U.S. patent application number 11/379829 was filed with the patent office on 2007-08-30 for enhanced hydrocarbon recovery by convective heating of oil sand formations.
Invention is credited to Grant Hocking.
Application Number | 20070199706 11/379829 |
Document ID | / |
Family ID | 38581718 |
Filed Date | 2007-08-30 |
United States Patent
Application |
20070199706 |
Kind Code |
A1 |
Hocking; Grant |
August 30, 2007 |
ENHANCED HYDROCARBON RECOVERY BY CONVECTIVE HEATING OF OIL SAND
FORMATIONS
Abstract
The present invention involves a method and apparatus for
enhanced recovery of petroleum fluids from the subsurface by
convective heating of the oil sand formation and the heavy oil and
bitumen in situ by a downhole electric heater. Multiple propped
vertical hydraulic fractures are constructed from the well bore
into the oil sand formation and filled with a diluent. The heater
and downhole pump force thermal convective flow of the heated
diluent to flow upward and outward into the propped fractures and
circulating back down and back towards the well bore heating the
oil sands and in situ bitumen on the vertical faces of the propped
fractures. The diluent now mixed with produced products from the
oil sand re-enters the bottom of the well bore and passes over the
heater element and is reheated to continue to flow in the
convective cell. Thus the heating and diluting of the in place
bitumen occurs predominantly circumferentially, i.e. orthogonal to
the propped fracture, by diffusion from the propped vertical
fracture faces progressing at a nearly uniform rate into the oil
sand deposit. In situ hydrogenation and thermal cracking of the in
place bitumen can provide a higher grade produced product. The
heated low viscosity oil is produced through the well bore at the
completion of the active heating phase of the process.
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: |
38581718 |
Appl. No.: |
11/379829 |
Filed: |
April 24, 2006 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
11363540 |
Feb 27, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11277308 |
Mar 23, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11277775 |
Mar 29, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11277815 |
Mar 29, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11277789 |
Mar 29, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11278470 |
Apr 3, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
11379123 |
Apr 18, 2006 |
|
|
|
11379829 |
Apr 24, 2006 |
|
|
|
Current U.S.
Class: |
166/280.1 ;
166/302; 166/306; 166/57; 166/59; 166/60 |
Current CPC
Class: |
E21B 43/2405 20130101;
E21B 43/261 20130101 |
Class at
Publication: |
166/280.1 ;
166/302; 166/057; 166/059; 166/060; 166/306 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 36/00 20060101 E21B036/00; E21B 43/24 20060101
E21B043/24 |
Claims
1. A method for in situ recovery of hydrocarbons from a hydrocarbon
containing formation, 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 by injecting a fracture
fluid into the casing, wherein the hydraulic fractures contain a
proppant and a diluent; c. providing heat from a heat source to
raise the temperature in a section of the bore hole containing the
diluent; d. circulating the diluent in the hydraulic fractures and
the formation; and e. recovering a mixture of diluent and
hydrocarbons from the formation.
2. The method of claim 1, wherein the heat is provided by a
downhole heater.
3. The method of claim 2, wherein the heat is provided by a
downhole electric heater.
4. The method of claim 2, wherein the heat is provided by a
downhole flameless distributed combustor.
5. The method of claim 1, wherein the heat is provided by a heat
transfer fluid by tubing from a surface fired heater or burner.
6. The method of claim 1, wherein a downhole pump provides forced
convective circulation of the diluent and hydrocarbons mixture.
7. The method of claim 1, wherein the temperature in part of the
formation is in the order of 100.degree. C. to cause hydrocarbons
comprising heavy oil to flow under gravity to the well bore.
8. The method of claim 1, wherein the temperature in part of the
formation is in the range of 150.degree. to 200.degree. C. to cause
hydrocarbons comprising bitumen to flow under gravity to the well
bore.
9. The method of claim 1, wherein the temperature in part of the
formation is in a pyrolysis temperature regime of greater than
250.degree. C.
