U.S. patent application number 13/644656 was filed with the patent office on 2014-04-10 for enhanced hydrocarbon recovery from multiple wells by steam injection of oil sand formations.
This patent application is currently assigned to GeoSierra LLC. The applicant listed for this patent is GeoSierra LLC. Invention is credited to Grant Hocking.
Application Number | 20140096959 13/644656 |
Document ID | / |
Family ID | 50431507 |
Filed Date | 2014-04-10 |
United States Patent
Application |
20140096959 |
Kind Code |
A1 |
Hocking; Grant |
April 10, 2014 |
ENHANCED HYDROCARBON RECOVERY FROM MULTIPLE WELLS BY STEAM
INJECTION OF OIL SAND FORMATIONS
Abstract
The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by steam injection
into highly permeable vertical inclusion planes in the oil sand
formation, and heating the heavy oil and bitumen, which flow by
gravity to the wells. The inclusion is propagated into a portion of
the formation having a Skempton's B parameter of greater than 0.95
exp(-0.04 p')+0.008 p', where p' is a mean effective stress in MPa
at the depth of the inclusion. The inclusion planes can be
propagated from only the central well, or from all wells, being the
central well and the periphery wells. The inclusion planes are
propagated into the formation to intersect and coalesce to provide
hydraulic connection between the central well and the periphery
wells. Steam is injected continuously in the central well, and
liquids are produced continuously from all wells, whilst
maintaining a liquid head over production tubing for steam trap
control. By injection of solvents and other gases and controlling
the reservoir temperature and pressure, a particular fraction of
the in situ hydrocarbon reserve is extracted and water inflow into
the heated zone is minimized.
Inventors: |
Hocking; Grant; (Alpharetta,
GA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GeoSierra LLC; |
|
|
US |
|
|
Assignee: |
GeoSierra LLC
Alpharetta
GA
|
Family ID: |
50431507 |
Appl. No.: |
13/644656 |
Filed: |
October 4, 2012 |
Current U.S.
Class: |
166/272.2 |
Current CPC
Class: |
E21B 43/2405
20130101 |
Class at
Publication: |
166/272.2 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method of improving production of hydrocarbon liquids from a
subterranean formation of weakly cemented sediments, the method
comprising the steps of: a) propagating a substantially vertical
first inclusion by injecting a fluid filled with proppant particles
into the formation in a first preferential direction having an
azimuth from a substantially vertical central wellbore intersecting
the formation; b) after the viscosity of the injected fluid in the
first inclusion has substantially reduced, propagating a
substantially vertical second inclusion filled with proppant
particles in the same but opposite preferential direction as the
first inclusion initiated from a circumferential wellbore, the
second vertical inclusion to intersect and coalesce with the first
vertical inclusion in the same formation; c) injecting steam into
the central wellbore and into a process zone in the formation; and
d) producing heated hydrocarbon liquids up the wellbores.
2. The method of claim 1, wherein the method includes propagating a
plurality of first and second inclusions at varying azimuths and a
plurality of circumferential wellbores at the same varying
azimuths.
3. The method of claim 1, wherein the method includes propagating a
plurality of inclusions propagated from the wellbores at
progressively shallower depths after the viscosity of the injected
fluid in the immediate lower inclusion has reduced substantially,
so that the shallower depth inclusions intersect and coalesce with
the inclusions immediately beneath on their respective
azimuths.
4. The method of claim 3, wherein the method includes propagating a
plurality of inclusions at varying azimuths and a plurality of
circumferential wellbores at the same varying azimuths.
5. The method of claim 1, wherein the proppant particles ranging in
size from #4 to #100 U.S. mesh are sand, ceramic beads, resin
coated sand and resin coated ceramic beads or mixture thereof.
6. The method of claim 1, wherein the steam injection is a
continuous injection, and the production of hydrocarbon liquids is
also continuous.
7. The method of claim 1, wherein the steam injection is a pressure
pulsed cyclic injection or intermittent injection.
8. The method of claim 1, wherein steam pressure in the process
zone is at ambient reservoir pressure.
9. The method of claim 1, wherein the method includes injecting
into the process zone a non-condensing gas or a hydrocarbon solvent
in a vaporized state or a mixture thereof.
10. The method of claim 9, wherein the solvent is one of a group of
ethane, propane, butane or a mixture thereof.
11. The method of claim 9, wherein the solvent is mixed with a
diluent gas.
12. The method of claim 11, wherein the diluent gas is
non-condensable under the process conditions.
13. The method of claim 12, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbon liquid than the saturated
hydrocarbon solvent.
14. The method of claim 13, wherein the diluent gas is one of a
group of methane, nitrogen, carbon dioxide, natural gas or a
mixture thereof.
15. The method of claim 1, wherein the method includes injecting a
hydrogenizing gas into the wellbore and thus into the fluids in the
process zone to promote hydrogenation and thermal cracking
reactions of at least a portion of the hydrocarbon fluids in the
process zone.
16. The method of claim 15, wherein the hydrogenising gas consists
of one of the group of H2 and CO or a mixture thereof.
17. The method of claim 15, wherein the method includes catalyzing
the hydrogenation and thermal cracking reactions of at least a
portion of the petroleum fluids in the process zone.
18. The method of claim 17, wherein a metal-containing catalyst is
used to catalyze said hydrogenation and thermal cracking
reactions.
19. The method of claim 18, wherein the catalyst is contained in a
canister in tubing inside of the wellbore.
20. The method of claim 18, wherein the proppant particles in the
inclusions contain the catalyst for the hydrogenation and thermal
cracking reactions.
21. A method of improving production of hydrocarbon liquids from a
subterranean formation of weakly cemented sediments, the method
comprising the steps of: a) propagating a substantially vertical
first inclusion by injecting a fluid filled with proppant particles
into the formation in a first preferential direction at an azimuth
from a substantially vertical central wellbore intersecting the
formation; b) propagating the substantially vertical first
inclusion to intersect a circumferential relief wellbore operated
at a reduced pressure and on azimuth with the propagating
inclusion; c) injecting steam into the central wellbore and into a
process zone in the formation; and d) producing the heated
hydrocarbon liquids up the wellbores.
22. The method of claim 21, wherein the method includes propagating
a plurality of first inclusions at varying azimuths and a plurality
of circumferential relief wellbores at the same varying
azimuths.
23. The method of claim 21, wherein the method includes propagating
a plurality of inclusions propagated from the central wellbore at
progressively shallower depths after the viscosity of the injected
fluid in the immediately lower inclusion has substantially reduced,
so that the shallower depth inclusions intersect and coalesce with
the inclusions immediately beneath on their respective
azimuths.
24. The method of claim 23, wherein the method includes propagating
a plurality of inclusions at varying azimuths and a plurality of
circumferential relief wellbores at the same varying azimuths.
25. The method of claim 21, wherein the proppant particles ranging
in size from #4 to #100 U.S. mesh are sand, ceramic beads, resin
coated sand and resin coated ceramic beads or mixture thereof.
26. The method of claim 21, wherein the steam injection is a
continuous injection, and the production of hydrocarbon liquids is
also continuous.
27. The method of claim 21, wherein the steam injection is a
pressure pulsed cyclic injection or intermittent injection.
28. The method of claim 21, wherein steam pressure in the process
zone is at ambient reservoir pressure.
29. The method of claim 21, wherein the method includes injecting
into the process zone a non-condensing gas or a hydrocarbon solvent
in a vaporized state or a mixture thereof.
30. The method of claim 29, wherein the solvent is one of a group
of ethane, propane, butane or a mixture thereof.
31. The method of claim 29, wherein the solvent is mixed with a
diluent gas.
32. The method of claim 31, wherein the diluent gas is
non-condensable under the process conditions.
33. The method of claim 32, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbon deposit liquid than the
saturated hydrocarbon solvent.
34. The method of claim 33, wherein the diluent gas is one of a
group of methane, nitrogen, carbon dioxide, natural gas or a
mixture thereof.
35. The method of claim 21, wherein the method includes injecting a
hydrogenizing gas into the wellbore and thus into the fluids in the
process zone to promote hydrogenation and thermal cracking
reactions of at least a portion of the petroleum fluids in the
process zone.
36. The method of claim 35, wherein the hydrogenising gas consists
of one of the group of H2 and CO or a mixture thereof.
37. The method of claim 35, wherein the method includes catalyzing
the hydrogenation and thermal cracking of at least a portion of the
petroleum fluids in the process zone.
38. The method of claim 37, wherein a metal-containing catalyst is
used to catalyze said hydrogenation and thermal cracking
reactions.
39. The method of claim 38, wherein the catalyst is contained in a
canister in tubing inside of the wellbore.
40. The method of claim 38, wherein the proppant particles in the
inclusions contain the catalyst for the hydrogenation and thermal
cracking reactions.
