water saturation
decreases. The ability of a well to produce water is directly
proportional to the coalbed's permeability to water, as shown by
the equation:
qw=PI.times.Krw.times..DELTA.P, where
[0038] qw=water production rate from a producer;
[0039] PI=productivity index of the well;
[0040] Krw=relative permeability to water; and
[0041] .DELTA.P=difference in pressure between producing well and
adjacent coalbed.
[0042] Conversely, because of the increased gas saturation, the
permeability to gas, and therefore its production rate, will be
increased.
[0043] Third, the coalbed stimulation gas injected into the cleat
system will initially promote a reduced methane content (i.e.,
concentration) in the cleats, which will increase the desorption
rate of methane from the coal matrix to the coal's cleat system by
the method of partial pressure reduction. The dual porosity
structure in coal is depicted in simple form in FIG. 6. Recall that
the cleat system is drained by the producing wells, and notice that
the cleat system surrounds the coal matrix. The relative locations
where the partial pressures of coalbed methane are calculated in
the cleats and the coal matrix are also shown in FIG. 6. During the
injection phase of this invention, coalbed stimulation gas replaces
a portion of the water as part of the displacement process.
Initially, the gas in the cleat system will contain a low-volume
fraction of methane and therefore, be at a low partial pressure of
methane. The idealized relationship that equates partial pressure
of coalbed methane in the cleats to local cleat pressure and volume
fraction of coalbed methane is shown by the following equation:
P.sub.CH.sub..sub.4=P.sub.CLEAT.times.V.sub.CH.sub..sub.4,
where
[0044] P.sub.CH.sub..sub.4=partial pressure of coalbed methane in
the cleats;
[0045] P.sub.CLEAT=Absolute pressure in the cleat at a particular
spatial location; and
[0046] V.sub.CH.sub..sub.4=Volume fraction of coalbed methane in
the cleat measured at the same location as P.sub.CLEAT
[0047] A conceptual relationship that relates the gas desorption
rate from the coal matrix to the cleats as a function of their
respective partial pressures is shown by the following
equation:
Q.sub.DSORB=K.times.(P.sub.COAL-P.sub.CH.sub..sub.4) where
[0048] Q.sub.DSORB=Rate of coalbed methane desorption from coal
matrix to the cleat system;
[0049] K=A group of terms assumed to be constant for this
example;
[0050] P.sub.COAL=Partial pressure of coalbed methane adsorbed onto
the surface of the coal matrix at a particular spatial location;
and
[0051] P.sub.CH.sub..sub.4=Partial pressure of coalbed methane
existing in the cleats measured at the same location as
P.sub.COAL
[0052] The above mentioned relationships will show a close
dependence between rate of desorption and the difference in partial
pressure, which is called the diffusional, partial-pressure driving
force. All of the above-mentioned factors should increase the
coalbed methane production rate and decrease the water production
rate. More complex relationships are possible and may require the
use of a numerical simulator such as WRICBM model entitled
"Development Of A Portable Data Acquisition System And Coalbed
Methane Simulator, Part 2: Development Of A Coalbed Methane
Simulator" which is attached to this application and hereby
incorporated by reference. The equations defined within WRICBM are
time dependent, interrelated (coupled) and non-liner in nature.
WRICBM uses an iterative, simultaneous method to solve the
equations for each discrete volume element or coalbed
characteristic of a coalbed at every point in time. A general and
simplified description of the WRICBM's formulation and equation set
follows.
[0053] WRICBM models a dual-porosity formation in which a
stationary, non-porous, nonpermeable matrix communicates with a
porous, permeable matrix. The stationary matrix represents the
coal. The permeable matrix represents the coalbed's cleat
(fracture) system. Water and gases only flow within the permeable
matrix. Gases exchange between the stationary and matrix elements.
