U.S. patent application number 11/379828 was filed with the patent office on 2007-08-30 for enhanced hydrocarbon recovery by steam injection of oil sand formations.
Invention is credited to Grant Hocking.
Application Number | 20070199697 11/379828 |
Document ID | / |
Family ID | 38581723 |
Filed Date | 2007-08-30 |
United States Patent
Application |
20070199697 |
Kind Code |
A1 |
Hocking; Grant |
August 30, 2007 |
ENHANCED HYDROCARBON RECOVERY BY STEAM INJECTION OF OIL SAND
FORMATIONS
Abstract
The present invention involves a method and apparatus for
enhanced recovery of petroleum fluids from the subsurface by
injection of a steam and hydrocarbon vaporized solvent in contact
with the oil sand formation and the heavy oil and bitumen in situ.
Multiple propped hydraulic fractures are constructed from the well
bore into the oil sand formation and filled with a highly permeable
proppant. Steam, a hydrocarbon solvent, and a non-condensing
diluent gas are injected into the well bore and the propped
fractures. The injected gas flows upwards and outwards in the
propped fractures contacting the oil sands and in situ bitumen on
the vertical faces of the propped fractures. The steam condenses on
the cool bitumen and thus heats the bitumen by conduction, while
the hydrocarbon solvent vapors diffuse into the bitumen from the
vertical faces of the propped fractures. The bitumen softens and
flows by gravity to the well bore, exposing fresh surface of
bitumen for the process to progressively soften and mobilize the
bitumen in a predominantly circumferential, i.e. orthogonal to the
propped fracture, diffusion direction at a nearly uniform rate into
the oil sand deposit. The produced product of oil and dissolved
solvent is pumped to the surface where the solvent can be recycled
for further injection.
Inventors: |
Hocking; Grant; (Alpharetta,
GA) |
Correspondence
Address: |
SMITH, GAMBRELL & RUSSELL
SUITE 3100, PROMENADE II
1230 PEACHTREE STREET, N.E.
ATLANTA
GA
30309-3592
US
|
Family ID: |
38581723 |
Appl. No.: |
11/379828 |
Filed: |
April 24, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11363540 |
Feb 27, 2006 |
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11379828 |
Apr 24, 2006 |
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11277308 |
Mar 23, 2006 |
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11379828 |
Apr 24, 2006 |
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11277775 |
Mar 29, 2006 |
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11379828 |
Apr 24, 2006 |
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11277815 |
Mar 29, 2006 |
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11379828 |
Apr 24, 2006 |
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11277789 |
Mar 29, 2006 |
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11379828 |
Apr 24, 2006 |
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11278470 |
Apr 3, 2006 |
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11379828 |
Apr 24, 2006 |
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11379123 |
Apr 18, 2006 |
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11379828 |
Apr 24, 2006 |
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Current U.S.
Class: |
166/250.1 ;
166/250.01; 166/280.1; 166/303; 166/57 |
Current CPC
Class: |
E21B 43/2405 20130101;
E21B 43/261 20130101 |
Class at
Publication: |
166/250.1 ;
166/280.1; 166/303; 166/250.01; 166/057 |
International
Class: |
E21B 47/00 20060101
E21B047/00; E21B 43/24 20060101 E21B043/24; E21B 43/267 20060101
E21B043/267; E21B 36/00 20060101 E21B036/00 |
Claims
1. A method for in situ recovery of hydrocarbons from a hydrocarbon
containing formation having an ambient reservoir pressure and
temperature, comprising: a. drilling a bore hole in the formation
to a predetermined depth to define a well bore with a casing; b.
installing one or more vertical hydraulic fractures from the bore
hole to create a process zone within the formation by injecting a
fracture fluid at a reservoir fracturing pressure into the casing,
wherein the hydraulic fractures contain a proppant; c. injecting
steam at a steam pressure into a section of the well casing
connected to the hydraulic fractures; d. recovering hydrocarbons
from the formation.
2. The method of claim 1, wherein the injection step includes
injecting an injection gas that is a mixture of steam, a
hydrocarbon solvent having a hydrocarbon solvent vapor phase,
hydrogen, and carbon monoxide.
3. The method of claim 2, wherein the hydrocarbon solvent is one of
a group of ethane, propane, butane, or a mixture thereof.
4. The method of claim 1, wherein the steam pressure is close to
the ambient reservoir pressure but substantially below the
reservoir fracturing pressure.
5. The method of claim 2, wherein the injection gas is mixed with a
diluent gas.
6. The method of claim 5, wherein the diluent gas is
non-condensable under the process conditions in the process
zone.
7. The method of claim 5, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbons in the formation than
the saturated hydrocarbon solvent.
8. The method of claim 5, wherein the diluent gas is one of a group
of methane, nitrogen, carbon dioxide, natural gas, or a mixture
thereof.