10. The method of claim 1, 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.
11. The method of claim 1, wherein the diluent and hydrocarbon
mixture is predominantly in a liquid phase throughout the process
zone.
12. The method of claim 1, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
13. The method of claim 1, wherein the hydraulic fractures are
filled with proppants of differing permeability.
14. The method of claim 1, wherein the formation includes a mobile
zone and wherein circulating the diluent causes the heat to
transfer predominantly by convection in the mobile zone and to
transfer predominantly from the mobile zone to the formation
substantially by conduction.
15. The method of claim 1, wherein the method further includes
injecting a hydrogenising gas into the well casing and thus into
the fluids in the process zone to promote hydrogenation and thermal
cracking of at least a portion of the hydrocarbons in the process
zone.
16. The method of claim 15, wherein the hydrogenising gas consists
of one of the group of H.sub.2 and CO or a mixture thereof.
17. The method of claim 15, wherein the method further includes
catalyzing the hydrogenation and thermal cracking of at least a
portion of the hydrocarbons in the process zone.
18. The method of claim 17, wherein a metal-containing catalyst is
used to catalyze the hydrogenation and thermal cracking
reactions.
19. The method of claim 17, wherein the catalyst is contained in a
canister in the well casing.
20. The method of claim 1, wherein the proppant in the hydraulic
fractures contains the catalyst for the hydrogenation and thermal
cracking reactions.
21. The method of claim 1, wherein the diluent is a light oil, a
pipeline diluent, natural condensate stream, or a fraction of a
synthetic crude or a mixture thereof.
22. The method of claim 1, wherein additional quantities of diluent
are injected over time into the well bore to modify the composition
of the diluent and hydrocarbons mixture within the process
zone.
23. The method of claim 1, wherein a light non-condensing low
hydrocarbon solubility gas is injected to fill the uppermost
portion of the hydraulic fractures to inhibit upward growth of the
process zone.
24. The method of claim 1, wherein the heat source is removed and
the hydrocarbons are produced from the formation and a hydrocarbon
solvent is injected into the process zone in a vaporized state.
25. The method of claim 24, wherein the solvent is one of a group
of ethane, propane, butane or a mixture thereof.
26. The method of claim 24, wherein the solvent is mixed with a
diluent gas.
27. The method of claim 26, wherein the diluent gas is
non-condensable under process conditions in the process zone.
28. The method of claim 26, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbons in the formation than
the saturated hydrocarbon solvent.
29. The method of claim 26, wherein the diluent gas is one of a
group of methane, nitrogen, carbon dioxide, natural gas, or a
mixture thereof.
30. The method of claim 1, wherein at least two vertical fractures
are installed from the bore hole at approximately orthogonal
directions.
31. The method of claim 1, wherein at least three vertical
fractures are installed from the bore hole.
32. The method of claim 1, wherein at least four vertical fractures
are installed from the bore hole.
33. A hydrocarbon production well in a formation of unconsolidated
and weakly cemented sediments, 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 source for delivering the
fracture fluid into the injection casing with sufficient fracturing
pressure to dilate the injection casing and the formation and
initiate a vertical fracture 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; d. a
source for delivering a diluent in the casing above the elevation
of the highest hydraulic fracture; e. a heat source positioned
within the casing and in contact with the diluent for heating the
diluent; f. circulating the diluent in a process zone including the
hydraulic fractures and the formation; and g. recovering a mixture
of diluent and hydrocarbons from the formation through the
casing.
34. The well of claim 33, wherein the heat source is a downhole
heater.
35. The well of claim 33, wherein the heat source is a downhole
electric heater.
36. The well of claim 33, wherein the heat source is a downhole
flameless distributed combustor.
37. The well of claim 33, wherein the heat source is a surface
fired heater or burner and tubing containing a heat transfer
fluid.
38. The well of claim 33, wherein a downhole pump provides forced
convective flow of the diluent and hydrocarbons mixture.