This feature simulates gas desorption/sorption between the
coalbed's coal and cleat systems. The movement of gases and water
phases within the permeable matrix are described by the generally
accepted multi-phase modification of Darcy flow. Therefore, the
transport of the fluids are subject to the effects of pressure
gradients for each phase, fluid viscosity, absolute permeability,
and liquid-gas phase relative permeability. The rate and quantity
of gas desorption/sorption between the stationary and permeable
matrix systems can optionally be determined by equilibrium
controlled, pseudo-unsteady state controlled, and fully unsteady
state controlled transport mechanisms. Equilibrium transport
assumes that the pressure in the coal is the same as the pressure
in the local fracture system. Thus, there is no time delay for gas
sorbing or desorbing with respect to the coal. The pseudo-unsteady
state transport assumes an average concentration of gas sorbed
within the coal and a diffusional time delay for sorbed gas
movement within the coal. Fully unsteady state transport assumes a
concentration gradient of sorbed gas within the coal element with a
diffusional delay for sorbed gas movement within the coal. For the
unsteady state methods, the sorbed gas, concentration at the
surfaces of each coal element are functions of the local partial
pressures at the cleat matrix. Partial pressure is the product of
the reservoir pressure and the individual mole fraction of each gas
species present. The multi-component, Extended Langmuir
relationship relates the quantity of individual gas component
sorbed to respective gas partial pressure.
[0054] The following set of equations are solved simultaneously
within WRICBM at each discrete timestep for each differential
element of coalbed:
[0055] 1. Material balance for water
[0056] 2. Material balance for each gas component present in the
stationary-matrix, permeable -matrix system
[0057] As stated previously, Darcy flow describes the transport of
material with respect to each differential element's permeable
matrix. The quantity of gas desorbed/sorbed for each component is
represented in the respective gas material balance equation by a
source term. The rate of gas desorption/sorption is dependent on
the local partial pressure for each permeable matrix's differential
element and the corresponding sorbed concentration of each gas
component.
[0058] WRICBM calculates the flow of water and gas phases at the
wells in the standard way.
[0059] The calculation uses viscosity for the phases, differential
pressure between each phase's matrix pressure and the wellbore, and
a productivity index that accounts for the radical nature of the
well's drainage. Source terms couple the well equations to the
individual material balance equations.
[0060] As a result the invention has many embodiments and may be
implemented in different ways to optimize the production of coalbed
methane. The option selected will depend on the determined
characteristics of the coalbed reservoir and the conditions at the
production well. This model may be invaluable in utilizing the
disclosed absorption and desorption rate calculation elements,
water displacement rate calculation elements, stimulation gas
amount calculation elements, coalbed gas removal calculation
elements, and reduced permeability gas pressure calculation
elements, although calculation elements may used manually or
otherwise. Optimizing this process may require a knowledge of
reservoir engineering and the use of a coalbed methane
simulator.
[0061] One embodiment of the invention uses a production well (12)
to both deliver stimulation gas (1) to the coalbed gas reservoir
and for the removal of coalbed gas (14) from the coalbed gas
reservoir (11). As mentioned above this approach is different than
most conventional coalbed gas production techniques which use a
separate gas stimulation well and a separate coalbed gas production
well. Using the production well for both purposes eliminates many
of the problems associated with conventional production methods
which include excessive water production at the coalbed gas
production well, contamination of the produced coalbed gas with
excessive amounts of stimulation gas and the unintended alteration
of the coalbed structure to mention a few. With regard to the
instant invention, the gas may be injected into the coalbed for a
brief period of time through the production well and the amount of
stimulation gas may be limited. The producer may be subsequently
placed back on production, and a dramatic increase in coalbed
methane recovery and reduction in water production results. This
approach may be applied to coalbeds that are either substantially
dry with little or no mobile water saturation or applied to
coalbeds that have a portion or all of the coalbed saturated with
water (6). In the former case, the increase in production would not
significantly involve changes in permeability to the water or gas
phases but will involve desorption of gas from the coal matrix and
possibly the immobile water. In the later case, the water in the