9. The method of claim 8, wherein the hydrocarbon solvent vapor in
the injection gas is maintained saturated at or near its dew
point.
10. The method of claim 8, wherein a spent tail gas is produced,
additional steam and hydrocarbon solvent is added to the tail gas
to create a tail gas mixture, and the tail gas mixture re-injected
into the casing.
11. The method of claim 2, wherein the dew point of the hydrocarbon
solvent vapor in the injection gas is adjusted to the downhole
conditions by injecting additional hydrocarbon solvent at depth to
add additional hydrocarbon solvent to the injection gas.
12. The method of claim 2, wherein the hydrocarbon solvent
injection is sufficient to maintain a saturated state of the
hydrocarbon solvent vapor in the process zone.
13. The method of claim 2, wherein the method further includes
injecting a hydrogenising gas into the well casing and thus into
the process zone to promote hydrogenation and thermal cracking of
at least a portion of the hydrocarbons in the process zone.
14. The method of claim 13, wherein the method further includes
catalyzing the hydrogenation and thermal cracking of at least a
portion of the hydrocarbons in the process zone.
15. The method of claim 13, wherein a metal-containing catalyst is
used to catalyze the hydrogenation and thermal cracking
reactions.
16. The method of claim 13, wherein the catalyst is contained in a
canister in the well casing.
17. The method of claim 1, wherein the proppant in the hydraulic
fractures contains the catalyst for the hydrogenation and thermal
cracking reactions.
18. The method of claim 1, wherein the hydraulic fractures are
filled with proppants of differing permeability.
19. The method of claim 1, wherein the steam injection is a
pressure pulsed cyclic intermittent injection.
20. The method of claim 1, wherein the steam injection is a
continuous injection.
21. The method of claim 2, wherein the dissolved hydrocarbon
solvent in the hydrocarbons produced from the formation is
separated and recycled for re-injection.
22. The method of claim 2, wherein hydrocarbon solvent vapor
saturation within the injection gas is monitored and adjusted,
based on the dew point of the hydrocarbon solvent.
23. The method of claim 1, further comprising controlling
temperature and pressure in the majority of the part of the process
zone, wherein the temperature is controlled as a function of
pressure, or the pressure is controlled as a function of
temperature.
24. The method of claim 1, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
25. The method of claim 1, wherein at least two vertical fractures
are installed from the bore hole at approximately orthogonal
directions.
26. The method of claim 1, wherein at least three vertical
fractures are installed from the bore hole.
27. The method of claim 1, wherein at least four vertical fractures
are installed from the bore hole.
28. A hydrocarbon production well in a formation of unconsolidated
and weakly cemented sediments having an ambient reservoir pressure
and temperature, comprising: a. a bore hole in the formation to a
predetermined depth; b. an injection casing grouted in the bore
hole at the predetermined depth, the injection casing including
multiple initiation sections separated by a weakening line and
multiple passages within the initiation sections and communicating
across the weakening line for the introduction of a fracture fluid
to dilate the casing and separate the initiation sections along the
weakening line; c. a fracture fluid source for delivering the
fracture fluid into the injection casing with sufficient reservoir
fracturing pressure to dilate the injection casing and the
formation and initiate a vertical hydraulic fracture, having a
fracture tip, at an azimuth orthogonal to the direction of dilation
to create a process zone within the formation, for controlling the
propagation rate of each individual opposing wing of the hydraulic
fracture, and for controlling the flow rate of the fracture fluid
and its viscosity so that the Reynolds Number Re is less than 1 at
fracture initiation and less than 2.5 during fracture propagation
and the fracture fluid viscosity is greater than 100 centipoise at
the fracture tip; and d. a source for injecting steam at a steam
pressure into the casing and the hydraulic fractures to produce
hydrocarbons from the formation.
29. The well of claim 28, wherein the source injects an injection
gas that is a mixture of steam, hydrocarbon solvent having a
hydrocarbon solvent vapor phase, hydrogen, and carbon monoxide.
30. The well of claim 28, wherein the hydrocarbon solvent is one of
a group of ethane, propane, butane, or a mixture thereof.
31. The well of claim 28, wherein the steam pressure is close to
the ambient reservoir pressure but substantially below the
reservoir fracturing pressure.
32. The well of claim 29, wherein the hydrocarbon solvent is mixed
with a diluent gas.
33. The well of claim 32, wherein the diluent gas is
non-condensable under the process conditions.
34. The well of claim 32, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbons in the formation than
the saturated hydrocarbon solvent.
35. The well of claim 32, wherein the diluent gas is one of a group
of methane, nitrogen, carbon dioxide, natural gas, or a mixture
thereof.
36. The well of claim 36, wherein the hydrocarbon solvent vapor is
maintained saturated at or near its dew point.
37. The well of claim 36, wherein a spent tail gas is produced,
additional steam and hydrocarbon solvent is added to the tail gas
to create a tail gas mixture, and the tail gas mixture re-injected
into the casing.