41. The method of claim 1, wherein a portion of the formation in
which the first inclusion is formed has a Skempton B parameter
greater than 0.95 exp(-0.04 p')+0.008 p', where p' is a mean
effective stress in MPa at the depth of the first inclusion and the
water saturation in the formation pores is greater or equal to
10%.
42. The method of claim 21, wherein a portion of the formation in
which the first inclusion is formed has a Skempton B parameter
greater than 0.95 exp(-0.04 p')+0.008 p', where p' is a mean
effective stress in MPa at the depth of the first inclusion and the
water saturation in the formation pores is greater or equal to
10%.
43. A production well system for improving production of
hydrocarbon liquids from a subterranean formation of weakly
cemented sediments having an ambient reservoir pressure and
temperature comprising: a) a substantially vertical central bore
hole in the formation to a predetermined depth; b) an injection
casing grouted in the central bore hole depth to create a
substantially vertical central wellbore, the injection casing being
radially expandable by the introduction of a fluid; c) a
substantially vertical first inclusion created by injecting a fluid
filled with proppant particles into the formation in a first
preferential direction having an azimuth from the substantially
vertical central wellbore intersecting the formation; d) a
substantially vertical circumferential bore hole in the formation
to a predetermined depth; e) an injection casing grouted in the
circumferential bore hole depth to create a substantially vertical
circumferential wellbore, the injection casing being radially
expandable by the introduction of a fluid; f) a substantially
vertical second inclusion created by injecting the fluid filled
with proppant particles from the circumferential wellbore, the
second inclusion oriented in the same but opposite preferential
direction as the first inclusion and oriented to intersect and
coalesce with the first vertical inclusion in the same formation
after the viscosity of the injected fluid in the first inclusion
has substantially reduced, wherein the first inclusion and the
second inclusion to form a process zone; and g) means for injecting
steam into the central wellbore and into the process zone in the
formation, thereby producing heated hydrocarbon liquids up the
wellbores.
44. The production well system of claim 43, wherein the production
well system includes a plurality of first and second inclusions at
varying azimuths and a plurality of circumferential wellbores at
the same varying azimuths.
45. The production well system of claim 43, wherein the production
well system includes a plurality of inclusions propagated from the
central and circumferential wellbores at progressively shallower
depths after the viscosity of the injected fluid in the immediate
lower inclusion has reduced substantially, so that the shallower
depth inclusions intersect and coalesce with the inclusions
immediately beneath on their respective azimuths.
46. The production well system of claim 45, wherein the production
well system includes propagating a plurality of inclusions at
varying azimuths and a plurality of circumferential wellbores at
the same varying azimuths.
47. The production well system of claim 43, wherein the proppant
particles ranging in size from #4 to #100 U.S. mesh are sand,
ceramic beads, resin coated sand, and resin coated ceramic beads or
mixture thereof.
48. The production well system of claim 43, wherein the means for
injecting the steam injects the steam continuously, and the
production of hydrocarbon liquids is also continuous.
49. The production well system of claim 43, wherein the means for
injecting the steam injects the steam intermittently as a pressure
pulsed cycle.
50. The production well system of claim 43, wherein steam pressure
in the process zone is at ambient reservoir pressure.
51. The production well system of claim 43, wherein the production
well system includes means for injecting into the process zone a
non-condensing gas, a hydrocarbon solvent in a vaporized state, or
a mixture thereof.
52. The production well system of claim 51, wherein the solvent is
one of a group of ethane, propane, butane, or a mixture
thereof.
53. The production well system of claim 51, wherein the solvent is
mixed with a diluent gas.
54. The production well system of claim 53, wherein the diluent gas
is non-condensable under the process conditions.
55. The production well system of claim 54, wherein the
non-condensable diluent gas has a lower solubility in the
hydrocarbon liquid than the saturated hydrocarbon solvent.
56. The production well system of claim 55, wherein the diluent gas
is one of a group of methane, nitrogen, carbon dioxide, natural
gas, or a mixture thereof.
57. The production well system of claim 43, wherein the production
well system includes means for injecting a hydrogenizing gas into
the central wellbore and thus into the fluids in the process zone
to promote hydrogenation and thermal cracking reactions of at least
a portion of the hydrocarbon fluids in the process zone.
58. The production well system of claim 57, wherein the
hydrogenising gas consists of one of the group of H2 and CO or a
mixture thereof.
59. The production well system of claim 57, wherein the production
well system includes means for catalyzing the hydrogenation and
thermal cracking reactions of at least a portion of the petroleum
fluids in the process zone.
60. The production well system of claim 59, wherein a
metal-containing catalyst is used to catalyze said hydrogenation
and thermal cracking reactions.
61. The production well system of claim 60, wherein the catalyst is
contained in a canister in tubing inside of the central
wellbore.
62. The production well system of claim 60, wherein the proppant
particles in the inclusions contain the catalyst for the
hydrogenation and thermal cracking reactions.
63. A production well system for improving production of
hydrocarbon liquids from a subterranean formation of weakly
cemented sediments having an ambient reservoir pressure and
temperature comprising: a) a substantially vertical central bore
hole in the formation to a predetermined depth; b) an injection
casing grouted in the central bore hole depth to create a
substantially vertical central wellbore, the injection casing being
radially expandable by the introduction of a fluid; c) a
substantially vertical circumferential relief bore hole in the
formation to a predetermined depth; d) an injection casing grouted
in the circumferential relief bore hole depth to create a
substantially vertical circumferential relief wellbore, the
injection casing being radially expandable by the introduction of a
fluid; e) a substantially vertical first inclusion created by
injecting a fluid filled with proppant particles into the formation
in a first preferential direction at an azimuth from the
substantially vertical central wellbore intersecting the formation,
wherein the substantially vertical first inclusion intersects the
circumferential relief wellbore operated at a reduced pressure and
on azimuth with the first inclusion form a process zone; and f)
means for injecting steam into the central wellbore and into the
process zone in the formation, thereby producing the heated
hydrocarbon liquids up the wellbores.
64. The production well system of claim 63, wherein the production
well system includes a plurality of first inclusions at varying
azimuths and a plurality of circumferential relief wellbores at the
same varying azimuths.
65. The production well system of claim 63, wherein the production
well system includes a plurality of inclusions propagated from the
central wellbore at progressively shallower depths after the
viscosity of the injected fluid in the immediately lower inclusion
has substantially reduced, so that the shallower depth inclusions
intersect and coalesce with the inclusions immediately beneath on
their respective azimuths.
66. The production well system of claim 65, wherein the production
well system includes propagating a plurality of inclusions at
varying azimuths and a plurality of circumferential relief
wellbores at the same varying azimuths.
67. The production well system of claim 63, wherein the proppant
particles ranging in size from #4 to #100 U.S. mesh are sand,
ceramic beads, resin coated sand, and resin coated ceramic beads or
mixture thereof.
68. The production well system of claim 63, wherein the means for
injecting the steam injects the steam continuously, and the
production of hydrocarbon liquids is also continuous.
69. The production well system of claim 63, wherein the means for
injecting the steam injects the steam intermittently as a pressure
pulsed cycle.
70. The production well system of claim 63, wherein steam pressure
in the process zone is at ambient reservoir pressure.
71. The production well system of claim 63, wherein the production
well system includes means for injecting into the process zone a
non-condensing gas, a hydrocarbon solvent in a vaporized state, or
a mixture thereof.
72. The production well system of claim 71, wherein the solvent is
one of a group of ethane, propane, butane, or a mixture
thereof.
73. The production well system of claim 71, wherein the solvent is
mixed with a diluent gas.
74. The production well system of claim 73, wherein the diluent gas
is non-condensable under the process conditions.
75. The production well system of claim 74, wherein the
non-condensable diluent gas has a lower solubility in the
hydrocarbon deposit liquid than the saturated hydrocarbon
solvent.
76. The production well system of claim 75, wherein the diluent gas
is one of a group of methane, nitrogen, carbon dioxide, natural
gas, or a mixture thereof.
77. The production well system of claim 63, wherein the production
well system includes means for injecting a hydrogenizing gas into
the wellbore and thus into the fluids in the process zone to
promote hydrogenation and thermal cracking reactions of at least a
portion of the petroleum fluids in the process zone.
78. The production well system of claim 77, wherein the
hydrogenising gas consists of one of the group of H2 and CO or a
mixture thereof.
79. The production well system of claim 77, wherein the production
well system includes means for catalyzing the hydrogenation and
thermal cracking of at least a portion of the petroleum fluids in
the process zone.
80. The production well system of claim 79, wherein a
metal-containing catalyst is used to catalyze said hydrogenation
and thermal cracking reactions.
81. The production well system of claim 80, wherein the catalyst is
contained in a canister in tubing inside of the wellbore.