coalbed may be displaced from a large area surrounding the
production well by the delivery of the stimulation gas to the
production well. The de-watered coalbed gas reservoir volume may
define a water displacement perimeter (7). This invention or
approach may require the use of surrounding producers or water
confinement wells (8) in addition to the stimulated well (or
wells). During production of the stimulated wells, these additional
producers can limit the encroachment of water that has been
displaced from the coalbed by the gas injection procedure. Used in
the ways described above, these surrounding wells may be regarded
as conventional, unstimulated producers or as water confinement
wells that act as barriers between the stimulated coalbed region
and the surrounding aquifer. In a particular application of the
embodiment and as shown in FIG. 7, the production well may be
located at the centroid of a tract of land having an area of
between approximately 40 and 320 acres. The tract of land may
optimally have a substantially square perimeter but this may not
necessarily be the case. Water confinement wells may be located
approximately at the corners of the substantially square perimeter
to remove water encroaching upon the de-watered coalbed surrounding
the production well. The coalbed may be stimulated by injecting
coalbed stimulation gas through the production well for a brief
period of eight to twelve days with an amount of coalbed
stimulation gas to sweep a substantial portion of the dewatered
coalbed reservoir. The injection of coalbed stimulation as may be
terminated and the same well may be used for removal of coalbed gas
and possibly water at a rate which lowers the coalbed pressure in
the coalbed and which is optimally never less than the rate at
which the coalbed gas is desorbed from the coalbed. A number of
adjacent tracts of land may be produced simultaneously by this
method as yet another application of this same embodiment. This
method may also be used on virgin or previously produced coalbed
gas reservoirs.
[0062] A second embodiment of this invention is to decrease the
water permeability of the coalbed formation. As mention above and
as shown in FIG. 4 increased water contained in a coalbed allows
increased flow of water to the coalbed. Permeability, as mentioned
above, is also a characteristic of coalbeds that have had the
coalbed structure altered by some conventional high pressure
injection techniques. The instant invention assesses the
hydrostatic pressure of water associated with the coalbed
surrounding a production well. Subsequently, a coalbed stimulation
gas having a pressure greater than the hydrostatic pressure but
with a pressure calculated to avoid altering the structure of the
coalbed is injected into the production well. A reduced water
permeability calculation element may be used to assist in these
calculations. The pressure of the injected coalbed stimulation gas
limited to a pressure not substantially greater than the
hydrostatic pressure displaces at least a portion of the water in
the coalbed without altering the coalbed structure. The de-watered
coalbed having the same structure may be a reduced water
permeability. To the extent that the reduced water permeability
excludes water from the coalbed reservoir the economic life of the
coalbed is extended, a reduced volume of water has to be removed by
water confinement wells, and the coalbed gas produced may contain
less water. In fact, overall water production should be lower than
with any production scheme (ECBM or otherwise) because of the
displacement of water from the coal and the reduced permeability to
water. Water handling costs should be lower as well, particularly
relative to the quantities of coalbed methane produced. Naturally,
this technique could be used in applications other than the
production of coalbed gas where water permeability of the
subterranean formation is important.
[0063] Another embodiment of this invention comprises maintaining
increased desorption of coalbed gases from the surface of the
organic matrix of subterranean formation or coalbed. The production
of coalbed gas from a de-watered coalbed can involve: (1)
production of gas and lowering of pressure in the immediate
vicinity of the wellbore; (2) the desorption of coalbed methane
from the coal matrix into the cleats due to the pressure reduction;
and (3) the accelerated production of mobile coalbed methane gas
from the coalbed as the radius of influence of the pressure
drawdown increases throughout the coalbed. These may be are
optimized when the coalbed gas desorption rate is known and the
removal rate of coalbed gas from the coalbed is never less than the
desorption rate from the surface of the organic matrix of the
coalbed or subterranean formation. However, withdrawal rates must
not be so great as to lower the pressure of the formation so as to
draw water into the coalbed. One aspect of this invention is
therefore, a method of estimating the desorption rate of the
coalbed gas from the coalbed by calculating a coalbed gas
desorption rate at which the coalbed gas desorbs from the coalbed.
