U.S. patent application number 11/278470 was filed with the patent office on 2007-08-30 for enhanced hydrocarbon recovery by in situ combustion of oil sand formations.
Invention is credited to Grant Hocking.
Application Number | 20070199700 11/278470 |
Document ID | / |
Family ID | 38442905 |
Filed Date | 2007-08-30 |
United States Patent
Application |
20070199700 |
Kind Code |
A1 |
Hocking; Grant |
August 30, 2007 |
ENHANCED HYDROCARBON RECOVERY BY IN SITU COMBUSTION OF OIL SAND
FORMATIONS
Abstract
The present invention is a method and apparatus for the enhanced
recovery of petroleum fluids from the subsurface by in situ
combustion of the hydrocarbon deposit, from injection of an oxygen
rich gas and drawing off a flue gas to control the rate and
propagation of the combustion front to be predominantly vertical
and propagating horizontally guided by the vertical highly
permeable hydraulic fractures. Multiple propped vertical hydraulic
fractures are constructed from the well bore into the oil sand
formation and filled with a highly permeable proppant containing
hydrodesulfurization and thermal cracking catalysts. The oxygen
rich gas is injected via the well bore into the top of the propped
fractures, the in situ hydrocarbons are ignited by a downhole
burner and the generated flue gas extracted from the bottom of the
propped fractures through the well bore and mobile oil gravity
drains through the propped fractures to the bottom of the well bore
and pumped to the surface. The combustion front is predominantly
upright, providing good vertical and lateral sweep, due to the flue
gas exhaust control provided by the highly permeable propped
fractures.
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: |
38442905 |
Appl. No.: |
11/278470 |
Filed: |
April 3, 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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11278470 |
Apr 3, 2006 |
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Current U.S.
Class: |
166/259 ;
166/260; 166/261 |
Current CPC
Class: |
E21B 43/247
20130101 |
Class at
Publication: |
166/259 ;
166/260; 166/261 |
International
Class: |
E21B 43/247 20060101
E21B043/247 |
Claims
1. A method for the 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 proppant and
diluent filled hydraulic fractures from the bore hole to create a
process zone within the formation by injecting a fracture fluid
into the casing; c. injecting an oxygen rich gas into a section of
the bore hole connected to the hydraulic fractures; d. igniting the
hydrocarbon deposit; e. exhausting a combustion gas from the
formation; f. recovering a hydrocarbon from the formation.
2. The method of claim 1, wherein the injected gas is air.
3. The method of claim 1, wherein the injected gas is a mixture of
oxygen and carbon dioxide.
4. The method of claim 1, wherein the produced hydrocarbon mixture
flows through a hot spent combusted zone.
5. The method of claim 3, wherein the combusted gas is separated
into carbon dioxide and a fuel gas.
6. The method of claim 5, wherein the carbon dioxide produced is
re-injected into the formation.
7. The method of claim 1, wherein the proppant of the hydraulic
fractures contains a catalyst or a mixture of catalysts.
8. The method of claim 7, wherein the catalyst is one of a group of
hydrodesulfurization catalysts or thermal cracking catalysts or a
mixture thereof.
9. The method of claim 1, wherein a catalyst or mixture of
catalysts are placed in a canister in the well bore through which
the produced hydrocarbons flow.
10. The method of claim 9, wherein the catalyst is one of a group
of hydrodesulfurization catalysts or thermal cracking catalysts or
a mixture thereof.
11. The method of claim 1, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
12. The method of claim 1, wherein at least two vertical fractures
are installed from the bore hole at approximately orthogonal
directions.
13. The method of claim 1, wherein at least three vertical
fractures are installed from the bore hole.
14. The method of claim 1, wherein at least four vertical fractures
are installed from the bore hole.
15. A 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
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; d. a
source of oxygen rich gas connected to the casing and the propped
hydraulic fractures; e. an ignition source for igniting the
hydrocarbon deposit in the presence of the oxygen rich gas, wherein
a resulting combustion gas from the formation is exhausted through
the casing and petroleum hydrocarbons from the formation are
recovered through the casing.
16. The well of claim 15, wherein the injected gas is air.
17. The well of claim 15, wherein the injected gas is a mixture of
oxygen and carbon dioxide.
18. The well of claim 15, wherein the produced hydrocarbon flows
through a hot spent combusted zone.
19. The well of claim 17, wherein the combusted gas is separated
into carbon dioxide and a fuel gas.
20. The well of claim 19, wherein the carbon dioxide produced is
re-injected into the formation.