82. The production well system of claim 80, wherein the proppant
particles in the inclusions contain the catalyst for the
hydrogenation and thermal cracking reactions.
83. The production well system of claim 43, wherein a portion of
the formation in which the first inclusion is formed has a Skempton
B parameter greater than 0.95 exp(-0.04 p')+0.008 p', where p' is a
mean effective stress in MPa at the depth of the first inclusion
and the water saturation in the formation pores is greater or equal
to 10%.
Description
TECHNICAL FIELD
[0001] The present invention generally relates to enhanced recovery
of petroleum fluids from the subsurface by steam injection into
permeable propped vertical inclusions, thereupon heating the oil
sand formation and the viscous heavy oil and bitumen in situ, with
steam injection and liquid production both being continuous
processes, resulting in increased production of petroleum fluids
from the subsurface formation. Steam is injected in a central well,
and liquids are produced from the central and periphery wells. By
operating the process at near ambient reservoir pressure, minimizes
water inflow into the heated zone and well bore,
BACKGROUND OF THE INVENTION
[0002] Heavy oil and bitumen oil sands are abundant in reservoirs
in many parts of the world such as those in Alberta, Canada, Utah
and California in the United States, the Orinoco Belt of Venezuela,
Indonesia, China and Russia. The hydrocarbon reserves of the oil
sand deposit is extremely large in the trillions of barrels, with
recoverable reserves estimated by current technology in the 300
billion barrels for Alberta, Canada and a similar recoverable
reserve for Venezuela. These vast heavy oil (defined as the liquid
petroleum resource of less than 20.degree. API gravity) deposits
are found largely in unconsolidated sandstones, being high porosity
permeable cohensionless sands with minimal grain to grain
cementation. The hydrocarbons are extracted from the oils sands
either by mining or in situ methods.
[0003] The heavy oil and bitumen in the oil sand deposits have high
viscosity at reservoir temperatures and pressures. While some
distinctions have arisen between tar or oil sands, bitumen and
heavy oil, these terms will be used interchangeably herein. The oil
sand deposits in Alberta, Canada extend over many square miles and
vary in thickness up to hundreds of feet thick. Although some of
these deposits lie close to the surface and are suitable for
surface mining, the majority of the deposits are at depth ranging
from a shallow depth of 150 feet down to several thousands of feet
below ground surface. The oil sands located at these depths
constitute some of the world's largest presently known petroleum
deposits. The oil sands contain a viscous hydrocarbon material,
commonly referred to as bitumen, in an amount that ranges up to 15%
by weight. Bitumen is effectively immobile at typical reservoir
temperatures. For example at 15.degree. C., bitumen has a viscosity
of .about.1,000,000 centipoise. However at elevated temperatures
the bitumen viscosity changes considerably to be .about.350
centipoise at 100.degree. C. down to .about.10 centipoise at
180.degree. C. The oil sand deposits have an inherently high
permeability ranging from .about.1 to 10 Darcy, thus upon heating,
the heavy oil becomes mobile and can easily drain from the
deposit.
[0004] Solvents applied to the bitumen soften the bitumen and
reduce its viscosity and provide a non-thermal mechanism to improve
the bitumen mobility. Hydrocarbon solvents consist of vaporized
light hydrocarbons such as ethane, propane or butane or liquid
solvents such as pipeline diluents, natural condensate streams or
fractions of synthetic crudes. The diluent can be added to steam
and flashed to a vapor state or be maintained as a liquid at
elevated temperature and pressure, depending on the particular
diluent composition. While in contact with the bitumen, the
saturated solvent vapor dissolves into the bitumen. This diffusion
process is due to the partial pressure difference between the
saturated solvent vapor and the bitumen. As a result of the
diffusion of the solvent into the bitumen, the oil in the bitumen
becomes diluted and mobile and will flow under gravity. The
resultant mobile oil may be deasphalted by the condensed solvent,
leaving the heavy asphaltenes behind within the oil sand pore space
with little loss of inherent fluid mobility in the oil sands due to
the small weight percent (5-15%) of the asphaltene fraction to the
original oil in place. Deasphalting the oil from the oil sands
produces a high grade quality product by 3.degree.-5.degree. API
gravity. If the reservoir temperature is elevated the diffusion
rate of the solvent into the bitumen is raised considerably being
two orders of magnitude greater at 100.degree. C. compared to
ambient reservoir temperatures of .about.15.degree. C.
[0005] In situ methods of hydrocarbon extraction from the oil sands
consist of cold production, in which the less viscous petroleum
fluids are extracted from vertical and horizontal wells with sand
exclusion screens, CHOPS (cold heavy oil production system) cold
production with sand extraction from vertical and horizontal wells
with large diameter perforations thus encouraging sand to flow into
the well bore, CSS (cyclic steam stimulation) a huff and puff
cyclic steam injection system with gravity drainage of heated
petroleum fluids using vertical and horizontal wells, steamflood
using injector wells for steam injection and producer wells on 5
and 9 point layout for vertical wells and combinations of vertical
and horizontal wells, SAGD (steam assisted gravity drainage) steam
injection and gravity production of heated hydrocarbons using two
horizontal wells, VAPEX (vapor assisted petroleum extraction)
solvent vapor injection and gravity production of diluted
hydrocarbons using horizontal wells, and combinations of these
methods.
[0006] Cyclic steam stimulation and steamflood hydrocarbon enhanced
recovery methods have been utilized worldwide, beginning in 1956
with the discovery of CSS, huff and puff or steam-soak in Mene
Grande field in Venezuela and for steamflood in the early 1960s in
the Kern River field in California. These steam assisted
hydrocarbon recovery methods including a combination of steam and
solvent are described in U.S. Pat. No. 3,739,852 to Woods et al,
U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to
McMillen, U.S. Pat. No. 4,697,642 to Vogel, and U.S. Pat. No.
6,708,759 to Leaute et al. The CSS process raises the steam
injection pressure above the formation fracturing pressure to
create fractures within the formation and enhance the surface area
access of the steam to the bitumen. Successive steam injection
cycles reenter earlier created fractures and thus the process
becomes less efficient over time. CSS is generally practiced in
vertical wells, but systems are operational in horizontal wells,
but have complications due to localized fracturing and steam entry
and the lack of steam flow control along the long length of the
horizontal well bore.
[0007] Descriptions of the SAGD process and modifications are
described in U.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No.
5,215,146 to Sanchez and thermal extraction methods in U.S. Pat.
No. 4,085,803 to Butler, U.S. Pat. No. 4,099,570 to Vandergrift,
and U.S. Pat. No. 4,116,275 to Butler et al. The SAGD process
consists of two horizontal wells at the bottom of the hydrocarbon
formation, with the injector well located approximately 10-15 feet
vertically above the producer well. The steam injection pressures
exceed the formation fracturing pressure in order to establish
connection between the two wells and develop a steam chamber in the
oil sand formation. Similar to CSS, the SAGD method has
complications, albeit less severe than CSS, due to the lack of
steam flow control along the long section of the horizontal well
and the difficulty of controlling the growth of the steam
chamber.
[0008] A thermal steam extraction process referred to a HASDrive
(heated annulus steam drive) and modifications thereof heat and
hydrogenate the heavy oils insitu in the presence of a metal
catalyst. See U.S. Pat. No. 3,994,340 to Anderson et al., U.S. Pat.
No. 4,696,345 to Hsueh, U.S. Pat. No. 4,706,751 to Gondouin, U.S.
Pat. No. 5,054,551 to Duerksen, and U.S. Pat. No. 5,145,003 to
Duerksen. It is disclosed that at elevated temperature and pressure
the injection of hydrogen or a combination of hydrogen and carbon
monoxide to the heavy oil in situ in the presence of a metal
catalyst will hydrogenate and thermal crack at least a portion of
the petroleum in the formation.
[0009] Thermal recovery processes using steam require large amounts
of energy to produce the steam, using either natural gas or heavy
fractions of produced synthetic crude. Burning these fuels
generates significant quantities of greenhouse gases, such as
carbon dioxide. Also, the steam process uses considerable
quantities of water, which even though may be reprocessed, involves
recycling costs and energy use. Therefore a less energy intensive
oil recovery process is desirable.