Producing the estimate may involve the use of a desorption rate
calculation elements in the model. Based on this estimate, a gas
removal rate is determined which is optimally never less than the
calculated coalbed gas desorption rate. Determing the coalbed gas
removal rate may involve the use of a gas removal rate calculation
element. Subsequently, the coalbed gas is removed from the
production well at the calculated coalbed gas removal rate. Since
this removal rate may be calculated to be a value not substantially
greater than the desorption rate the coalbed may have a pressure
which induces the least amount of water to be drawn into the
coalbed. The water confinement wells may also be used to assist in
the removal of coalbed gas to maintain or establish a reduced
coalbed gas reservoir pressure within the region of stimulated
production wells.
[0064] In an additional embodiment of the invention, an appropriate
amount of coalbed stimulation gas to be used based upon determined
characteristics of the coalbed. One such characteristic may be
sorbed coal gas volume although other characteristics could be
determined and additionally the characteristics may be
interdependent on one another. Simulations may have to be run to
weigh these characteristics to estimate the stimulation gas having
an appropriate amount to stimulate the coalbed reservoir. Because
the amount of stimulation gas estimated is the minimum amount to
stimulate the coalbed gas reservoir, coalbed gas removed from the
production well may not require cleanup for pipeline use. In
simulations of the present method with nitrogen, the nitrogen
content of the initially produced as may be less than ten volume
percent and optimally less than four volume per cent, under stable
stabilized coalbed gas removal conditions, and the percentage may
decrease with time. The clean coalbed gas having low levels of
contamination by nitrogen, results from the limited quantities of
stimulation gas injected and its dilution from the large quantities
of the coalbed methane gas mixture produced after stimulation.
[0065] In yet another embodiment of the invention, the stimulation
of a producer may be accomplished by mechanical or chemical
alteration of the coal and coalbed's physical structure. These
stimulation methods employ high pressure coalbed stimulation gas,
acid treatments or other coalbed alteration elements to induce
fracturing and creation of cavities (cavitation). These forms of
stimulation either extend the well's drainage radius by improving
the coal's absolute permeability or increase the well's
productivity index. Thus, the mechanical and chemical techniques
stimulate wells differently than the present invention and should
be considered as a separate and distinct method of enhancing
production. However, it may be possible to achieve a further
increase in production by applying the present invention in
addition to a mechanical or chemical stimulation. In any case, a
limited degree of fracturing may occur in the immediate vicinity of
the well bore when the present invention is applied to a soft coal.
This minor degree of fracturing is probably an unavoidable
consequence of injecting air into the pressurized coalbed.
[0066] In another embodiment of the invention, several adjacent
producers within a field may be stimulated simultaneously. This
technique would de-water a large portion of the reservoir before
the commencement of production. The period of as injection could be
increased at a central well or to establish gas saturation at
surrounding producers. This technique may de-water a large region
of the coalbed using a single well. A single well within a pattern
could be stimulated for a limited period before being placed on
production. In this case, the outer wells could serve as barriers
to prevent water encroachment and to further reduce the overall
pressure in the reservoir. Finally, a central region of the
reservoir comprising several wells can be de-watered by gas
injection, and a surrounding pattern of unstimulated producers can
be used to prevent water encroachment into the dewatered area.
[0067] In yet another embodiment, the stimulation technique may be
repeated on a particular well (or wells). The technique may also be
used on wells that were previously produced by conventional means
and are therefore partially de-watered. The increase in recovery
may not be as dramatic as its application to a virgin reservoir,
but it may be significant.
[0068] In many of the above mentioned embodiments the stimulation
compression costs are significantly reduced. This invention does
not always employ high injection pressures. In fact, it is most
efficiently operated by maintaining the lowest possible processing
and reservoir pressures. It is only necessary to moderately exceed
the prevailing hydrostatic gradient. In addition, the gas injection
(or stimulation cycle) is only performed for a brief period. In
comparison, a typical ECBM procedure requires continuous or almost
continuous injection at high injection pressures and gas rates to
drive the gas mixture to the producer.
[0069] Lastly, this invention may be applied to any reservoir
material or subterranean formation whose gas is physically held
(sorbed) onto the surface of an organic matrix and can be released
by a reduction in pressure. In this manner water associated with a
portion of the coalbed is displaced away from the coalbed.