38. The well of claim 29, wherein the dew point of the hydrocarbon
solvent vapor is adjusted to the downhole conditions by employing a
solvent injector at depth to add additional hydrocarbon solvent to
the process zone.
39. The well of claim 29, wherein the hydrocarbon solvent injection
is sufficient to maintain a saturated state of the hydrocarbon
solvent vapor in the process zone.
40. The well of claim 29, wherein the well further includes means
for injecting a hydrogenising gas into the well casing and thus
into the process zone to promote hydrogenation and thermal cracking
of at least a portion of the hydrocarbons in the process zone.
41. The well of claim 29, wherein means for delivering a catalyst
to the process for catalyzing the hydrogenation and thermal
cracking of at least a portion of the petroleum fluids in the
process zone.
42. The well of claim 41, wherein the catalyst is a
metal-containing catalyst is used to catalyze said hydrogenation
and thermal cracking reactions.
43. The well of claim 41, wherein the catalyst is contained in a
canister inside of the well casing.
44. The well of claim 28, wherein the proppant in the hydraulic
fractures contains the catalyst for the hydrogenation and thermal
cracking reactions.
45. The well of claim 28, wherein the hydraulic fractures are
filled with proppants of differing permeability.
46. The well of claim 28, wherein the steam injection is a pressure
pulsed cyclic intermittent injection.
47. The well of claim 28, wherein the steam injection is a
continuous injection.
48. The well of claim 29, wherein the well has recycling means for
recovering the dissolved hydrocarbon solvent in the produced
hydrocarbons for re-injection.
49. The well of claim 29, wherein the hydrocarbon solvent vapor
saturation within the injection gas is monitored and adjusted,
based on the dew point of the injection gas.
50. The well of claim 28, further comprising controlling the
temperature and pressure in the majority of the part of the process
zone, wherein the temperature is controlled as a function of
pressure, or the pressure is controlled as a function of
temperature.
51. The well of claim 28, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
52. The well of claim 28, wherein at least two vertical fractures
are installed from the bore hole at approximately orthogonal
directions.
53. The well of claim 28, wherein at least three vertical fractures
are installed from the bore hole.
54. The well of claim 28, wherein at least four vertical fractures
are installed from the bore hole.
Description
RELATED APPLICATION
[0001] This application is a continuation-in-part of copending U.S.
patent application Ser. No. 11/363,540, filed Feb. 27, 2006, U.S.
patent application Ser. No. 11/277,308, filed Mar. 27, 2006, U.S.
patent application Ser. No. 11/277,775, filed Mar. 29, 2006, U.S.
patent application Ser. No. 11/277,815, filed Mar. 29, 2006, U.S.
patent application Ser. No. 11/277,789, filed Mar. 29, 2006, U.S.
patent application Ser. No. 11/278,470, filed Apr. 3, 2006, and
U.S. patent application Ser. No. 11/379,123, filed Apr. 18,
2006.
TECHNICAL FIELD
[0002] The present invention generally relates to enhanced recovery
of petroleum fluids from the subsurface by the injection of steam
in the oil sand formation contacting the viscous heavy oil and
bitumen in situ, and more particularly to a method and apparatus to
extract a particular fraction of the in situ hydrocarbon reserve by
controlling the access to the in situ bitumen, the steam and
solvent composition, and operating temperatures and pressures of
the in situ process, resulting in increased production of petroleum
fluids from the subsurface formation as well as limiting water
inflow into the process zone.
BACKGROUND OF THE INVENTION
[0003] 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 cohesionless sands with minimal grain to grain
cementation. The hydrocarbons are extracted from the oils sands
either by mining or in situ methods.
[0004] 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 and 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 .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.
[0005] 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.
[0006] 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, stream flood
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.
[0007] Cyclic steam stimulation and steam flood 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 steam flood 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, see 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.
[0008] Descriptions of the SAGD process and modifications are
described, see 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.
[0009] A thermal steam extraction process referred to a HASDrive
(heated annulus steam drive) and modifications thereof are
described to heat and hydrogenate the heavy oils in situ 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.
[0010] 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.
[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 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
(300.degree. to 400.degree. range and above) to pyrolysis the oil
sands. 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, and 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 over pressurized conditions are usually imposed to
accelerated the steam chamber development, followed by a prolonged
period of under pressurized 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] Hydraulic fracturing of petroleum recovery wells enhances
the extraction of fluids from low permeable formations due to the
high permeability of the induced fracture and the size and extent
of the fracture. A single hydraulic fracture from a well bore
results in increased yield of extracted fluids from the formation.
Hydraulic fracturing of highly permeable unconsolidated formations
has enabled higher yield of extracted fluids from the formation and
also reduced the inflow of formation sediments into the well bore.