[0010] Solvents applied to the bitumen soften the bitumen and
reduce its viscosity and provide a non-thermal mechanism to improve
the bitumen mobility. Hydrocarbon solvents consist of vaporized
light hydrocarbons such as ethane, propane or butane or liquid
solvents such as pipeline diluents, natural condensate streams or
fractions of synthetic crudes. The diluent can be added to steam
and flashed to a vapor state or be maintained as a liquid at
elevated temperature and pressure, depending on the particular
diluent composition. While in contact with the bitumen, the
saturated solvent vapor dissolves into the bitumen. This diffusion
process is due to the partial pressure difference in the saturated
solvent vapor and the bitumen. As a result of the diffusion of the
solvent into the bitumen, the oil in the bitumen becomes diluted
and mobile and will flow under gravity. The resultant mobile oil
may be deasphalted by the condensed solvent, leaving the heavy
asphaltenes behind within the oil sand pore space with little loss
of inherent fluid mobility in the oil sands due to the small weight
percent (5-15%) of the asphaltene fraction to the original oil in
place. Deasphalting the oil from the oil sands produces a high
grade quality product by 3.degree.-5.degree. API gravity. If the
reservoir temperature is elevated the diffusion rate of the solvent
into the bitumen is raised considerably being two orders of
magnitude greater at 100.degree. C. compared to ambient reservoir
temperatures of .about.15.degree. C.
[0011] Solvent assisted recovery of hydrocarbons in continuous and
cyclic modes are described including the VAPEX process and
combinations of steam and solvent plus heat. See U.S. Pat. No.
4,450,913 to Allen et al, U.S. Pat. No. 4,513,819 to Islip et al,
U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to
Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No.
6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Lim et al, and U.S.
Pat. No. 6,883,607 to Nenniger et al. The VAPEX process generally
consists of two horizontal wells in a similar configuration to
SAGD; however, there are variations to this including spaced
horizontal wells and a combination of horizontal and vertical
wells. The startup phase for the VAPEX process can be lengthy and
take many months to develop a controlled connection between the two
wells and avoid premature short circuiting between the injector and
producer. The VAPEX process with horizontal wells has similar
issues to CSS and SAGD in horizontal wells, due to the lack of
solvent flow control along the long horizontal well bore, which can
lead to non-uniformity of the vapor chamber development and growth
along the horizontal well bore.
[0012] Direct heating and electrical heating methods for enhanced
recovery of hydrocarbons from oil sands and oil shales have been
disclosed in combination with steam, hydrogen, catalysts and/or
solvent injection at temperatures to ensure the petroleum fluids
gravity drain from the formation and at significantly higher
temperatures (3000 to 4000 range and above) to pyrolysis the oil
shales. See U.S. Pat. No. 2,780,450 to Ljungstrom, U.S. Pat. No.
4,597,441 to Ware et al, U.S. Pat. No. 4,926,941 to Glandt et al,
U.S. Pat. No. 5,046,559 to Glandt, U.S. Pat. No. 5,060,726 to
Glandt et al, U.S. Pat. No. 5,297,626 to Vinegar et al, U.S. Pat.
No. 5,392,854 to Vinegar et al, U.S. Pat. No. 6,722,431 to
Karanikas et al. In situ combustion processes have also been
disclosed see U.S. Pat. No. 5,211,230 to Ostapovich et al, U.S.
Pat. No. 5,339,897 to Leaute, U.S. Pat. No. 5,413,224 to Laali, and
U.S. Pat. No. 5,954,946 to Klazinga et al.
[0013] In situ processes involving downhole heaters are described
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. Electrical
heaters are described for heating viscous oils in the forms of
downhole heaters and electrical heating of tubing and/or casing,
see U.S. Pat. No. 2,548,360 to Germain, U.S. Pat. No. 4,716,960 to
Eastlund et al, U.S. Pat. No. 5,060,287 to Van Egmond, U.S. Pat.
No. 5,065,818 to Van Egmond, U.S. Pat. No. 6,023,554 to Vinegar and
U.S. Pat. No. 6,360,819 to Vinegar. Flameless downhole combustor
heaters are described, see 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.
Surface fired heaters or surface burners may be used to heat a heat
transferring fluid pumped downhole to heat the formation as
described in U.S. Pat. No. 6,056,057 to Vinegar et al and U.S. Pat.
No. 6,079,499 to Mikus et al.
[0014] The thermal and solvent methods of enhanced oil recovery
from oil sands, all suffer from a lack of surface area access to
the in place bitumen. Thus the reasons for raising steam pressures
above the fracturing pressure in CSS and during steam chamber
development in SAGD, are to increase surface area of the steam with
the in place bitumen. Similarly the VAPEX process is limited by the
available surface area to the in place bitumen, because the
diffusion process at this contact controls the rate of softening of
the bitumen. Likewise during steam chamber growth in the SAGD
process the contact surface area with the in place bitumen is
virtually a constant, thus limiting the rate of heating of the
bitumen. Therefore both methods (heat and solvent) or a combination
thereof would greatly benefit from a substantial increase in
contact surface area with the in place bitumen. Hydraulic
fracturing of low permeable reservoirs has been used to increase
the efficiency of such processes and CSS methods involving
fracturing are described in U.S. Pat. No. 3,739,852 to Woods et al,
U.S. Pat. No. 5,297,626 to Vinegar et al, and U.S. Pat. No.
5,392,854 to Vinegar et al. Also during initiation of the SAGD
process overpressurized conditions are usually imposed to
accelerate the steam chamber development, followed by a prolonged
period of underpressurized condition to reduce the steam to oil
ratio. Maintaining reservoir pressure during heating of the oil
sands has the significant benefit of minimizing water inflow to the
heated zone and to the well bore.
[0015] Electrical resistive heating of oil shale and oil sand
formations utilizing a hydraulic fracture filled with an
electrically conductive material are described in U.S. Pat. No.
3,137,347 to Parker, involving a horizontal hydraulic fracture
filled with conductive proppant and with the use of two (2) wells
to electrically energizing the fracture and raise the temperature
of the oil shale to pyrolyze the organic matter and produce
hydrocarbon from a third well, in U.S. Pat. No. 5,620,049 to Gipson
et al. with a single well configuration in a hydrocarbon formation
predominantly a vertical fracture filled with conductive
temperature setting resin coated proppant and the electric current
passes through the conductive proppant to a surface ground and the
single well is completed to raise the temperature of the oil
in-situ to reduce its viscosity and produce hydrocarbons from the
same well, in U.S. Pat. No. 6,148,911 to Gipson et al. with a
single well configuration in a gas hydrate formation with
predominantly a horizontal fracture filled with conductive proppant
and the electric current passes through the conductive proppant to
a surface ground, raising the temperature of the formation to
release the methane from the gas hydrates and the single well is
completed for methane production, in U.S. Pat. No. 7,331,385 to
Symington et al. in U.S. Pat. No. 7,631,691 to Symington et al. and
in Canadian Patent No. 2,738,873 to Symington et al. all with a
predominantly vertical fracture filled with conductive proppant and
the conductive fracture is electrically energized by contact with
at least two (2) wells or in the case of a single well presumably
through the well and surface ground with the oil shale raised to a
temperature to pyrolyze the organic matter into producible
hydrocarbons, with the electrically conductive fracture composed of
electrically conductive proppant and non-electrically conductive
non-permeable cement. The single well systems described above all
suffer from low efficiency and high energy loss due to the current
passes through a significant distance of the formation from the
conductive fracture to the surface ground. Also the systems with
two or more wellbores do not disclosed how the electrode to
conductive fracture contact will be other than a point contact
resulting in significant energy loss and overheating at such a
contact.
[0016] It is well known that extensive heavy oil reservoirs are
found in formations comprising unconsolidated, weakly cemented
sediments. Unfortunately, the methods currently used for extracting
the heavy oil from these formations have not produced entirely
satisfactory results. Heavy oil is not very mobile in these
formations, and so it would be desirable to be able to form
increased permeability planes in the formations and by injecting
steam into these planes, heating the formation and thus increase
the mobility of the heavy oil in the formation and by drainage
through the permeable planes to the wellbore for production up the
well. Steam injection into multiple azimuth vertical permeables
planes has been disclosed earlier in U.S. Pat. No. 7,591,306 to
Hocking; however the method cited is for a single well being both a
steam injector and liquids producer, whereas the current invention
contains multiple wells with the significant advantage of much
faster production and lower SOR.
[0017] However, techniques used in hard, brittle rock to form
fractures therein are typically not applicable to ductile
formations comprising unconsolidated, weakly cemented sediments.
The method of controlling the azimuth of a vertical hydraulic
planar inclusion in formations of unconsolidated or weakly cemented
soils and sediments by slotting the well bore or installing a
pre-slotted or weakened casing at a predetermined azimuth has been
disclosed. The method disclosed that a vertical hydraulic planar
inclusion can be propagated at a pre-determined azimuth in
unconsolidated or weakly cemented sediments and that multiple
orientated vertical hydraulic planar inclusions at differing
azimuths from a single well bore can be initiated and propagated
for the enhancement of petroleum fluid production from the
formation. See U.S. Pat. No. 6,216,783 to Hocking et al, U.S. Pat.
No. 6,443,227 to Hocking et al, U.S. Pat. No. 6,991,037 to Hocking,
U.S. Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to
Cavender et al., U.S. Pat. No. 7,640,982 to Schultz et al., U.S.