21. The well of claim 15, wherein the proppant of the hydraulic
fractures contains a catalyst or a mixture of catalysts.
22. The well of claim 21, wherein the catalyst is one of a group of
hydrodesulfurization catalysts or thermal cracking catalysts or a
mixture thereof.
23. The well of claim 15, wherein a catalyst or mixture of
catalysts are placed in a canister in the well bore through which
the produced hydrocarbons flow.
24. The well of claim 23, wherein the catalyst is one of a group of
hydrodesulfurization catalysts or thermal cracking catalysts or a
mixture thereof.
25. The well of claim 15, wherein the pressure in the majority of
the part of the process zone is at ambient reservoir pressure.
26. The well of claim 15, wherein at least two vertical fractures
are installed from the bore hole at approximately orthogonal
directions.
27. The well of claim 15, wherein at least three vertical fractures
are installed from the bore hole.
28. The well of claim 15, 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.
TECHNICAL FIELD
[0002] The present invention generally relates to the enhanced
recovery of petroleum fluids from the subsurface by the injection
of an oxygen enriched gas into the oil sand formation for in situ
combustion of 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 rate and growth of the
combustion front, the flue gas composition, the flow of produced
hydrocarbons through a hot spent previously combusted zone
containing a catalyst for promoting in situ hydrodesulfurization
and thermal cracking, the operating reservoir pressures of the in
situ process, thus resulting in increased production and quality of
the produced 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 cohensionless 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 or oil sands, bitumen and
heavy oil, these terms will be used interchangeably herein. The oil
sand deposits in Alberta, Canada extend over many square miles and
vary in thickness up to hundreds of feet thick. Although some of
these deposits lie close to the surface and are suitable for
surface mining, the majority of the deposits are at depth ranging
from a shallow depth of 150 feet down to several thousands of feet
below ground surface. The oil sands located at these depths
constitute some of the world's largest presently known petroleum
deposits. The oil sands contain a viscous hydrocarbon material,
commonly referred to as bitumen, in an amount that ranges up to 15%
by weight. Bitumen is effectively immobile at typical reservoir
temperatures. For example at 15.degree. C., bitumen has a viscosity
of .about.1,000,000 centipoise. However at elevated temperatures
the bitumen viscosity changes considerably to be .about.350
centipoise at 100.degree. C. down to .about.10 centipoise at
180.degree. C. The oil sand deposits have an inherently high
permeability ranging from .about.1 to 10 Darcy, thus upon heating,
the heavy oil becomes mobile and can easily drain from the
deposit.
[0005] In situ methods of hydrocarbon extraction from the oil sands
consist of cold production, in which the less viscous petroleum
fluids are extracted from vertical and horizontal wells with sand
exclusion screens, CHOPS (cold heavy oil production system) cold
production with sand extraction from vertical and horizontal wells
with large diameter perforations thus encouraging sand to flow into
the well bore, CSS (cyclic steam stimulation) a huff and puff
cyclic steam injection system with gravity drainage of heated
petroleum fluids using vertical and horizontal wells, streamflood
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 the THAI (toe heel air
injection), a vertical injector well located near the base of a
horizontal producer well for an in situ combustion process, and
combinations of these methods.
[0006] Cyclic steam stimulation and steamflood hydrocarbon enhanced
recovery methods have been utilized worldwide, beginning in 1956
with the discovery of CSS, huff and puff or steam-soak in Mene
Grande field in Venezuela and for steamflood in the early 1960s in
the Kern River field in California. These steam assisted
hydrocarbon recovery methods including a combination of steam and
solvent are described, 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.
[0007] 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.
[0008] 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 insitu in the
presence of a metal catalyst, see U.S. Pat. No. 3,994,340 to
Anderson et al, U.S. Pat. No. 4,696,345 to Hsueh, U.S. Pat. No.
4,706,751 to Gondouin, U.S. Pat. No. 5,054,551 to Duerksen, and
U.S. Pat. No. 5,145,003 to Duerksen. It is disclosed that at
elevated temperature and pressure the injection of hydrogen or a
combination of hydrogen and carbon monoxide to the heavy oil in
situ in the presence of a metal catalyst will hydrogenate and
thermal crack at least a portion of the petroleum in the
formation.
[0009] Thermal recovery processes using steam require large amounts
of energy to produce the steam, using either natural gas or heavy
fractions of produced synthetic crude. Burning these fuels
generates significant quantities of greenhouse gases, such as
carbon dioxide. Also, the steam process uses considerable
quantities of water, which even though may be reprocessed, involves
recycling costs and energy use. Therefore a less energy intensive
oil recovery process is desirable.