Typically the well casing is cemented into the borehole, and the
casing perforated with shots of generally 0.5 inches in diameter
over the depth interval to be fractured. The formation is
hydraulically fractured by injecting fracture fluid into the
casing, through the perforations and into the formation. The
hydraulic connectivity of the hydraulic fracture or fractures
formed in the formation may be poorly connected to the well bore
due to restrictions and damage due to the perforations. Creating a
hydraulic fracture in the formation that is well connected
hydraulically to the well bore will increase the yield from the
well, result in less inflow of formation sediments into the well
bore and result in greater recovery of the petroleum reserves from
the formation.
[0016] Turning now to the prior art, hydraulic fracturing of
subsurface earth formations to stimulate production of hydrocarbon
fluids from subterranean formations has been carried out in many
parts of the world for over fifty years. The earth is hydraulically
fractured either through perforations in a cased well bore or in an
isolated section of an open bore hole. The horizontal and vertical
orientation of the hydraulic fracture is controlled by the
compressive stress regime in the earth and the fabric of the
formation. It is well known in the art of rock mechanics that a
fracture will occur in a plane perpendicular to the direction of
the minimum stress, see U.S. Pat. No. 4,271,696 to Wood. At
significant depth, one of the horizontal stresses is generally at a
minimum, resulting in a vertical fracture formed by the hydraulic
fracturing process. It is also well known in the art that the
azimuth of the vertical fracture is controlled by the orientation
of the minimum horizontal stress in consolidated sediments and
brittle rocks.
[0017] At shallow depths, the horizontal stresses could be less or
greater than the vertical overburden stress. If the horizontal
stresses are less than the vertical overburden stress, then
vertical fractures will be produced; whereas if the horizontal
stresses are greater than the vertical overburden stress, then a
horizontal fracture will be formed by the hydraulic fracturing
process.
[0018] Hydraulic fracturing generally consists of two types,
propped and unpropped fracturing. Unpropped fracturing consists of
acid fracturing in carbonate formations and water or low viscosity
water slick fracturing for enhanced gas production in tight
formations. Propped fracturing of low permeable rock formations
enhances the formation permeability for ease of extracting
petroleum hydrocarbons from the formation. Propped fracturing of
high permeable formations is for sand control, i.e. to reduce the
inflow of sand into the well bore, by placing a highly permeable
propped fracture in the formation and pumping from the fracture
thus reducing the pressure gradients and fluid velocities due to
draw down of fluids from the well bore. Hydraulic fracturing
involves the literally breaking or fracturing the rock by injecting
a specialized fluid into the well bore passing through perforations
in the casing to the geological formation at pressures sufficient
to initiate and/or extend the fracture in the formation. The theory
of hydraulic fracturing utilizes linear elasticity and brittle
failure theories to explain and quantify the hydraulic fracturing
process. Such theories and models are highly developed and
generally sufficient for the art of initiating and propagating
hydraulic fractures in brittle materials such as rock, but are
totally inadequate in the understanding and art of initiating and
propagating hydraulic fractures in ductile materials such as
unconsolidated sands and weakly cemented formations.
[0019] Hydraulic fracturing has evolved into a highly complex
process with specialized fluids, equipment and monitoring systems.
The fluids used in hydraulic fracturing vary 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.
[0020] Oil based fracturing fluids are generally based on a gel
formed as a reaction product of aluminum phosphate ester and a
base, typically sodium aluminate. The reaction of the ester and
base creates a solution that yields high viscosity in diesels or
moderate to high API gravity hydrocarbons. Gelled hydrocarbons are
advantageous in water sensitive oil producing formations to avoid
formation damage, that would otherwise be caused by water based
fracturing fluids.
[0021] The method of controlling the azimuth of a vertical
hydraulic fracture 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 fracture can be propagated at a pre-determined azimuth in
unconsolidated or weakly cemented sediments and that multiple
orientated vertical hydraulic fractures 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. patent
application Ser. No. 11/363,540 and U.S. patent application Ser.
No. 11/277,308. The method disclosed that a vertical hydraulic
fracture can be propagated at a pre-determined azimuth in
unconsolidated or weakly cemented sediments and that multiple
orientated vertical hydraulic fractures 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.
[0022] Accordingly, there is a need for a method and apparatus for
enhancing the extraction of hydrocarbons from oil sands by direct
heating, steam and/or solvent injection, or a combination 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
[0023] The present invention is a method and apparatus for enhanced
recovery of petroleum fluids from the subsurface by injection of
steam in contact with the oil sand formation and the heavy oil and
bitumen in situ. Multiple propped hydraulic fractures are
constructed from the well bore into the oil sand formation and
filled with a highly permeable proppant. Steam is injected into the
well bore and the propped fractures at or near the ambient
reservoir pressure but substantially below the reservoir fracturing
pressure. The injected steam flows upwards and outwards in the
propped fractures contacting the oil sands and in situ bitumen on
the vertical faces of the propped fractures. The steam condenses
onto the cool bitumen and the latent heat of the steam diffuse into
the bitumen from the vertical faces of the propped fractures. The
bitumen softens and flows by gravity to the well bore, exposing
fresh surface of bitumen for the process to progressively soften
and mobilize the bitumen in a predominantly circumferential, i.e.
