U.S. patent application number 13/628178 was filed with the patent office on 2013-04-25 for steam flooding with oxygen injection, and cyclic steam stimulation with oxygen injection.
This patent application is currently assigned to Nexen Inc.. The applicant listed for this patent is Richard Kelso Kerr. Invention is credited to Richard Kelso Kerr.
Application Number | 20130098607 13/628178 |
Document ID | / |
Family ID | 48135022 |
Filed Date | 2013-04-25 |
United States Patent
Application |
20130098607 |
Kind Code |
A1 |
Kerr; Richard Kelso |
April 25, 2013 |
Steam Flooding with Oxygen Injection, and Cyclic Steam Stimulation
with Oxygen Injection
Abstract
A process to recover heavy oil from a hydrocarbon reservoir,
said process comprising injecting oxygen-containing gas and steam
separately injected via separate wells into the reservoir to cause
heated hydrocarbon fluids to flow more readily to a production
well, wherein: (i) the hydrocarbon is heavy oil (API from 10 to 20;
with some initial gas injectivity (ii) the ratio of oxygen/steam
injectant gas is controlled in the range from 0.05 to 1.00 (v/v)
(iii) the process uses Cyclic Steam Stimulation or Steam Flooding
techniques and well geometry, with extra well(s) or a segregated
zone to inject oxygen gas wherein the oxygen contact zone within
the reservoir is less than substantially 50 metres long.
Inventors: |
Kerr; Richard Kelso;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Kerr; Richard Kelso |
Calgary |
|
CA |
|
|
Assignee: |
Nexen Inc.
Calgary
CA
|
Family ID: |
48135022 |
Appl. No.: |
13/628178 |
Filed: |
September 27, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61550479 |
Oct 24, 2011 |
|
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|
Current U.S.
Class: |
166/256 ;
166/268 |
Current CPC
Class: |
E21B 43/24 20130101;
E21B 43/243 20130101; E21B 43/16 20130101 |
Class at
Publication: |
166/256 ;
166/268 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/243 20060101 E21B043/243 |
Claims
1. A process to recover heavy oil from a hydrocarbon reservoir,
said process comprising injecting oxygen-containing gas and steam
separately injected via separate wells into the reservoir to cause
heated hydrocarbon fluids to flow more readily to a production
well, wherein: (i) the hydrocarbon is heavy oil (API from about 10
to 20; with some initial gas injectivity (ii) the ratio of
oxygen/steam injectant gas is controlled substantially in the range
from 0.05 to 1.00 (v/v) (iii) the process uses Cyclic Steam
Stimulation or Steam Flooding techniques and well geometry, with
extra well(s) or a segregated zone to inject oxygen gas wherein the
oxygen contact zone within the reservoir is less than substantially
50 metres long.
2. The process of claim 1 wherein a separate well or segregation is
used for non-condensable gas produced by combustion.
3. The process of claim 1 wherein the oxygen-containing gas has an
oxygen content of 95 to 99.9% (v/v).
4. The process of claim 3 wherein the oxygen-containing gas has an
oxygen content of 95 to 97% (v/v).
5. The process of claim 1 wherein the oxygen-containing gas is
air.
6. The process of claim 5 wherein the oxygen-containing gas is
enriched air with an oxygen content of substantially 20 to 95%
(v/v).
7. The process of claim 1 wherein the oxygen injection well within
the reservoir is less than substantially 50 metres long proximate a
steam swept zone.
8. The process of claim 1 whereby the oxygen-containing gas
injection step is started only after a steam-swept zone is formed
around the injection point.
9. The process of claim 8 controlled by: (i) adjusting steam and
oxygen flow ratios to attain a target. (ii) adjusting steam +oxygen
flows to attain an energy rate target.
10. The process of claim 2 or 9 wherein a separate produced gas
removal well is used to minimize steam override to production
wells.
11. The process of claim 1 wherein oxygen/steam (v/v) ratios start
at about 0.05 and ramp up to about 1.00 as the process matures.
12. The process of claim 1 or 2 where the oxygen/steam (v/v) ratio
is held between 0.4 and 0.7 and most preferably 0.35.
13. The process of claim 1 wherein: (i) the ratio of oxygen/steam
(v/v) is between 0.4 and 0.7 (ii) the oxygen purity in the
oxygen-containing gas is between 95 and 97% (v/v).
14. The process of claim 1 or 7 further comprising an injector well
(either a separate vertical well or the segregated portion of a
well) having a maximum perforated zone (or zone with slotted
liners) of less than substantially 50 m so that oxygen flux rates
can be maximized.