[0010] Solvents applied to the bitumen soften the bitumen and
reduce its viscosity and provide a non-thermal mechanism to improve
the bitumen mobility. Hydrocarbon solvents consist of vaporized
light hydrocarbons such as ethane, propane, or butane or liquid
solvents such as pipeline diluents, natural condensate streams, or
fractions of synthetic crudes. The diluent can be added to steam
and flashed to a vapor state or be maintained as a liquid at
elevated temperature and pressure, depending on the particular
diluent composition. While in contact with the bitumen, the
saturated solvent vapor dissolves into the bitumen. This diffusion
process is due to the partial pressure difference in the saturated
solvent vapor and the bitumen. As a result of the diffusion of the
solvent into the bitumen, the oil in the bitumen becomes diluted
and mobile and will flow under gravity. The resultant mobile oil
may be deasphalted by the condensed solvent, leaving the heavy
asphaltenes behind within the oil sand pore space with little loss
of inherent fluid mobility in the oil sands due to the small weight
percent (5-15%) of the asphaltene fraction to the original oil in
place. Deasphalting the oil from the oil sands produces a high
grade quality product by 3.degree.-5.degree. API gravity. If the
reservoir temperature is elevated the diffusion rate of the solvent
into the bitumen is raised considerably being two orders of
magnitude greater at 100.degree. C. compared to ambient reservoir
temperatures of .about.15.degree. C.
[0011] Solvent assisted recovery of hydrocarbons in continuous and
cyclic modes are described including the VAPEX process and
combinations of steam and solvent plus heat, see U.S. Pat. No.
4,450,913 to Allen et al, U.S. Pat. No. 4,513,819 to Islip et al,
U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to
Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No.
6,318,464 to Mokrys, U.S. Patent 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
[0013] In situ combustion processes have been disclosed. See U.S.
Pat. No. 4, 454,916 to Shu, U.S. Pat. No. 4,474,237 to Shu, U.S
Pat. No. 4,566,536 to Holmes et al, 4,598,770 to Shu et al, U.S.
Pat. No. 4,625,800 to Venkatesan, U.S. Pat. No. 4,993,490 to
Stephens et al, U.S. Pat. No. 5,211,230 to Ostapovich et al, U.S.
Pat. No. 5,273,111 to Brannan et al, U.S. Pat. No. 5,339,897 to
Leaute, U.S. Pat. No. 5,413,224 to Laali, U.S. Pat. No. 5,626,191
to Greaves et al, U.S. Pat. No. 5,824,214 to Paul et al, U.S. Pat.
No. 5,871,637 to Brons, U.S. Pat. No. 5,954,946 to Klazinga et al,
and U.S. Pat. No. 6,412,557 to Ayasse et al. Many of these
disclosed methods involve in situ combustion of the in situ
hydrocarbon deposit with a combination of vertical and horizontal
wells. The process involves the injection of an oxygen rich
injection gas, igniting the in situ hydrocarbons, either by direct
ignition from a standard downhole burner, or from self ignition,
and drawing the produced flue gas off to create a gas pressure
gradient to control the rate and progress of the combustion front.
The difficulties experienced by the various disclosed methods are:
1) initiating connection of the injector, the combustion zone, and
producer to get the process started, 2) the potential for a liquid
and/or gravity block, i.e. mobile hydrocarbons can not flow to the
producer or combustion (flue) gases rise vertically rather than
flow to the producer, and 3) the difficulty of raising the
temperature of the produced hydrocarbons to initiate some form of
hydrodesulfurization and/or thermal cracking. Some of the disclosed
processes overcome some of these difficulties by heating a zone and
thus connecting the injector and producer prior to injection of the
oxygen rich gas injection and ignition of the hydrocarbon
formation. Other methods force the produced hydrocarbons to flow
through a spent previously combusted zone to raise the temperature
to induce some form of cracking process, while others propose
placement of a catalyst in the producer well to promote further
cracking at the elevated temperatures. The THAI (toe heel air
injection) combustion process has been demonstrated in laboratory
tests for application to oil sands, involving air injection in a
vertical well with the producer being a horizontal well at a deeper
depth and the combustion front progressing horizontally along the
alignment of the producer and downwards towards the producer.
[0014] 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.