Pat. No. 7,748,458 to Hocking, U.S. Pat. No. 7,814,978 to Steele et
al., U.S. Pat. No. 7,832,477 to Cavender et al., U.S. Pat. No.
7,866,395 to Hocking, U.S. Pat. No. 7,950,456 to Cavender et al.,
U.S. Pat. No. 8,151,874 to Schultz et al. The method disclosed that
a vertical hydraulic planar inclusion can be propagated at a
pre-determined azimuth in unconsolidated or weakly cemented
sediments and that multiple orientated vertical hydraulic planar
inclusions at differing azimuths from a single well bore can be
initiated and propagated for the enhancement of petroleum fluid
production from the formation. It is now known that unconsolidated
or weakly cemented sediments behave substantially different from
brittle rocks from which most of the hydraulic fracturing
experience is founded.
[0018] The methods disclosed above find especially beneficial
application in ductile rock formations made up of unconsolidated or
weakly cemented sediments, in which it is typically very difficult
to obtain directional or geometric control over inclusions as they
are being formed. Weakly cemented sediments are primarily
frictional materials since they have minimal cohesive strength. An
uncemented sand having no inherent cohesive strength (i.e., no
cement bonding holding the sand grains together) cannot contain a
stable crack within its structure and cannot undergo brittle
fracture. Such materials are categorized as frictional materials
which fail under shear stress, whereas brittle cohesive materials,
such as strong rocks, fail under normal stress.
[0019] The term "cohesion" is used in the art to describe the
strength of a material at zero effective mean stress. Weakly
cemented materials may appear to have some apparent cohesion due to
suction or negative pore pressures created by capillary attraction
in fine grained sediment, with the sediment being only partially
saturated. These suction pressures hold the grains together at low
effective stresses and, thus, are often called apparent
cohesion.
[0020] The suction pressures are not true bonding of the sediment's
grains, since the suction pressures would dissipate due to complete
saturation of the sediment. Apparent cohesion is generally such a
small component of strength that it cannot be effectively measured
for strong rocks, and only becomes apparent when testing very
weakly cemented sediments.
[0021] Geological strong materials, such as relatively strong rock,
behave as brittle materials at normal petroleum reservoir depths,
but at great depth (i.e. at very high confining stress) or at
highly elevated temperatures, these rocks can behave like ductile
frictional materials. Unconsolidated sands and weakly cemented
formations behave as ductile frictional materials from shallow to
deep depths, and the behavior of such materials are fundamentally
different from rocks that exhibit brittle fracture behavior.
Ductile frictional materials fail under shear stress and consume
energy due to frictional sliding, rotation and displacement.
[0022] Conventional hydraulic dilation of weakly cemented sediments
is conducted extensively on petroleum reservoirs as a means of sand
control. The procedure is commonly referred to as "Frac-and-Pack."
In a typical operation, the casing is perforated over the formation
interval intended to be fractured and the formation is injected
with a treatment fluid of low gel loading without proppant, in
order to form the desired two winged structure of a fracture. Then,
the proppant loading in the treatment fluid is increased
substantially to yield tip screen-out of the fracture. In this
manner, the fracture tip does not extend further, and the fracture
and perforations are backfilled with proppant.
[0023] The process assumes a two winged fracture is formed as in
conventional brittle hydraulic fracturing. However, such a process
has not been duplicated in the laboratory or in shallow field
trials. In laboratory experiments and shallow field trials what has
been observed is chaotic geometries of the injected fluid, with
many cases evidencing cavity expansion growth of the treatment
fluid around the well and with deformation or compaction of the
host formation.
[0024] Weakly cemented sediments behave like a ductile frictional
material in yield due to the predominantly frictional behavior and
the low cohesion between the grains of the sediment. Such materials
do not "fracture" and, therefore, there is no inherent fracturing
process in these materials as compared to conventional hydraulic
fracturing of strong brittle rocks.
[0025] Linear elastic fracture mechanics is not generally
applicable to the behavior of weakly cemented sediments. The
knowledge base of propagating viscous planar inclusions in weakly
cemented sediments is primarily from recent experience over the
past ten years and much is still not known regarding the process of
viscous fluid propagation in these sediments.
[0026] Accordingly, there is a need for a method and apparatus for
enhancing the extraction of hydrocarbons from oil sands in a single
well and in multiple wells by steam injection into permeable
vertical inclusions combined with gas and/or solvent injection or a
mixture thereof and controlling the subsurface environment, both
temperature and pressure to optimize the hydrocarbon extraction in
terms of produced rate, efficiency and produced product quality, as
well as limit water inflow into the process zone.
SUMMARY OF THE INVENTION
[0027] The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by injecting steam
into multiple vertical inclusion planes containing proppant in the
oil sand formation and thus heating the heavy oil and bitumen,
which drain under gravity and are produced to the surface. In one
embodiment of this invention, multiple propped vertical inclusions
are constructed at various azimuths from a central well and
propagate into the oil sand formation and filled with a proppant.
The vertical inclusions are propagated to intersect and connect
with circumferential wells, on azimuth and depth from the central
well. Additional vertical inclusions filled with the same proppant
are initiated in the central well at progressively shallower depths
but on azimuth with the lower propped inclusions, such that they
propagate laterally and vertical into the formation and intersect
and coalesce with the lower inclusions, and intersect the on
azimuth circumference well. Steam is injected in the central well,
heating the inclusions and oil sand formation, lowering the
viscosity of the heavy oil and bitumen, which flows by gravity to
all wells, where it is produced to the surface.
[0028] In another embodiment multiple propped vertical inclusions
are constructed at various azimuths from a central well and
propagate into the oil sand formation and filled with a proppant.
Vertical inclusions filled with the same proppant are constructed
from circumferential wells, on azimuth and depth to intersect and
coalesce with the inclusions from the central well. Additional
vertical inclusions filled with the same proppant are initiated in
the central well at progressively shallower depths but on azimuth
with the lower propped inclusions, such that they propagate
laterally and vertical into the formation and intersect and
coalesce with the lower inclusions. Additional vertical inclusions
filled with the same proppant are initiated in the circumferential
wells at progressively shallower depths but on azimuth with the
lower propped inclusions, such that they propagate laterally and
vertical into the formation and intersect and coalesce both with
the lower inclusion and the inclusions from the central well. Steam
is injected in the central well, heating the inclusions and oil
sand formation, lowering the viscosity of the heavy oil and
bitumen, which flows by gravity to all wells, where it is produced
to the surface.
[0029] The heating of the formation and in place heavy oil and
bitumen is via the condensing steam and in order to limit loss of
heat by conduction to overlying formations, a non condensing gas
can be injected to remain in the uppermost portions of the heated
process zone. The steam injection is planned to be continuous at
near ambient reservoir pressures to limit water inflow into the
heated zone, with the continuous extraction of liquids.
[0030] Although the present invention contemplates the formation of
vertical propped inclusions which generally extend laterally away
from a vertical or near vertical well penetrating an earth
formation and in a generally vertical plane, those skilled in the
art will recognize that the invention may be carried out in earth
formations wherein the fractures and the well bores can extend in
directions other than vertical.
[0031] Therefore, the present invention provides a method and
apparatus for enhanced recovery of petroleum fluids from the
subsurface by steam injection into propped permeable inclusions,
thereupon heating the oil sand formation and the viscous heavy oil
and bitumen in situ, which drain under gravity and are produced to
the surface.
[0032] Other objects, features and advantages of the present
invention will become apparent upon reviewing the following
description of the preferred embodiments of the invention, when
taken in conjunction with the drawings and the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0033] FIG. 1 is a schematic isometric view of a multiple well
system and associated method embodying principles of the present
invention with a central injection well and circumferential relief
wells;
[0034] FIG. 2 is a schematic isometric view of a multiple well
system and associated method embodying principles of the present
invention with a central injection well and circumferential
injection wells;
[0035] FIG. 3 is a schematic isometric view of the multiple well
system with a lower inclusion propagating towards a circumferential
relief well;
[0036] FIG. 4 is a schematic isometric view of the multiple well
system with a completed lower inclusion intersecting a
circumferential relief well;
[0037] FIG. 5 is a schematic isometric view of the multiple well
system completed with a lower inclusion, and an upper inclusion
propagating towards a circumferential relief well;
[0038] FIG. 6 is a schematic isometric view of the multiple well
system with completed lower and upper inclusions intersecting a
circumferential relief well;
[0039] FIG. 7 is a schematic isometric view of the multiple well
system with a first lower inclusion propagating towards a
circumferential injection well;
[0040] FIG. 8 is a schematic isometric view of the multiple well
system with the completed first lower inclusion, and a second lower
inclusion propagating from the circumferential injection well
towards the first inclusion;
[0041] FIG. 9 is a schematic isometric view of the multiple well
system with a completed lower inclusion, and an upper inclusion
propagating towards a circumferential injection well;
[0042] FIG. 10 is a schematic isometric view of the multiple well
system with completed lower and upper inclusions.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0043] Several embodiments of the present invention are described
below and illustrated in the accompanying drawings. The present
invention involves a method and apparatus for enhanced recovery of
petroleum fluids from the subsurface by steam injection into
propped vertical inclusions in the oil sand formation, and thus
heating the oil sand formation and the heavy oil and bitumen in
situ, and at much reduced viscosity the hydrocarbon flow by gravity
drainage to the wells and are produced to surface.