15. The process of claim 14 wherein Oxygen is injected proximate a
steam-swept zone, whereby combustion of residual fuel in the
reservoir is the source of energy for said combustion, said zone
being preheated, at start-up, so spontaneous High Temperature
Oxidation can occur.
16. An improved Cyclic Steam Stimulation Enhanced Oil Recovery
process to recover heavy oil comprising adding oxygen gas during a
typical steam-injection cycle (the "huff"), the "soak" and "puff"
cycles being similar to conventional CSS, wherein the injection of
Oxygen provides extra energy from combustion of residual oil, for
heavy oil recovery while creating CO.sub.2 in the reservoir and
removing produced CO.sub.2 separately to better control the
process.
17. The process of claim 16 wherein an extra oxygen injection well
is utilized.
18. The process of claim 16 further comprising segregating oxygen
injection within steam injection wells using separate tubing and a
packer.
19. The process of claim 16 wherein steam and oxygen are injected
at separate times, as long as oxygen injection follows steam, so
the reservoir is preheated for auto-ignition of High Temperature
Oxidation combustion.
20. The process of claim 16 wherein; oxygen injection is segregated
near the top of the injector well or using a separate O.sub.2 well,
during the "huff" cycle, by injecting steam and oxygen; and during
the "puff" cycle removing produced gases (mainly CO.sub.2)
separately to better control the process.
21. The process of claim 16 wherein the CSSOX process is the
startup process for a SFOX process.
22. An improved Steam Flooding (SFOX EOR) Enhanced Oil Recovery
process to recover heavy oil, basically similar to a conventional
SF process, the improvement comprising injection of oxygen gas
continuously injected near (or at) the steam injector to provide an
added source of energy from in situ combustion of residual fuels,
said Steam and oxygen being injected in a vertical-well geometry,
with producer/injector wells arranged in regular patterns.
23. The process of claim 22 wherein separated wells are provided to
remove non-condensable combustion gases.
24. The process of claim 22 or 23 further comprising use of
horizontal wells, especially for the more viscous heavy oils.
25. The process of claim 1, 16 or 22 wherein the pipe sizes for
CSSOX or SFOX wells can be much smaller than for steam-only
processes because oxygen carries about ten times the heat content,
per unit volume.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to an enhanced oil recovery
process for heavy oil in subterranean reservoirs and specifically
processes for cyclic steam stimulation and/or steam flooding both
improved by the additional step of injecting oxygen into the
reservoir.
ACRONYM DICTIONARY OF TERMS
[0002] API American Petroleum Institute (density)
[0003] ASU Air Separation Unit (to produce oxygen gas)
[0004] CAGD Combustion Assisted Gravity Drainage
[0005] CIM Canadian Institute of Mining
[0006] COFCAW Combination of Forward Combustion and Waterflood
[0007] CSS Cyclic Steam Simulation
[0008] CSSOX CSS with Oxygen
[0009] DOE (US) Department of Energy
[0010] EOR Enhanced Oil Recovery
[0011] ETOR Energy to Oil Ratio (MMBTU/bbl)
[0012] HTO High Temperature Oxidation
[0013] ISC In Situ Combustion
[0014] JCPT Journal of Canadian Petroleum Technology
[0015] JPT Journal of Petroleum Technology
[0016] LTO Low Temperature Oxidation
[0017] OGJ Oil & Gas Journal
[0018] OOIP Original Oil in Place
[0019] SAGD Steam Assisted Gravity Drainage
[0020] SAGDOX SAGD+Oxygen
[0021] SF Steam Flood
[0022] SFOX Steam Flood with Oxygen
[0023] SOR Steam to Oil Ratio (bbls/bbl)
[0024] SPE Society of Petroleum Engineers
[0025] STARS Steam, Thermal and Advanced Process Reservoir
Simulator
REFERENCES
[0026] Anderson, R. E. et al--"Method of Direct Steam Generation
Using an Oxyfuel Combustor", Intl Pat. WO2010/101647 A2, 2010.