orthogonal to the propped fracture, diffusion direction at a nearly
uniform rate into the oil sand deposit. To limit upward growth of
the process, a light non-condensing gas can be injected to remain
in the uppermost portions of the propped fractures. The mobile oil
may be deasphalted by co-injection of a hydrocarbon solvent with
the steam, leaving the heavy asphaltenes behind in the oil sand
pore space with little loss of inherent fluid mobility in the
processed oil sands. The processed hydrocarbon product with the
dissolved solvent is produced from the formation and steam along
with a hydrocarbon solvent is re-injected into the process zone and
the cycle repeats.
[0024] The processes active at the contact of the inject steam and
solvent with the bitumen in the oil sand are predominantly
diffusive, being driven by partial pressure and temperature
gradients, resulting in the diffusion of hydrocarbon solvent and
heat into the bitumen. Upon softening of the bitumen, the oil will
become mobile and flow under gravity and exposed contact with fresh
bitumen in situ for an every larger expanding zone of mobile oil in
the native oil sand formation. The mobile oil flows by gravity with
the dissolved solvent back to the well bore and pumped to the
surface.
[0025] The hydrocarbon solvent would preferably be one of ethane,
propane, or butane or a mixture thereof, and be mixed with a
non-condensing diluent gas being either methane, nitrogen, carbon
dioxide, natural gas, or a mixture thereof, to ensure that the
selected composition of the injected gas is such that: 1) the
solvent mixture has a dew point that substantially corresponds with
the operating process temperature and pressure in situ, 2) the
solvent mixture is substantially more soluble in the bitumen than
the diluent gas, 3) the solvent mixture is liquefied but
vaporizable in the process zone, and 4) solvent mixture has a
vapor/liquid envelop that encompasses the process operating
temperatures and pressures. The solvent and diluent gas are
injected with the steam into the well bore and the process zone,
with the solvent primarily as a vapor state contacting and
diffusing into the bitumen. By selecting the appropriate solvent,
diluent gas, and steam mixture, the process can operate close to
ambient reservoir pressures, so that water inflow into the process
zone can be minimized. 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,
composition of the solvent, diluent gas and steam mixture, and the
presence of nearby water bodies. At such elevated temperatures, the
diffusion rate of the solvent diffusing into the bitumen is
significantly greater than at reservoir ambient temperatures.
[0026] As the steam solvent mixture is injected and contacts the in
situ bitumen, the steam condenses onto the cool bitumen and thus
heats the bitumen by conduction. As the gas mixture contacts the
bitumen, the oil becomes diluted with solvent and heated by the
steam, softens and flows by gravity to the well bore. The flowing
oil contains dissolved solvent. The produced product of oil and
dissolved solvent is pumped to the surface where the solvent can be
recycled for further injection.
[0027] Although the present invention contemplates the formation of
fractures 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.
[0028] Therefore, the present invention provides a method and
apparatus for enhanced recovery of petroleum fluids from the
subsurface by steam and vaporized solvents placed in the oil sand
formation contacting the viscous heavy oil and bitumen in situ, and
more particularly to a method and apparatus to extract a particular
fraction of the in situ hydrocarbon reserve by controlling the
access to the in situ bitumen, the steam solvent composition, and
operating temperatures and pressures of the in situ process,
resulting in increased production of petroleum fluids from the
subsurface formation as well as limiting water inflow into the
process zone.
[0029] 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
[0030] FIG. 1 is a horizontal cross-section view of a well casing
having dual fracture winged initiation sections prior to initiation
of multiple azimuth controlled vertical fractures.
[0031] FIG. 2 is a cross-sectional side elevation view of a well
casing having dual fracture winged initiation sections prior to
initiation of multiple azimuth controlled vertical fractures.
[0032] FIG. 3 is an isometric view of a well casing having dual
propped fractures with downhole steam, solvent, and diluent gas
injection for a cyclic pulsed pressure steam injection system.
[0033] FIG. 4 is a horizontal cross-sectional side elevation view
of a well casing and propped fracture showing flow of the injected
gas and oil with progressive growth of the mobile oil zone.
[0034] FIG. 5 is an isometric view of a well casing having dual
propped fractures with downhole steam, solvent, and diluent gas
injection for a continuous steam injection system.
[0035] FIG. 6 is a horizontal cross-section view of a well casing
having multiple fracture dual winged initiation sections after
initiation of all four controlled vertical fractures.
[0036] FIG. 7 is an isometric view of a well casing having four
propped fractures with downhole steam, solvent, and diluent gas
injection for a cyclic pulsed pressure steam injection system.