[0044] It is well known that extensive heavy oil reservoirs are
found in formations comprising unconsolidated, weakly cemented
sediments. Unfortunately, the methods currently used for extracting
the heavy oil from these formations have not produced entirely
satisfactory results. Heavy oil is not very mobile in these
formations, and so it would be desirable to be able to form
increased permeability planes in the formations and by injecting
steam into the permeable planes, heating the formation and in-situ
hydrocarbons and thus increase the mobility of the heavy oil in the
formation and by gravity drainage through the permeable planes to
the wellbore for production up the wells.
[0045] Representatively illustrated in FIG. 1 is a well system 10
and associated method which embody principles of the present
invention. The system 10 is particularly useful for producing heavy
oil 42 from a formation 14. The formation 14 may comprise
unconsolidated and/or weakly cemented sediments for which
conventional fracturing operations are not well suited. The term
"heavy oil" is used herein to indicate relatively high viscosity
and high density hydrocarbons, such as bitumen. Heavy oil is
typically not recoverable in its natural state (e.g., without
heating or diluting) via wells, and may be either mined or
recovered via wells through use of steam and solvent injection, in
situ combustion, etc. Gas-free heavy oil generally has a viscosity
of greater than 100 centipoise and a density of less than 20
degrees API gravity (greater than about 900 kilograms/cubic
meter).
[0046] As depicted in FIG. 1, a central vertical well has been
drilled into the formation 14 and the well casing 11 has been
cemented in the formation 14, and circumferential vertical wells
have been drilled into the formation and the well casings 16 have
been cemented into the formation 14. The term "casing" is used
herein to indicate a protective lining for a wellbore. Any type of
protective lining may be used, including those known to persons
skilled in the art as liner, casing, tubing, etc. Casing may be
segmented or continuous, jointed or unjointed, conductive or
non-conductive made of any material (such as steel, aluminum,
polymers, composite materials, etc.), and may be expanded or
unexpanded, etc.
[0047] The central well casing string 11 has an expansion device 12
and a sump section 13 interconnected therein. The circumferential
relief wells casing string 16 have an open section 15 and a sump
section 13 interconnected therein. The open section 15 could be a
perforated section of the casing, a screen, slotted liner, etc
providing hydraulic connection between the circumferential well and
the formation 14. The open section 15 of the well is maintained at
a lower pressure and independently of the injected fluid 22
pressure. The expansion device 12 operates to expand the casing
string 11 radially outward and thereby dilate the formation 14
proximate the device, in order to initiate forming of generally
vertical and planar inclusions 18 extending outwardly from the
wellbore at various azimuths. Suitable expansion devices for use in
the well system 10 are described in U.S. Pat. Nos. 6,216,783,
6,330,914, 6,443,227, 6,991,037, 7,404,441, 7,640,975, 7,640,982,
7,748,458, 7,814,978, 7,832,477, 7,866,395, 7,950,456 and
8,151,874. The entire disclosures of these prior patents are
incorporated herein by this reference. Other expansion devices may
be used in the well system 10 in keeping with the principles of the
invention.
[0048] Once the device 12 is operated to expand the casing string
11 radially outward, fluid 22 is forced into the dilated formation
14 to propagate the inclusions 18 into the formation. It is not
necessary for the inclusions 18 to be formed simultaneously. Shown
in FIG. 1 is an eight (8) wing inclusion well system 10, with eight
(8) inclusions 18 formed. The well system 10 does not necessarily
need to consist of eight (8) inclusions at the same depth
orientated at various azimuths, but could consist of one, two,
three, four, five, six or even seven vertical planar inclusions at
various azimuths at the same depth, with such choice of the number
of inclusions constructed depending on the application, formation
type and/or economic benefit. Also there is only one inclusion at a
particular azimuth, whereas there could be other upper inclusions
on the same azimuth, and in fact there could be numerous of these
upper inclusions at progressively shallower depths.
[0049] Typically, the lower inclusions 18 are constructed first,
with each wing of the eight (8) inclusions 18 injected
independently of the others. As the inclusions 18 are propagated
into the formation 14, the open section 15 of the on azimuth
circumferential well acts as a pore pressure sink and thus attracts
and accelerates the lateral propagation of the inclusion 18, so as
to intersect with the circumferential relief well, and thus stop
the lateral propagation of the inclusion. The formation 14, pore
space may contain a significant portion of immobile heavy oil or
bitumen generally up to a maximum oil saturation of 90%; however,
even at these very high oil saturations of 90%, i.e. very low water
saturation of 10%, the mobility of the formation pore water is
quite high, due to its viscosity and the formation permeability.
The open section 15 allows mobile formation pore fluids and the
injected fluid 22 to enter the relief well at 15 at a reduced
pressure, with 15 being at a lower pressure and independent of the
injected fluid 22 pressure. Upon the inclusions reaching the open
section 15, its lateral tip propagation will stop. The well system
10 is shown with inclusions 18 constructed at only a single depth,
this well system 10 is cited as only one example of the invention,
since there could be alternate forms of the invention containing
numerous of upper inclusions constructed at progressively shallower
depths, depending on the formation thickness, the distribution of
hydrocarbons within the formation 14, and/or economic benefit.
[0050] The injected fluid 22 carries the proppant to the extremes
of the inclusions 18. Upon propagation of the inclusions 18 to
their required lateral and vertical extent, the thickness of the
inclusions 18 may need to be increased by utilizing the process of
tip screen out. The tip screen out process involves modifying the
proppant loading and/or inject fluid 22 properties to achieve a
proppant bridge at the inclusion tips. The injected fluid 22 is
further injected after tip screen out, but rather then extending
the inclusion laterally or vertically, the injected fluid 22
widens, i.e. thickens, and fills the inclusion from the inclusion
tips back to the well bore.
[0051] The behavioral characteristics of the injected viscous fluid
22 are preferably controlled to ensure the propagating viscous
inclusions maintain their azimuth directionality, such that the
viscosity of the injected fluid 22 and its volumetric rate are
controlled within certain limits depending on the formation 14,
proppant 20 specific gravity and size distribution. For example,
the viscosity of the injected fluid 22 is preferably greater than
approximately 100 centipoise. However, if foamed fluid is used, a
greater range of viscosity and injection rate may be permitted
while still maintaining directional and geometric control over the
inclusions. The viscosity and volumetric rate of the injected fluid
22 needs to be sufficient to transport the proppant 20 to the
extremities of the inclusions. The size distribution of the
proppant 20 needs to be matched with that of the formation 14, to
ensure formation fines do not migrate into the propped pack
inclusion during hydrocarbon production. Typical size distribution
of the proppant would range from #12 to #20 U.S. Mesh for oil sand
formations, with an ideal proppant being sand or ceramic beads.
Ceramic beads coated with a resin such as phenol formaldehyde,
being heat hardenable, is capable of mechanically binding the
proppant together 21 in the presence of steam without loss of
permeability of the propped inclusion.
[0052] The well system 10, has steam injected 31 in the central
well through a vacuum insulated tubing 32 placed inside of the
casing 11. Heated heavy oil and bitumen will thus be mobilized and
flow under gravity through the inclusions and the formation towards
the wells and enter the sumps 13 and pumped to surface via a PCP
(progressive cavity pump), ESP (electrical submersible pump), gas
lift or natural lift 41, depending on operating temperatures,
pressures and depth, via a production tubing 40 in all of the
wells, both the central well and the circumferential wells.
[0053] The selected range of temperatures and pressures to operate
the process will depend on reservoir depth, ambient conditions,
quality of the in place heavy oil and bitumen, and the presence of
nearby water bodies. The process can be operated at a low
temperature range of .about.100.degree. C. for a heavy oil rich oil
sand deposit and at a moderate temperature range of
.about.150.degree.-180.degree. C. for a bitumen rich oil sand
deposit, basically to reduce the heavy oil and bitumen viscosity
and thus mobilized the in place oil. However, the process can be
operated at much higher temperatures >270.degree. C. to
pyrolysis the in place hydrocarbon in the presence of H.sub.2, CO
and/or catalysts. Thus the proppant could contain such catalysts,
or these catalysts could be incorporated into a canister in line
with the production tubing in the well. Such catalysts are really
available as HDS (hydrodesulfurization) metal containing catalysts,
and FCC (fluid catalytic cracking) rare earth aluminum silica
catalysts.