[0015] 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, the methods, heat and solvent, or a combination
thereof, would greatly benefit from a substantial increase in
contact surface area with the in place bitumen. Hydraulic
fracturing of low permeable reservoirs has been used to increase
the efficiency of such processes and CSS methods involving
fracturing are described in U.S. Pat. No. 3,739,852 to Woods et al,
U.S. Pat. No. 5,297,626 to Vinegar et al, and U.S. Pat. No.
5,392,854 to Vinegar et al. Also during initiation of the SAGD
process, overpressurized conditions are usually imposed to
accelerated the steam chamber development, followed by a prolonged
period of underpressurized condition to reduce the steam to oil
ratio. Maintaining reservoir pressure during heating of the oil
sands has the significant benefit of minimizing water inflow to the
heated zone and to the well bore.
[0016] In situ combustion methods all suffer from poor connection
between the injected gas location, combustion zone, and producer
especially at initiation, and during propagation and growth of the
combustion front if barren or shale lenses are present or if the
oil sands have intrinsically low vertical permeability. The in situ
combustion method would benefit greatly from having good connection
between the injected gas location, combustion zone, and the
producer both at the initiation configuration and throughout the
propagation and growth of the combustion front. Highly permeable
vertical propped hydraulic fractures extending radially from the
injector would greatly benefit the process by providing a
connection to control the rate and growth of the combustion front
and thus guide the combustion front radially between the propped
fracture system.
[0017] 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 bore hole, 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 the 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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, 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.
[0022] 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.
[0023] 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, and Hocking
U.S. patent application Ser. Nos. 11/363,540, 11/277,308,
11/277,775, 11/277,815, and 11/277,789. 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.
[0024] Accordingly, there is a need for a method and apparatus for
enhancing the extraction of hydrocarbons from oil sands by in situ
combustion, 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
[0025] The present invention is a method and apparatus for the
enhanced recovery of petroleum fluids from the subsurface by in
situ combustion of the hydrocarbon deposit, by injecting an oxygen
rich gas, and by drawing off a flue gas to control the rate and
progation of the combustion front to be predominantly radially away
from the well bore and downwards to the bottom of the well bore,
from which the produced flue gas and hydrocarbons are extracted.
Multiple propped hydraulic fractures are constructed from the well
bore into the oil sand formation and filled with a highly permeable
proppant. The oxygen rich gas is injected via the well bore into
the top of the propped fractures, the in situ hydrocarbons are
ignited by a downhole burner, and the generated flue gas are
extracted from the bottom of the propped fractures through the well
bore. A mobile oil zone forms in front of the combustion front, and
the oil, under the influence of gravity, drains through the propped
fractures to the bottom of the well bore and is pumped to the
surface. The injection gas is injected into the well bore and into
the propped fractures at or near the ambient reservoir pressure but
substantially below the reservoir fracturing pressure. The flue gas
is extracted at a rate to control the propagation and shape of the
combustion front and the resultant oxygen content of the flue gas.
The upright and nearly vertical combustion front propagates
horizontally contacting the oil sands and in situ bitumen between
the vertical faces of the propped fractures. The combustion front
is predominantly upright, providing good vertical sweep and
advances radially in the horizontal direction with good lateral
sweep, due to the flue gas exhaust control provided by the highly
permeable propped fractures. Basically the combustion front is
guided by the radially entending vertical hydraulic fractures. The
flue gas is composed of combustion gases consisting of carbon
monoxide, carbon dioxide, sulfur dioxide, and water vapor.
[0026] The combustion front generates significant heat, which
diffuses into the bitumen ahead of the combustion front and heats
the bitumen sufficient for mobile oil to flow under gravity. The
bitumen softens and flows by gravity through the oil sands and the
propped fractures to the well bore. The generated flue gases and
produced hydrocarbons flow down the propped fractures to the well
bore heating the proppant in the process. The radial and downward
growth of the combustion front consumes the in situ hydrocarbon
first near the well bore and then progressively extends radially
outwards. Thus the proppant in the lower portions of the propped
fractures have been significantly heated by the passage of the
combustion front and thus are at sufficiently high a temperature to
induce thermal cracking of the cooler produced hydrocarbons
draining by gravity through this cracking zone to the well bore. A
catalyst placed as the proppant in the fractures or placed in a
canister in the well bore will further promote hydrodesulfurization
and thermal cracking and thus upgrading in situ the quality of the
produced hydrocarbon product. Such catalysts are really available
as HDS (hydrodesulfurization) metal containing catalysts and FCC
(fluid catalytic cracking) rare earth aluminum silica
catalysts.