[0037] FIG. 8 is an isometric view of a well casing having dual
multi-stage propped fractures with downhole steam, solvent, and
diluent gas injection for a continuous steam injection system.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0038] Several embodiments of the present invention are described
below and illustrated in the accompanying drawings. The present
invention is a method and apparatus for enhanced recovery of
petroleum fluids from the subsurface by injection of steam and a
hydrocarbon vaporized solvent in contact with the oil sand
formation and the heavy oil and bitumen in situ. Multiple propped
hydraulic fractures are constructed from the well bore into the oil
sand formation and filled with a highly permeable proppant. Steam,
a hydrocarbon solvent, and a non-condensing diluent gas are
injected into the well bore and the propped fractures. The injected
gas flows upwards and outwards in the propped fractures contacting
the oil sands and in situ bitumen on the vertical faces of the
propped fractures. The steam condenses on the cool bitumen and thus
heats the bitumen by conduction, while the hydrocarbon solvent
vapors diffuse into the bitumen from the vertical faces of the
propped fractures. The bitumen softens and flows by gravity to the
well bore, exposing fresh surface of bitumen for the process to
progressively soften and mobilize the bitumen in a predominantly
circumferential, i.e. orthogonal to the propped fracture, diffusion
direction at a nearly uniform rate into the oil sand deposit. The
produced product of oil and dissolved solvent is pumped to the
surface where the solvent can be recycled for further
injection.
[0039] Referring to the drawings, in which like numerals indicate
like elements, FIGS. 1 and 2 illustrate the initial setup of the
method and apparatus for forming either an in situ cyclic pressure
pulsed or continuous injection of steam, solvent, and diluent into
the oil sand deposit and for the extraction of the processed
hydrocarbons. Conventional bore hole 5 is completed by wash rotary
or cable tool methods into the formation 8 to a predetermined depth
7 below the ground surface 6. Injection casing 1 is installed to
the predetermined depth 7, and the installation is completed by
placement of a grout 4 which completely fills the annular space
between the outside the injection casing 1 and the bore hole 5.
Injection casing 1 consists of four initiation sections 21, 22, 23,
and 24 to produce two fractures one orientated along plane 2, 2'
and one orientated along plane 3, 3'. Injection casing 1 must be
constructed from a material that can withstand the pressures that
the fracture fluid exerts upon the interior of the injection casing
1 during the pressurization of the fracture fluid. The grout 4 can
be any conventional material (if elevated temperatures are
contemplated a steam injection casing cementation system is
preferred) that preserves the spacing between the exterior of the
injection casing 1 and the bore hole 5 throughout the fracturing
procedure, preferably a non-shrink or low shrink cement based grout
that can withstand the imposed temperature and differential
strains.
[0040] The outer surface of the injection casing 1 should be
roughened or manufactured such that the grout 4 bonds to the
injection casing 1 with a minimum strength equal to the down hole
pressure required to initiate the controlled vertical fracture. The
bond strength of the grout 4 to the outside surface of the casing 1
prevents the pressurized fracture fluid from short circuiting along
the casing-to-grout interface up to the ground surface 6.
[0041] Referring to FIGS. 1, 2, and 3, the injection casing 1
comprises two fracture dual winged initiation sections 21, 22, 23,
and 24 installed at a predetermined depth 7 within the bore hole 5.
The winged initiation sections 21, 22, 23, and 24 can be
constructed from the same material as the injection casing 1. The
position below ground surface of the winged initiation sections 21,
22, 23, and 24 will depend on the required in situ geometry of the
induced hydraulic fractures and the reservoir formation properties
and recoverable reserves.
[0042] The hydraulic fractures will be initiated and propagated by
an oil based fracturing fluid consisting of a gel formed as a
reaction product of aluminum phosphate ester and a base, typically
sodium aluminate. The reaction of the ester and base creates a
solution that yields high viscosity in diesels or moderate to high
API gravity hydrocarbons. Gelled hydrocarbons are advantageous in
water sensitive oil producing formations to avoid formation damage,
that would otherwise be caused by water based fracturing fluids.
Alternatively a water based fracturing fluid gel can be used.
[0043] The pumping rate of the fracturing fluid and the viscosity
of the fracturing fluids needs to be controlled to initiate and
propagate the fracture in a controlled manner in weakly cemented
sediments such as oil sands. The dilation of the casing and grout
imposes a dilation of the formation that generates an unloading
zone in the oil sand, and such dilation of the formation reduces
the pore pressure in the formation in front of the fracturing tip.