[0054] The operating pressure of the process may be selected to
closely match the ambient reservoir conditions to minimize water
inflow into the process zone and the well bore by the injection of
steam, gas or vaporized solvent. The process zone can be injected
with a vaporized hydrocarbon solvent, such as ethane, propane or
butane and mixed with a diluent gas, such as methane, nitrogen and
carbon dioxide. The solvent will contact the in situ bitumen at the
edge of the process zone, diffusive into and soften the bitumen, so
that it flows by gravity to the well bore. Dissolved solvent and
product hydrocarbon are produced and further solvent and diluent
gas injected into the process zone. The elevated temperature of the
process zone will significantly accelerate the diffusion process of
the solvent diffusing into the bitumen compared to ambient
reservoir conditions. The solvent and diluent gas will be injected
at near reservoir pressures to minimize water inflow into the
process zone. The solvent vapor in the injection gas is maintained
saturated at or near its dew point at the process operating
temperatures and pressures.
[0055] As depicted in FIG. 2, is an alternate configure of the well
system 10, with all wells being vertical injection wells as regards
proppant injection, drilled into the formation 14 and the central
well casing 11 has been cemented in the formation 14, and
circumferentially vertical wells have been drilled into the
formation 14 and the well casings 17 have been cemented into the
formation 14. In this configuration, typically the multiple propped
vertical inclusions 18 are constructed at various azimuths first
from the central well and propagate into the oil sand formation 14,
filled with a proppant, and the injection of the propagating fluid
22 is stopped when the inclusion is approximately midway between
the central well and its circumferential well. The fluid in the
lowermost inclusion 18 loses its viscosity over time due to
breakers placed in the injected fluid 22. Common breakers consist
of enzymes, catalyzed oxidizers, and organic acids. The formation
14, pore space may contain a significant portion of immobile heavy
oil or bitumen generally up to a maximum oil saturation of 90%;
however, even at these very high oil saturations of 90%, i.e. very
low water saturation of 10%, the mobility of the formation pore
water is quite high, due to its viscosity and the formation
permeability. Thus during propagation of the opposing inclusion 18'
from the circumferential well, the inclusion 18 pore fluid's
viscosity is low due to the action of the breaker, then inclusion
18 acts a large pore pressure sink, due to size, relative
permeability to the formation, mobility of its and the formation's
pore fluids, and hydraulic connection to the central well,
resulting in the intersection and coalescence of 18' and 18
irrespective of slight discrepancies in their azimuthal
orientations.
[0056] The well system 10 does not necessarily need to consist of
eight (8) inclusions at the same depth orientated at various
azimuths, but could consist of one, two, three, four, five, six or
even seven vertical planar inclusions at various azimuths at the
same depth, with such choice of the number of inclusions
constructed depending on the application, formation type and/or
economic benefit. Also there is only one inclusion at a particular
azimuth, whereas there could be other upper inclusions on the same
azimuth, and in fact there could be numerous of these upper
inclusions at progressively shallower depths.
[0057] The well system 10, has steam injected 31 in the central
well through a vacuum insulated tubing 32 placed inside of the
casing 11. Heated heavy oil and bitumen will thus be mobilized and
flow under gravity through the inclusions and the formation towards
the wells and enter the sumps 13 and pumped to surface via a PCP
(progressive cavity pump), ESP (electrical submersible pump), gas
lift or natural lift 41, depending on operating temperatures,
pressures and depth, via a production tubing 40 in all of the
wells, both the central well and the circumferential wells.
[0058] The formation 14 could be comprised of relatively hard and
brittle rock, but the system 10 and method find especially
beneficial application in ductile rock formations made up of
unconsolidated or weakly cemented sediments, in which it is
typically very difficult to obtain directional or geometric control
over inclusions as they are being formed.
[0059] However, the present disclosure provides information to
enable those skilled in the art of hydraulic fracturing, soil and
rock mechanics to practice a method and system 10 to initiate and
control the propagation of a viscous fluid in weakly cemented
sediments, and importantly for the propagating inclusion to
intersect and coalesce with earlier placed permeable inclusions and
thus form a continuous planar inclusion on a particular azimuth
from within a single well or between multiple wells.
[0060] The system and associated method are applicable to
formations of weakly cemented sediments with low cohesive strength
compared to the vertical overburden stress prevailing at the depth
of interest. Low cohesive strength is defined herein as no greater
than 3 MegaPasca (MPa) plus 0.4 times the mean effective stress
(p') in MPa at the depth of propagation.
c<3 MPa+0.4p' (1)
where c is cohesive strength in MPa and p' is mean effective stress
in the formation.
[0061] Examples of such weakly cemented sediments are sand and
sandstone formations, mudstones, shales, and siltstones, all of
which have inherent low cohesive strength. Critical state soil
mechanics assists in defining when a material is behaving as a
cohesive material capable of brittle fracture or when it behaves
predominantly as a ductile frictional material.
[0062] Weakly cemented sediments are also characterized as having a
soft skeleton structure at low effective mean stress due to the
lack of cohesive bonding between the grains. On the other hand,
hard strong stiff rocks will not substantially decrease in volume
under an increment of load due to an increase in mean stress.
[0063] In the art of poroelasticity, the Skempton B parameter is a
measure of a sediment's characteristic stiffness compared to the
fluid contained within the sediment's pores. The Skempton B
parameter is a measure of the rise in pore pressure in the material
for an incremental rise in mean stress under undrained
conditions.
[0064] In stiff rocks, the rock skeleton takes on the increment of
mean stress and thus the pore pressure does not rise, i.e.,
corresponding to a Skempton B parameter value of at or about 0. But
in a soft soil, the soil skeleton deforms easily under the
increment of mean stress and, thus, the increment of mean stress is
supported by the pore fluid under undrained conditions
(corresponding to a Skempton B parameter of at or about 1).
[0065] The following equations illustrate the relationships between
these parameters in equations denoted as (2) as follows:
.DELTA.u=B.DELTA.p
B=(K.sub.u-K)/(.alpha.K.sub.u)
.alpha.=1-(K/K.sub.s) (2)
where .DELTA.u is the increment of pore pressure, B the Skempton B
parameter, .DELTA.p the increment of mean stress, K.sub.u is the
undrained formation bulk modulus, K the drained formation bulk
modulus, .alpha. is the Biot-Willis poroelastic parameter, and
K.sub.s is the bulk modulus of the formation grains. In the system
and associated method, the bulk modulus K of the formation for
inclusion propagation is preferably less than approximately 5
GPa.
[0066] For use of the system 10 and method in weakly cemented
sediments, preferably the Skempton B parameter is as follows with
p' in MPa:
B>0.95 exp(-0.04p')+0.008p' (3)
The system and associated method are applicable to formations of
weakly cemented sediments (such as tight gas sands, mudstones and
shales) where large entensive propped vertical permeable drainage
planes are desired to intersect thin sand lenses and provide
drainage paths for greater gas production from the formations. In
weakly cemented formations containing heavy oil (viscosity>100
centipoise) or bitumen (extremely high viscosity>100,000
centipoise), generally known as oil sands, propped vertical
permeable drainage planes provide drainage paths for cold
production from these formations, and access for steam, solvents,
oils, and heat to increase the mobility of the petroleum
hydrocarbons and thus aid in the extraction of the hydrocarbons
from the formation. In highly permeable weak sand formations,
permeable drainage planes of large lateral length result in lower
drawdown of the pressure in the reservoir, which reduces the fluid
gradients acting towards the wellbore, resulting in less drag on
fines in the formation, resulting in reduced flow of formation
fines into the wellbore.
[0067] Proppant is carried by the injected fluid, resulting in a
highly permeable planar inclusion. Such proppants are typically
clean sand or specialized manufactured particles (generally ceramic
in composition), and depending on the size composition, closure
stress and proppant type, the permeability of the fracture can be
controlled. Either type of proppant could be resin coating to
provide for bounding between proppant particles 21 at elevated
temperatures and also to reduce the steam dissolution of the
particle over time. The permeability of the propped inclusions 18
will typically be orders of magnitude greater than the formation 14
permeability, generally at least by two orders of magnitude.
[0068] The injected fluid 22 varies depending on the application
and can be water, oil or multi-phased based gels. Aqueous based
fracturing fluids consist of a polymeric gelling agent such as
solvatable (or hydratable) polysaccharide, e.g. galactomannan gums,
glycomannan gums and cellulose derivatives. The purpose of the
hydratable polysaccharides is to thicken the aqueous solution and
thus act as viscosifiers, i.e. increase the viscosity by 100 times
or more over the base aqueous solution. A cross-linking agent can
be added which further increases the viscosity of the solution. The
borate ion has been used extensively as a cross-linking agent for
hydrated guar gums and other galactomannans, see U.S. Pat. No.