39. The well of claim 33, wherein the heat source produces a
temperature in part of the formation that is in the order of
100.degree. C. for the hydrocarbons comprising heavy oil thereby
causing the heavy oil to flow under gravity to the well bore.
40. The well of claim 33, wherein the heat source produces a
temperature in part of the formation that is in the range of
150.degree. to 200.degree. C. for the hydrocarbons comprising
bitumen to cause the bitumen to flow under gravity to the well
bore.
41. The well of claim 33, wherein the heat source produces a
temperature in part of the formation that is in a pyrolysis
temperature regime of greater than 250.degree. C.
42. The well of claim 33, further comprising a temperature and
pressure regulator that controls the temperature and pressure in a
majority of a 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.
43. The well of claim 33, wherein the diluent and hydrocarbons
mixture is predominantly in the liquid phase throughout the process
zone.
44. The well of claim 33, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
45. The well of claim 33, wherein the hydraulic fractures are
filled with proppants of differing permeability.
46. The well of claim 33, wherein the formation includes a mobile
zone and wherein heat produced by the heat source transfers
predominantly by convection in the mobile zone and transfer
predominately from the mobile zone to the formation by
conduction.
47. The well of claim 33, wherein the well includes means for
injecting a hydrogenising gas into the well casing and thus into
the fluids in the process zone to promote hydrogenation and thermal
cracking of at least a portion of the hydrocarbons in the process
zone.
48. The well of claim 33, wherein the hydrogenising gas consists of
one of the group of H.sub.2 and CO or a mixture thereof.
49. The well of claim 48, wherein the well includes means for
catalyzing the hydrogenation and thermal cracking of at least a
portion of the hydrocarbons in the process zone.
50. The well of claim 49, wherein a metal-containing catalyst is
used to catalyze the hydrogenation and thermal cracking
reactions.
51. The well of claim 50, wherein well casing includes a canister
containing the catalyst for the hydrogenation and thermal cracking
reactions.
52. The well of claim 33, wherein the proppant in the hydraulic
fractures contains the catalyst for the hydrogenation and thermal
cracking reactions.
53. The well of claim 33, wherein the diluent is a light oil,
pipeline diluent, natural condensate stream, or fraction of a
synthetic crude or a mixture thereof.
54. The well of claim 33, wherein the well includes means for
injecting additional quantities of diluent over time into the well
casing to modify the composition of the diluent and hydrocarbons
mixture within the process zone.
55. The well of claim 33, wherein the well includes means for
injecting a light non-condensing low hydrocarbon solubility gas to
fill the uppermost portion of the hydraulic fractures to inhibit
upward growth of the process zone.
56. The well of claim 33, wherein the heat source is removed and
the hydrocarbons are produced from the formation and a hydrocarbon
solvent is injected into the process zone in a vaporized state.
57. The well of claim 56, wherein the solvent is one of a group of
ethane, propane, butane, or a mixture thereof.
58. The well of claim 56, wherein the solvent is mixed with a
diluent gas.
59. The well of claim 56, wherein the diluent gas is
non-condensable under process conditions in the process zone.
60. The well of claim 59, wherein the non-condensable diluent gas
has a lower solubility in the hydrocarbons in the formation than
the saturated hydrocarbon solvent.
61. The well of claim 60, wherein the diluent gas is one of a group
of methane, nitrogen, carbon dioxide, natural gas, or a mixture
thereof.
62. The well of claim 33, wherein the well includes at least two
vertical fractures installed from the bore hole at approximately
orthogonal directions.
63. The well of claim 33, wherein the well includes at least three
vertical fractures installed from the bore hole.
64. The well of claim 33, wherein the well includes at least four
vertical fractures 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 convective heating of
the oil sand formation and the viscous heavy oil and bitumen in
situ, more particularly to a method and apparatus to extract a
particular fraction of the in situ hydrocarbon reserve by
controlling the reservoir temperature and pressure, while also
minimizing water inflow into the heated zone and well bore,
resulting in increased production of petroleum fluids from the
subsurface formation.