The variables of interest are v the velocity of the fracturing
fluid in the throat of the fracture, i.e. the fracture propagation
rate, w the width of the fracture at its throat, being the casing
dilation at fracture initiation, and .mu. the viscosity of the
fracturing fluid at the shear rate in the fracture throat. The
Reynolds number is Re=.rho.vw/.mu.. To ensure a repeatable single
orientated hydraulic fracture is formed, the formation needs to be
dilated orthogonal to the intended fracture plane, and the
fracturing fluid pumping rate needs to be limited so that the Re is
less than 1.0 during fracture initiation and less than 2.5 during
fracture propagation. Also if the fracturing fluid can flow into
the dilated zone in the formation ahead of the fracture and negate
the induce pore pressure from formation dilation then the fracture
will not propagate along the intended azimuth. In order to ensure
that the fracturing fluid does not negate the pore pressure
gradients in front of the fracture tip, its viscosity at fracturing
shear rates within the fracture throat of .about.1-20 sec-1 needs
to be greater than 100 centipoise.
[0044] The fracture fluid forms a highly permeable hydraulic
fracture by placing a proppant in the fracture to create a highly
permeable fracture. Such proppants are typically clean sand for
large massive hydraulic fracture installations or specialized
manufactured particles (generally resin coated sand or ceramic in
composition) which are designed also to limit flow back of the
proppant from the fracture into the well bore. The fracture
fluid-gel-proppant mixture is injected into the formation and
carries the proppant to the extremes of the fracture. Upon
propagation of the fracture to the required lateral 31 and vertical
extent 32, the predetermined fracture thickness may need to be
increased by utilizing the process of tip screen out or by
re-fracturing the already induced fractures. The tip screen out
process involves modifying the proppant loading and/or fracture
fluid properties to achieve a proppant bridge at the fracture tip.
The fracture fluid is further injected after tip screen out, but
rather then extending the fracture laterally or vertically, the
injected fluid widens, i.e. thickens, and fills the fracture from
the fracture tip back to the well bore.
[0045] Referring to FIG. 3 for the intermittent cyclic pressure
pulsed steam, solvent, and diluent gas injection system, the casing
1 is washed clean of fracturing fluids and a screen 25 is present
in the casing as a bottom screen 25 for hydraulic connection from
the casing well bore 1 to the propped fractures 30. A downhole
electric pump 17 is placed inside the casing, connected to a power
and instrumentation cable 18, with downhole packer 19 and drop tube
16 for steam, solvent, and diluent gas injection, and piping 9 for
production of the produced hydrocarbons to the surface. The steam,
solvent, and diluent gas are injected at just below or very close
to reservoir ambient pressure through the drop tube 16, through the
screen 25 and into the propped fractures 30. The steam, solvent,
and diluent gas contact the bitumen from the propped fracture
faces, the steam heats the bitumen and the solvent diffuses into
the bitumen. The mobile oil from the bitumen includes dissolved
solvents and flows by gravity along with any in place water as
shown by 11, to form a pool of oil 10 which flows 15 into the
screen 25 and 13 into the pump, and is pumped 14 through the tubing
9 to the surface. The pressure of the injected gas in the propped
fractures drops slightly as the steam condenses and the solvent
diffuses into the bitumen, and further steam, solvent, and diluent
gas is injected through the drop tube 16 to continue the cycle of
progressively mobilizing the in place bitumen. The slight cyclic
pressure cycling will encourage the gravity flow of the oil towards
the well bore.
[0046] Referring to FIGS. 3 and 4, the injected steam, solvent, and
diluent gas flow as shown by vectors 12 from the screen 25 into the
propped fractures 30 with proppant shown 34 and mobilized oil sand
zone 35 adjacent to the propped fractures 34. The mobilized oil
sand zone extends into the bitumen oil sands 36 by diffusive
processes 33 due to the thermal and partial pressure gradients. The
mixture of solvent and produced bitumen results in a modified
hydrocarbon that flows from the bitumen 36 into the mobilized oil
sand zone 35 and the propped fracture 34. The modified hydrocarbon
eventually flows as 11 down to a pool of oil 10 and as flow 15 into
the lower screen 25 of the well bore. The process zone includes the
propped hydraulic fractures 30, the mobile zone 35 in the oil sands
of the formation, and the fluid contained therein. In some cases,
the well bore casing 1 may be considered part of the process zone
when a part of the process for recovering hydrocarbons from the
formation is carried out in the well casing.
[0047] The mobilized oil sand zone 35 grows circumferentially 33,
i.e. orthogonal to the propped fractures 30, and becomes larger
with time until eventually the bitumen within the lateral 31 and
vertical 32 extent of the propped fracture system is completely
mobilized by the injected solvent. Upon growth of the mobilized oil
sand zone circumferentially to the lateral 31 and vertical 32
extent of the propped fractures 30, the contact area of the in
place bitumen available for steam condensation and solvent
diffusion drops dramatically from eight fracture surfaces each of
an area of lateral extent 31 times vertical extent 32 plus
virtually a cylindrical shape of area 2.pi. times the lateral and
vertical extents 31 and 32, down to a cylindrical shape of area
2.pi. times the lateral and vertical extents 31 and 32, i.e. from 8
plus 2.pi. down to 2.pi., i.e. a drop of 65% in surface contact
area, assuming vertical growth of the process zone has been
inhibited by placing a light non-condensing gas in the uppermost
portions of the fractures. At this stage if the process is
continued the growth of the mobile oil zone will become radial, and
the mobilized oil will need to flow radially from the mobilized oil
zone towards the fractures and well bore. It is at this stage that
the process slows down and economics will determine if the
injection/production process continues.