3,059,909 to Wise. Other suitable cross-linking agents are
chromium, iron, aluminum, and zirconium (see U.S. Pat. No.
3,301,723 to Chrisp) and titanium (see U.S. Pat. No. 3,888,312 to
Tiner et al). A breaker is added to the solution to controllably
degrade the viscous fracturing fluid. Common breakers are enzymes
and catalyzed oxidizer breaker systems, with weak organic acids
sometimes used.
[0069] An enlarged scale isometric view of the system 10 is
representatively illustrated in FIG. 3. This view depicts the
system 10 during the propagation of only one of the lowermost
inclusions 18, to provide a clearer description of the process used
to construct the system 10. The viscous fluid propagation process
in these sediments involves the unloading of the formation 14 in
the vicinity of the tips 23, 24, 25 of the propagating viscous
fluid 22, causing dilation of the formation 14, which generates
pore pressure gradients towards this dilating zone. As the
formation 14 dilates at the tips 23, 24, 25 of the advancing
viscous fluid 22, the pore pressure decreases dramatically at the
tips, resulting in increased pore pressure gradients surrounding
the tips.
[0070] The pore pressure gradients at the tips 23, 24, 25 of the
inclusion 18 result in the liquefaction, cavitation (degassing) or
fluidization of the formation 14 immediately surrounding the tips.
That is, the formation 14 in the dilating zone about the tips 23,
24, 25 acts like a fluid since its strength, fabric and in situ
stresses have been destroyed by the fluidizing process, and this
fluidized zone in the formation immediately ahead of the viscous
fluid 22 propagating tips 23, 24, 25 is a planar path of least
resistance for the viscous fluid to propagate further. In at least
this manner, the system 10 and associated method provide for
directional and geometric control over the advancing inclusions
18.
[0071] The behavioral characteristics of the injected viscous fluid
22 are preferably controlled to ensure the propagating viscous
fluid does not overrun the fluidized zone and lead to a loss of
control of the propagating process. Thus, the viscosity of the
fluid 22 and the volumetric rate of injection of the fluid should
be controlled to ensure that the conditions described above persist
while the inclusions 18 are being propagated through the formation
14. The propagation rate of the inclusion 18 due to the injected
fluid 22, varies depending on direction, in general due to
gravitation effects, the lateral tip 23 propagation rate is
generally much greater than the upward tip 24 propagation rate and
the downward tip 25 propagation rate. However, these tips 23, 24,
25 propagation rates can change due to heterogeneities in the
formation 14, pore pressure gradients especially associated with
pore pressure sinks, and stress, stiffness and strength contrasts
in the formation 14.
[0072] During propagation of the inclusion 18, the pore pressure in
the overall formation 14 will rise due to the injection of the
fluid 22. As the inclusion 18 propagates, the open section 15 of
the on azimuth circumferential relief well acts as a pore pressure
sink, and mobile formation pore fluids and injected fluid 22 flow
towards 15 as shown by 29. The open section 15 thus attracts and
accelerates the lateral tip 23 propagation rate of the inclusion
18. The inclusion 18 grows laterally towards the open section 15,
and upon reaching the relief well, the inclusion lateral tip
propagation stops.
[0073] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 4. The inclusion
18 has intersected the circumferential relief well and its lateral
propagation has stopped. By shutting in the circumferential relief
well, the inclusion 18 can be thickened if desired by the process
of tip screen-out.
[0074] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 5. This view
depicts the system 10 during the propagation of only one of the
uppermost inclusions 19, to provide a clearer description of the
process used to construct the system 10. The lowermost inclusion 18
has been constructed to its final dimension, and the fluid within
the inclusion 18 has lost its viscosity due to breakers placed in
the injected fluid 22. Common breakers consist of enzymes,
catalyzed oxidizers, and organic acids. The formation 14, pore
space may contain a significant portion of immobile heavy oil or
bitumen generally up to a maximum oil saturation of 90%; however,
even at these very high oil saturations of 90%, i.e. very low water
saturation of 10%, the mobility of the formation pore water is
quite high, due to its viscosity and the formation permeability.
Thus during propagation of the uppermost inclusion 19, and provided
the lowermost inclusion pore fluid's viscosity is low due to the
action of the breaker, then the lowermost inclusion 18 acts a large
pore pressure sink, due to size, relative permeability to the
formation, mobility of its and the formation's pore fluids, as does
the open section 15 in the circumferential relief well.
[0075] During propagation of the uppermost inclusion 19, the pore
pressure in the overall formation will rise due to the injection of
the fluid 22. The lowermost inclusion 18 will act as a pore
pressure sink and thus attract and accelerate the downward
propagating tip 28, and ensure that the propagating uppermost
inclusion 19 intersects and coalesces with the lowermost inclusion
18, even if there are slight discrepancies in their respective
azimuthal orientations. Upon coalescence of the downward
propagating tip 28 with the lowermost inclusion 18, the tip 28 will
stop propagating in the area of coalescence due to leakoff of the
injected fluid 22 to the highly permeable pore pressure sink,
inclusion 18. As the inclusion 19 further propagates, the open
section 15 of the on azimuth circumferential relief well acts as a
pore pressure sink, and mobile formation pore fluids and injected
fluid 22 flow towards 15 as shown by 29. The open section 15 thus
attracts and accelerates the lateral tip 26 propagation rate of the
inclusion 19. The inclusion 19 grows laterally towards the open
section 15, and upon reaching the relief well, the inclusion
lateral tip propagation stops. At completion of the injection of
fluid 22 in inclusions 19, the system 10 configuration will contain
continuous vertical coalescence of inclusions 18 with its
respective on azimuth inclusions 19.
[0076] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 6. The inclusion
19 has intersected and coalesced with the lower inclusion 18, and
intersected the circumferential relief well and thus its lateral
propagation has stopped. By shutting in the circumferential relief
well, the inclusion 19 can be thickened if desired by the process
of tip screen-out.
[0077] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 7 in an alternate
configuration. In this alternate configuration, the circumferential
well is an injection well and not a relief well as shown earlier in
FIG. 2. The lower inclusion 18 is propagating into the formation
and the injection fluid 22 flow rate is stopped when the inclusion
is approximately midway between the central well and the
circumferential injection well. The inclusion 18 can be thickened
at this stage by the process of tip screen-out if desired.
[0078] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 8. This view
depicts the system 10 during the propagation of the lowermost
inclusion 18' from the circumferential injection well. The
lowermost inclusion 18 has been constructed to its final dimension,
and the fluid within the inclusion 18 has lost its viscosity due to
breakers placed in the injected fluid 22. Common breakers consist
of enzymes, catalyzed oxidizers, and organic acids. The formation
14, pore space may contain a significant portion of immobile heavy
oil or bitumen generally up to a maximum oil saturation of 90%;
however, even at these very high oil saturations of 90%, i.e. very
low water saturation of 10%, the mobility of the formation pore
water is quite high, due to its viscosity and the formation
permeability. Thus during propagation of the lowermost inclusion
18', and provided the lowermost inclusion pore fluid's viscosity is
low due to the action of the breaker, then the lowermost inclusion
18 acts a large pore pressure sink, due to size, relative
permeability to the formation, mobility of its and the formation's
pore fluids, resulting in the intersect and coalescence of 18' and
18 irrespective of slight discrepancies in their azimuthal
orientations.
[0079] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 9. This view
depicts the system 10 during the propagation of only one of the
uppermost inclusions 19, to provide a clearer description of the
process used to construct the system 10. The lowermost inclusions
18 and 18' have been constructed to their final dimensions, and the
fluid within the inclusions 18 and 18' have lost its viscosity due
to breakers placed in the injected fluid 22. Thus during
propagation of the uppermost inclusion 19, and provided the
lowermost inclusions pore fluid's viscosity is low due to the
action of the breaker, then the lowermost inclusions 18 and 18'
acts as large pore pressure sinks, due to size, relative
permeability to the formation, mobility of its and the formation's
pore fluids. Thus inclusion 19 intersects and coalesces with
inclusions 18 and 18'. The injected fluid 22 flow rate is stopped
once the inclusion 19 is approximately midway between the central
well and the circumferential injection well.
[0080] Referring further to an enlarged scale isometric view of the
system 10 is representatively illustrated in FIG. 10. This view
depicts the system 10 for the completion of all inclusions, 18,
18', 19, 19' showing the coalescence of the inclusions both
vertically and laterally.
[0081] Finally, it will be understood that the preferred embodiment
has been disclosed by way of example, and that other modifications
may occur to those skilled in the art without departing from the
scope and spirit of the appended claims.
* * * * *