EXAMPLES
[0070] The following examples of both apparatus and methods for
coalbed gas reservoir simulation are representative and do not
limit the possible scenarios and variations of using this
invention. A stimulation gas is applied to a production well
located within a five-spot repeated pattern of producers on
320-acre spacings as shown in FIG. 7. The coalbed is fully
water-saturated and has not been previously produced. The
permeability of the coalbed is 1 Darcy, and its depth is 700 ft. A
stimulation of the coalbed reservoir is performed by injecting 60
thousand standard cubic feet per day for 10 days. The producer is
subsequently placed on production for the remainder of one year.
The cumulative coalbed methane production as a function of time is
shown in FIG. 8. Also shown in FIG. 8 is the cumulative coalbed
methane production that results from a conventional gas depletion
procedure. The stimulated well yields a 30-fold increase in
cumulative production compared to the conventionally produced well.
The gas: water ratios for the stimulated and unstimulated wells
were 3.9 and 0.12 mscf/bbl, respectively. The maximum nitrogen
content in the stimulated producer's product gas was 3.0 volume
percent. This example demonstrates the dramatic increases in
coalbed gas production that are possible with this invention. It is
also illustrative of the potential commercial benefit that can be
derived from the production of clean coalbed gas that does not
require any further cleanup prior to introduction into a gas supply
pipeline.
[0071] As a second example, a stimulation was performed on a well
that was previously on production by a conventional depletion
method for one year. The reservoir description and production well
pattern are the same as for the first example. A 10-day stimulation
was performed as before. The cumulative production history for the
stimulated well and the well that is continuing to be produced on
primary are compared for the second year of production as shown in
FIG. 9. The stimulated well produced 40 volume percent more coalbed
methane. The gas: water ratios for the stimulated and unstimulated
procedures were 8.7 and 6.1 mscf/bbl, respectively. The maximum
nitrogen content in the stimulated producer's product gas was less
than 5.0 volume percent. This example demonstrates that a
substantial increase in coalbed methane production is possible when
the technique is applied to a well that is already under
production.
[0072] It should be understood that the apparatuses and methods of
the embodiments of the present invention and many of its attendant
advantages will be understood from the foregoing description and it
will be apparent that various changes may be made in the form,
construction and arrangement of the parts thereof without departing
from the spirit and scope of the invention or sacrificing all of
its material advantages, the form hereinbefore described being
merely a preferred or exemplary embodiment thereof.
[0073] Particularly, it should be understood that as the disclosure
relates to elements of the invention, the words for each element
may be expressed by equivalent apparatus terms or method terms even
if only the function or result is the same. Such equivalent,
broader, or even more generic terms should be considered to be
encompassed in the description of each element or action. Such
terms can be substituted where desired to make explicit the
implicitly broad coverage to which this invention is entitled. As
but one example, it should be understood that all action may be
expressed as a means for taking that action or as an element which
causes that action. Similarly, each physical element disclosed
should be understood to encompass a disclosure of the action which
that physical element facilitates. Regarding this last aspect, and
as but one example the disclosure of a "stimulated coalbed
reservoir" should be understood to encompass disclosure of the act
of "stimulating a coalbed reservoir"--whether explicitly discussed
or not--and, conversely, were there only disclosure of the act of
"stimulating a coalbed reservoir", such a disclosure should be
understood to encompass disclosure of a "stimulated coalbed
reservoir". Such changes and alternative terms are to be understood
to be explicitly included in the description.
[0074] Any references mentioned, including but not limited to the
references in the application to a "Development Of A Portable Data
Acquisition System And Coalbed Methane Simulator, Part 2:
Development Of A Coalbed Methane Simulator", are hereby
incorporated by reference or should be considered as additional
text or as an additional exhibits or attachments to this
application to the extent permitted; however, to the extent
statements might be considered inconsistent with the patenting of
this/these invention(s) such statements are expressly not to be
considered as made by the applicant. Further, the disclosure should
be understood to include support for each feature, component, and
step shown as separate and independent inventions as well as the
various combinations and permutations of each.
* * * * *