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. Patent 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 convective
heating of the oil sand formation and the heavy oil and bitumen in
situ, by either a downhole heater in the well bore or heat supplied
to the well bore by a heat transferring fluid from a surface fired
heater or surface burner. Multiple propped hydraulic fractures are
constructed from the well bore into the oil sand formation and
filled with a highly permeable proppant. The permeable propped
fractures and well bore are filled with a diluent and elevated
temperatures from the heater set up thermal convective cells in the
diluent forcing heated diluent to flow upward and outward in the
propped fractures and circulating back down and back towards the
well bore heating the oil sands and in situ bitumen on the vertical
faces of the propped fractures. The diluent now mixed with produced
products from the oil sand re-enters the bottom of the well bore
and passes over the heater element and is reheated to continue to
flow in the convective cell. Thus the heating and diluting of the
in place bitumen is predominantly circumferential, i.e. orthogonal
to the propped fracture, diffusion from the propped vertical
fracture faces progressing at a nearly uniform rate into the oil
sand deposit. To limit upward growth of the process, a non
condensing gas can be injected to remain in the uppermost portions
of the propped fractures.
[0024] The processes active at the contact of the diluent with the
bitumen in the oil sand are predominantly diffusive, being driven
by partial pressure gradients and thermal gradients, resulting in
the diffusion of diluent components into the bitumen and the
conduction of heat from the diluent into the bitumen and oil sand
formation. Upon softening of the bitumen, the oil will become
mobile and additional smaller convective cells will developed
providing better mixing of the diluent in the propped fracture and
the every expanded zone of mobile oil in the native oil sand
formation.
[0025] The diluent would preferably be an on site diluent, light
oil, or natural gas condensate stream, or a mixture thereof, with
its selected composition to provide a primarily liquid phase of the
diluent in the process zone at the imposed reservoir temperatures
and pressures. The diluent could be derived from synthetic crude if
available. The prime use of the diluent is to transfer by
convection, heat from the well bore to the process zone, heat and
dilute the produced product to yield a mixture that will flow
readily at the elevated temperatures through the oil sands and
propped fractures back to the well bore. 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 diluent, 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 bitumen viscosity and thus
mobilized the in place oil. However, the process can be operated a
much higher temperatures >270.degree. C. to pyrolysis the in
place hydrocarbon in the presence of hydrogen and/or catalysts. 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. However, the process operating
conditions may deviate from this pressure in order to maintain the
diluent and produced mixture in a predominantly liquid state, i.e.
the diluent is to remain in most part soluble in the produced heavy
oil or bitumen at the operating process temperatures and
pressures.
[0026] To accelerate the process, forced convection by a pump can
assist and transfer additional heat into the propped fracture
convective cells, by pumping the diluent and produced product at
greater velocities past the heater and into the propped fractures
and mobile zone within the oil sands.
[0027] During the heating and diluting process in situ, only a
small quantity of the mobile produced product will be extracted
from the subsurface in order to maintain reservoir pressures
optimum for the process and to maintain a high liquid level in the
process zone, thus resulting heat transfer occurring at more or
less a uniform rate in a circumferential direction. Drawing down
the pressure for petroleum extraction will result in gas release
from the mixture filling the upper portion of the process zone as
the liquids are extracted from the formation. Upon production of
the liquid hydrocarbons the gas in the process zone could be
produced by sweeping the process zone with another gas, or the gas
could be re-pressurized to reservoir conditions to minimize water
inflow into the process zone and the thermal energy in the process
zone oil sands allowed to conduct radially into the surrounding
cooler oil sands and thus mobilize additional hydrocarbons (i.e. a
heat conductive soak) albeit at a much reduced rate than during the
active heating phase of the process. Finally the remaining liquid
hydrocarbons and gas are produced from the oil sand formation after
some extended heat conductive soak period.