[0027] The in situ produced hydrocarbon product and flue gas are
extracted from the bottom section of the well bore, with the rate
of flue gas extraction controlling the rate and growth of the
combustion front and the resultant oxygen content of the flue gas.
The injected gas could be air or an enriched oxygen injected gas to
limit degrading influences that air injection has on the resulting
the mobilized oil's viscosity. The process can operate close to
ambient reservoir pressures, so that water inflow into the process
zone can be minimized. Catalysts for hydrodesulftirization and
thermal cracking are contained in the proppant of the hydraulic
fractures or within a canister in the well bore. The proppant zone
in the lower portions of the hydraulic fractures will be raised to
combustion temperatures as the combustion front moves through this
zone in a radial growth direction. Therefore the produced
hydrocarbons will flow through this hot spent area and thus the
catalysts will promote upgrading of the mobile oil by
hydrodesulfurization and thermal cracking of some portions of the
produced hydrocarbon.
[0028] 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.
[0029] Therefore, the present invention provides a method and
apparatus for enhanced recovery of petroleum fluids from the
subsurface by the injection of an oxygen enriched gas in the oil
sand formation for the in situ combustion of 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, by controlling the rate and growth of the combustion
front, by controlling the flue gas composition, by controlling the
flow of produced hydrocarbons through a hot spent previously
combusted zone containing a catalyst for promoting in situ
hydrodesulfurization and thermal cracking, and by controlling the
operating reservoir pressures of the in situ process, thus
resulting in increased production and quality of the produced
petroleum fluids from the subsurface formation as well as limiting
water inflow into the process zone.
[0030] 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
[0031] 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.
[0032] 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.
[0033] FIG. 3 is an isometric view of a well casing having dual
propped fractures with downhole injected oxygen enriched gas,
combustion front, and gravity flow of produced hydrocarbons.
[0034] FIG. 4 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.
[0035] FIG. 5 is an isometric view of a well casing having four
propped fractures with downhole injected oxygen enriched gas,
combustion front, and gravity flow of produced hydrocarbons.
DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT
[0036] Several embodiments of the present invention are described
below and illustrated in the accompanying drawings. The present
invention is a method and apparatus for the enhanced recovery of
petroleum fluids from the subsurface by in situ combustion of the
hydrocarbon deposit, by injecting an oxygen rich gas, and by
drawing off a flue gas to control the rate and progation of the
combustion front to be predominantly horizontal away from the well
bore. Multiple propped hydraulic fractures are constructed from the
well bore into the oil sand formation and filled with a highly
permeable proppant. The oxygen rich gas is injected via the well
bore into the top of the propped fractures, the in situ
hydrocarbons are ignited by a downhole burner, the generated flue
gas is extracted from the bottom of the propped fractures through
the well bore, and the mobile oil drains by gravity through the
propped fractures to the bottom of the well bore and is pumped to
the surface. The combustion front is predominantly upright,
providing good vertical sweep and advances radially in the
horizontal direction with good lateral sweep, due to the flue gas
exhaust control provided by the highly permeable propped vertical
fractures.
[0037] 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 an in situ combustion enhanced
recovery system of the oil sand deposit, for the extraction of in
situ upgraded processed hydrocarbon fluids. 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 and the elevated temperatures
imposed by the combustion process. The grout 4 is a special purpose
cement for high temperature that preserves the spacing between the
exterior of the injection casing 1 and the bore hole 5 throughout
the fracturing procedure and in situ combustion process, preferably
being a non-shrink or low shrink cement based grout that can
withstand the imposed temperatures and differential strains.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] The pumping rate of the fracturing fluid and the viscosity
of the fracturing fluid 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 tt the viscosity of the
fracturing fluid at the shear rate in the fracture throat. The
Reynolds number is Re=pvw/.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 dilatant 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.sup.-1, needs to be greater than 100 centipoise.
[0042] 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) that are designed also to limit flow back of the
proppant from the fracture into the well bore. Due to the high
temperatures experienced by the proppant during the combustion
process, the proppant material will be specially selected to be
temperature compatible with the process and consist of clean strong
sands, ceramic beads, HDS and FCC catalysts, or a mixture thereof.
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 extent 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.
[0043] Referring to FIG. 3 for the in situ combustion process of
oil sands, 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 and the oil sand formation 8. A
downhole electric pump 17 is placed inside the casing, connected to
a power and instrumentation cable 18, with downhole packer 19, drop
tube 16 for flue gas extraction, drop tube 29 for injection of
oxygen enriched gas, and piping 9 for production of the produced
hydrocarbons to the surface. The oxygen enriched injection gas is
injected into the well bore at the top of the hydraulic fractures,
through the drop tube 29, through the screen 26, and into the
propped fractures 30 and oil sand formation 8, as shown by flow
vectors 12. The injection pressure is very close to reservoir
ambient pressure. The in situ hydrocarbons in the formation 8 in
the vicinity of the injected gas are ignited by a downhole burner.