[0048] Another embodiment of the present invention is shown on FIG.
5, for a continuous steam, solvent, and diluent gas injection
system, consisting of a similar arrangement of hydraulic fractures
30, injection casing 1, a bottom screen 25 for hydraulic connection
from the casing well bore 1 to the propped fractures 30, but also a
top screen 26 for connection of upper portions of the propped
fractures to the casing well bore 1. A downhole electric pump 17 is
placed inside the casing, connected to a power and instrumentation
cable 18, with downhole packer 19 and drop tube 16 for steam,
solvent, and diluent gas injection, and piping 9 for production of
the produced hydrocarbons to the surface. The steam, solvent, and
diluent gas are injected at just below or very close to reservoir
ambient pressure through the drop tube 16, through the screen 25
and into the propped fractures 30. The spent tail gas, now devoid
or lowered in solvent content, flows into the casing well bore 1
through the upper screen 27, with additional steam, solvent, and
diluent gas injected through the drop pipe 16 and the spent tail
gas removed through the casing well bore 1. This system involves a
continuous injection of steam, solvent, and diluent gas, compared
to the earlier system which was an intermittent process.
[0049] Another embodiment of the present invention is shown on
FIGS. 6 and 7, consisting of an injection casing 38 inserted in a
bore hole 39 and grouted in place by a grout 40. The injection
casing 38 consists of eight symmetrical fracture initiation
sections 41, 42, 43, 44, 45, 46, 47, and 48 to install a total of
four hydraulic fractures on the different azimuth planes 31, 31',
32, 32', 33, 33', 34, and 34'. The process results in four
hydraulic fractures installed from a single well bore at different
azimuths as shown on FIG. 7. The casing 1 is washed clean of
fracturing fluids and screen 25 is present in the casing as a
bottom screen 25 for hydraulic connection of the casing well bore 1
to the propped fractures 30. A downhole electric pump 17 is placed
inside the casing, connected to a power and instrumentation cable
18, with downhole packer 19 and drop tube 16 for steam, solvent,
and diluent gas injection, and piping 9 for production of the
produced hydrocarbons to the surface. The steam, solvent, and
diluent gas are injected at just below or very close to reservoir
ambient pressure through the drop tube 16, through the screen 25
and into the propped fractures 30. The steam, solvent, and diluent
gas contact the bitumen from the propped fracture faces, the steam
heats the bitumen, and the solvent diffuses into the bitumen. The
mobile oil from the bitumen includes dissolved solvents and flows
by gravity along with any in place water as shown by 11, to form a
pool of oil 10, which flows 15 into the screen 25 and 13 into the
pump, and is pumped 14 through the tubing 9 to the surface. This
configuration is for a cyclic pressure pulsed intermittent
injection of steam, solvent, and diluent gas and could be
configured similar to FIG. 5 for continuous steam, solvent, and
diluent gas injection.
[0050] Another embodiment of the present invention is shown on FIG.
8, similar to FIG. 5 except that the hydraulic fractures are
constructed by a multi-stage process with various proppant
materials of differing permeability. Multi-stage fracturing
involves first injecting a proppant material 50 to form a hydraulic
fracture 30. Prior to creation of the full fracture extent, a
different proppant material 51 is injected into the fracture over a
reduced central section of the well bore 53 to create an area of
the hydraulic fracture loaded with the different proppant material
51. Similarly the multi-stage fracturing could consist of a third
stage by injecting a third different proppant material 52. By the
appropriate selection of proppants with differing permeability, the
circulation of the steam and vaporized solvent in the formed
fracture can be extended laterally a greater distance compared to a
hydraulic fracture filled with a uniform permeable proppant, as
shown earlier in FIG. 5. The proppant materials are selected so
that the proppant material 50 has the highest proppant
permeability, with proppant material 51 being lower, and with
proppant material 52 having the lowest proppant permeability. The
different permeability of the proppant materials thus optimizes the
lateral extent of the fluids flowing within the hydraulic fractures
and controls the geometry and propagation rate of the transfer of
heat and solvent to the oil sand formation. The permeability of the
proppant materials will typically range from 1 to 100 Darcy for the
proppant material 50 in the fracture zone, i.e. generally being at
least 10 times greater than the oil sand formation permeability.
The proppant material 51 in fracture zone is selected to be lower
than the proppant material 50 in fracture zone by at least a factor
of 2, and proppant material 52 in fracture zone close to the well
bore casing 1 is selected to be in the milli-Darcy range thus
limiting fluid flow in the fracture zone containing the proppant
material 52.
[0051] 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.
* * * * *