[0028] The prime benefits of the above process are to provide an
efficient low temperature heating phase to mobilize the hydrocarbon
in situ, to produce a higher grade petroleum product, and to
maintain ambient reservoir pressure conditions and thus limit water
inflow into the process zone. The disadvantage of the process is
that only minimal quantities of hydrocarbons are extracted from the
subsurface during the active heating phase of the process since the
majority of the hydrocarbons are produced near the end of the
process.
[0029] 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.
[0030] Therefore, the present invention provides a method and
apparatus for enhanced recovery of petroleum fluids from the
subsurface by convective heating of the oil sand formation and the
viscous heavy oil and bitumen in situ, more particularly to a
method and apparatus to extract a particular fraction of the in
situ hydrocarbon reserve by controlling the reservoir temperature
and pressure, while also minimizing water inflow into the heated
zone and well bore resulting in increased production of petroleum
fluids from the subsurface formation.
[0031] 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
[0032] 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.
[0033] 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.
[0034] FIG. 3 is an isometric view of a well casing having dual
propped fractures with downhole heater and convection fluid flow
shown in the subsurface.
[0035] FIG. 4 is a horizontal cross-sectional side elevation view
of a well casing and propped fracture with downhole heater and
convective fluid flow shown in the subsurface.
[0036] FIG. 5 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.
[0037] FIG. 6 is an isometric view of a well casing having four
propped fractures with downhole heater and convection fluid flow
shown in the subsurface.
[0038] FIG. 7 is an isometric view of a well casing having dual
multi-stage propped fractures with downhole heater and convection
fluid flow shown in the subsurface.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0039] 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 convective heating of the
oil sand formation and the heavy oil and bitumen in situ, by either
a downhole heater in the well bore or heat supplied to the well
bore by a heat transferring fluid from a surface fired heater or
surface burner. Multiple propped hydraulic fractures are
constructed from the well bore into the oil sand formation and
filled with a highly permeable proppant. The permeable propped
fractures and well bore are filled with a diluent, the heater and
pump activated with forced thermal convective flow forcing the
heated diluent to flow upward and outward in the propped fractures
and circulating back down and back towards the well bore heating
the oil sands and in situ bitumen on the vertical faces of the
propped fractures. The diluent now mixed with produced products
from the oil sand re-enters the bottom of the well bore and passes
over the heater element and is reheated to continue to flow in the
convective cell. Thus the heating and diluting of the in place
bitumen is predominantly circumferentially, i.e. orthogonal to the
propped fracture, diffusion from the propped vertical fracture
faces progressing at a nearly uniform rate into the oil sand
deposit. The heated low viscosity oil is produced through the well
bore at the completion of the active heating phase of the
process.
[0040] Referring to the drawings, in which like numerals indicate
like elements, FIGS. 1, 2, and 3 illustrate the initial setup of
the method and apparatus for forming an in situ forced convective
heating system of 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 used in steam
injection casing cementation systems 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 high temperature and
differential strains.
[0041] 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.
[0042] 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 fracture and the reservoir formation properties
and recoverable reserves.
[0043] 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.
The oil based gel provides the added advantage of placing the
required diluent within the propped fracture, without the inherent
problems of injecting a diluent into a water saturated proppant
fracture if water based fracturing fluids were used.
[0044] 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, 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.
[0045] 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 (FIG. 3), 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.
[0046] Referring to FIG. 3, the casing 1 is washed clean of
fracturing fluids and screens 25 and 26 are present in the casing
as a bottom screen 25 and a top screen 26 for hydraulic connection
from the casing well bore 1 to the propped fractures 30. A downhole
electric heater 17 is placed inside the casing, with a downhole
pump 18, connected to a power and instrumentation cable 27, with
downhole packers 16 to isolate the top screen interval from the
remaining sections of the well bore, piping 27, and downhole valve
19. The heater 17 and pump 18 are energized through electric power
provided from the surface through cable 27. The pump and thermal
buoyancy effects forces the diluent fluid to flow 13 past the
heater into 14 the pump 18 and up 15 the tubing 27 and out of the
top screen 26. The downhole valve 19 in the closed position enables
the pumped hot fluid to flow through the top screen 26 into the
fracture and oil sand formation as flow vectors 10, 11, and 12
illustrating the convection cell formation due to the pumped hot
fluid. The surface controlled downhole valve 19 in the open
position enables the pump fluid to flow only up the tubing 9 and
not into the top screen 26. The fluid diluent is cooled by the oil
sands 8 adjacent to the propped fractures 30 as it flows from 10 to
11 to 12, and enters the well bore through the bottom screen 25 to
be convectively moved 13 up past the heater 17 for a return to the
forced convective re-circulation cell.