The resulting combustion front generates significant heat, which
softens the bitumen in front of the combustion front 10 and forms a
fluid mobile hydrocarbon zone 28 in front of the combustion front
10. The oil in the mobile zone 28 drains by gravity 11 down to the
bottom of the hydraulic fracture and enters as shown by flow
vectors 15 into the well bore through the lower screen 25 and
accumulates at location 13 adjacent the pump 17. The accumulated
oil is pumped by the pump 17 as shown by arrows 14 through the
tubing 9 to the surface. The flue gas flows down to the lower
screen 25 as shown by flow vectors 27 in the spent combusted zone
and is extracted by the drop tube 16. The extraction rate of the
flue gas controls the propagation rate and growth of the combustion
front, and the resultant oxygen content of the flue gas. The
extraction rate of the flue gas is balanced to maintain an upright
combustion front with good vertical and lateral sweep, and
resulting in low oxygen content in the flue gas. The operating
pressure of the process is selected to be close to the ambient
reservoir pressure to minimize water inflow into the process zone.
The highly permeable hydraulic fractures enable close control of
flue gas exhaust and thus minimizes the pressure difference between
the injected and exhausted gases required to operate the
process.
[0044] The combustion zone 10 grows horizontally/radially from the
well bore casing 1, i.e. parallel 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 or spent by the combustion process. Upon
growth of the combustion zone radially to the lateral extent 31 and
vertical 32 extent of the propped fractures 30, the influence of
the hydraulic fractures on the connection between the various zones
falls off dramatically. It is at this stage that the process may be
stopped due to the limited lateral reach of the process compared to
the height of the combusted pay zone. That is, the injected gas may
preferentially short circuit to the flue gas extraction location at
the bottom of the well bore rather than flow to the combustion
front some large lateral distance away. The optimum configuration
of the process, i.e. its maximum lateral reach, will depend on the
height of the pay zone, the horizontal and vertical permeabilities
of the pay zone, the extent of barren or shale lenses within the
pay zone, and the ratio of propped fracture permeability to host
oil sand permeability.
[0045] Another embodiment of the present invention is shown on
FIGS. 4 and 5, 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 FIGS. 4 and 5. 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 top screen 26 for hydraulic connection of
the casing well bore 1 to the propped fractures 30 and the oil sand
formation 8. A downhole electric pump 17 is placed inside the
casing, connected to a power and instrumentation cable 18, with
downhole packer 19, drop tube 16 for flue gas extraction, drop tube
29 for injection of oxygen enriched gas, and piping 9 for
production of the produced hydrocarbons to the surface. The oxygen
enriched injection gas is injected into the well bore at the top of
the hydraulic fractures through the drop tube 29, through the
screen 26 and into the propped fractures 30 and oil sand formation
8, as shown by flow vectors 12. The injection is at a pressure very
close to reservoir ambient pressure. The in situ hydrocarbons in
the formation 8 in the vicinity of the injected gas 12 are ignited
by a downhole burner. The resulting combustion front generates
significant heat, which soften the bitumen in front of the front
and forms a fluid mobile hydrocarbon zone 28 in front of the
combustion front. The oil in the mobile zone 28 drains by gravity
11 down to the bottom of the hydraulic fracture and enters as shown
by flow vectors 15 into the well bore through the lower screen 25
and accumulates at location 13 adjacent the pump 17. The
accumulated oil is pumped by the pump 17 as shown by arrows 14
through the tubing 9 to the surface. The flue gas is extracted by
the drop tube 16 and flows down to the lower screen 25 as shown by
flow vectors 27. The extraction rate of the flue gas controls the
propagation rate and growth of the combustion front and the oxygen
content of the flue gas. The extraction rate of the flue gas is
balanced to maintain an upright combustion front with good vertical
and lateral sweep, and results in low oxygen content in the flue
gas. The operating pressure of the process is selected to be close
to the ambient reservoir pressure to minimize water inflow into the
process zone. The highly permeable hydraulic fractures enable close
control of flue gas exhaust and thus minimizes the pressure
difference between the injected and exhausted gases required to
operate the process.
[0046] 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.
* * * * *