[0047] Referring to FIGS. 3 and 4, the hot diluent flows in a
re-circulation force convective cell as shown by vectors 10, 11,
and 12 in the propped fracture 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 partial pressure and temperature
gradients. The mixture of diluent 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 to flow
eventually as 12 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.
[0048] 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 elevated temperature and diffused diluent. As the
mobilized oil sand region 35 grows the diluent fluid 12 entering
the lower screen 26 of the well bore becomes a mixture of mobilized
oil from the bitumen and the original diluent. It may be necessary
to dilute this mixture from time to time with additional diluent to
yield the required viscosity and heat transfer properties of the
heated fluid in the re-circulation cell. Upon growth of the
mobilized oil sand zone to the lateral 31 and vertical 32 extents
of the propped fractures 30, the valve 19 will be open and the
liquid hydrocarbons produced up the tubing 9 to the surface.
[0049] As the pressure is lowered during hydrocarbon production to
the surface, gases from the diluent and bitumen mixture will fill
the mobilized oil sand region 35 and the propped fractures 34.
Re-pressurizing these gases back to ambient reservoir pressures
will minimize water inflow into the heated region and an extended
heat conduction soak can provide additional mobilized hydrocarbons
from the oil sands with out additional heat required.
Alternatively, 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.
[0050] During the active heating phase of the process, the
reservoir temperatures and pressures and composition of the
produced fluid will be controlled to optimize the process as
regards the quality and composition of the produced product, the
heat transfer, and diluent properties of the produced mixture, and
to minimize water inflow into the process zone and well bore.
[0051] Another embodiment of the present invention is shown on
FIGS. 5 and 6, 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. 6. The casing 1 is washed clean of
fracturing fluids and screens 25 and 26 are present in the casing
as a bottom screen 25 and a top screen 26 for hydraulic connection
of the well bore 10 to the propped fractures 30. A downhole
electric heater 17 is placed inside the casing, with a downhole
pump 18, connected to a power and instrumentation cable 27, with
downhole packers 16 to isolate the top screen interval from the
remaining sections of the well bore, piping 27, and downhole valve
19. The heater 17 and pump 18 are energized through electric power
provided from the surface through cable 27. The pump and thermal
buoyancy effects force the diluent fluid to flow 13 past the heater
into 14 the pump 18 and up 15 the tubing 27 and out of the top
screen 26. The downhole valve 19 in the closed position enables the
pumped hot fluid to flow through the top screen 26 into the
fracture and oil sand formation as flow vectors 10, 11, and 12
illustrating the convection cell formation due to the pumped hot
fluid. The fluid diluent is cooled by the oil sands 8 adjacent to
the propped fractures 30 as it flows from 10 to 11 to 12, and
enters the well bore through the bottom screen 25 to be
convectively moved 13 up past the heater 17 for a return to the
forced convective re-circulation cell. Following the active heater
phase of the process, the mobilized hydrocarbons are produced from
the well bore and heated zone through opening the downhole valve 19
and transported by tubing 9 to the surface.
[0052] Another embodiment of the present invention is shown on FIG.
7, similar to FIG. 3 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 diluent and mobilized oil 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. 3. 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 convective
heat 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 the fracture zone by at least a factor
of 2, and proppant material 52 in the 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.
[0053] 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.
* * * * *