[0027] Arabian Oil & Gas Company, "Middle East Enhanced Oil
Recovery", May 5, 2011. [0028] Balog, S. et al., "The Wet Air
Oxidation Boiler for EOR", JCP, September-October, 1982. [0029]
Bousard, "Recovery of Oil by a Combustion of LTO and Hot Water or
Steam Injection", U.S. Pat. No. 3,976,137, August, 1976. [0030]
Butler, R. M., "Thermal Recovery of Oil & Bitumen", Prentice
Hall, 1991. [0031] Carcoana, A. N., "Enhanced Oil Recovery in
Rumania", SPE, April 1982. [0032] Donaldson, E. C. et al, "Enhanced
Oil Recovery II, Process and Operations Elsevier, 1989. [0033]
Escobar, E., et al, "Optimization Methodology for Cyclic Steam
Injection with Horizontal Wells", SPE/CIM, November, 2000. [0034]
Farouq Ali, S. M., et al, "The Promise and Problems of Enhanced Oil
Recovery Method. JCPT, July 1996. [0035] Frauenfeld, T. W. J. et
al., "Effect of an Initial Gas Content on Thermal EOR as Applied to
Oil Sands", JPT, March, 1988. [0036] Green Car Congress, "Chevron
leveraging information technology to optimize thermal production of
heavy oil with increased recovery and reduced costs". Jun. 23,
2011. [0037] Hanzlik, E. J., et al, "Forty Years of Steam Injection
in California--The Evolution of Heat Management", SPE, October,
2003. [0038] Heavyoilinfo.com, "Wafra pilot delivers for Chevron",
Oct. 21, 2010. [0039] Hong, K. C., et al, "Effects of
Noncondensable Gas Injection on Oil Recovery by Steam Floods, JPT,
December 1984. [0040] L. Lake et al, "A Niche for Enhanced Oil
Recovery in the 1990's, Oilfield Rev., January 1992. [0041] Leung,
L. C., "Numerical Evaluation of the Effect of Simultaneous Steam
and Carbon Dioxide Injection of the Recovery of Heavy Oil", JPT,
September, 1983. [0042] Luo, R. et al, "Feasibility Study of
CO.sub.2 Injection for Heavy Oil Reservoir After Cyclic Steam
Simulation: Liaohe Oil Field Test", SPE, November 2005. [0043]
Kumar, M., et al, "Cyclic steaming in Heavy Oil Diatomite", SPE,
March, 1995. [0044] Moore, R. G., et al, "In Situ Performance in
Steam Flooded Heavy Oil Cores", JCP, September, 1999. [0045] Moore,
R. G., et al, "Parametric Study of Steam Assisted In Situ
Combustion", unpublished, February, 1994. [0046] Nasr, T. N., et
al, "Thermal Techniques for the Recovery of Heavy Oil and Bitumen".
SPE, December, 2005. [0047] OGJ, "More US EOR Projects start but
EOR production continues to decline". Apr. 21, 2008. [0048]
Parrish, D. R. et al, "Laboratory Study of a Combination of Forward
Combustion and Waterflooding--the COFCAW Process", JPT, June, 1969.
[0049] Pfefferle, W. C., "Method for CAGD Recovery of Heavy Oil",
Intl Pat. WO2008/060311 A2, May, 2008. [0050] Praxair, website,
2010. [0051] Sarathi, P. "In Situ Combustion EOR Status", DOE,
1999. [0052] Sarkar et al, "Comparison of Thermal EOR Process Using
Combinations of Vertical and Horizontal Wells", SPE, February,
1993. [0053] Stevens, S. H. et al, "A Versatile Model for
Evaluation Thermal EOR Economics" SPE 1998.113, 1998. [0054] The
Jakarta Post, "12 Oil Companies to use EOR methods to boost
production", Jun. 27, 2011. [0055] Thomas. S. "Enhanced Oil
Recovery--An Overview", Oil & Gas Sci& Tech, 63, 2008.
[0056] Wylie et al, "Hot Fluid Recovery of Heavy Oil with Steam and
Carbon Dioxide", U.S. Pat. 2010/0276148 A1, November, 2010. [0057]
Yang, X. et al, "Combustion Kinetics of Athabasca Bitumen from 1D
Combustion Tube Experiments", Nat. Res. Res., 18, No. 3, September
2009(2). [0058] Yang, X. et al, "Design and Optimization of Hybrid
Ex Situ/In Situ Steam Generation Recovery Process for Heavy Oil and
Bitumen", SPE, Calgary, October 2008. [0059] Yang, X. et al,
"Design of Hybrid Steam--ISC Bitumen Recovery Processes". Nat. Res.
Res., Sep. 3, 2009(1). [0060] Zawierucua et al., "Material
Compatibility and Systems Considerations in Thermal EOR
Environments containing High-Pressure oxygen," JPT, November,
1988.
BACKGROUND OF THE INVENTION
[0061] Steam Floods (SF) and Cyclic Steam Stimulation (CSS) are EOR
processes that recover heavy oil and/or bitumen. These processes
have been practiced for over 50 years. The processes use steam to
deliver heat energy to the reservoir. An alternative to steam is to
use mixtures of steam and oxygen. Oxygen delivers heat by
combustion to supplement steam energy delivery.
[0062] The present invention supplements and improves steam floods
(SF) by adding oxygen gas (SFOX) and supplements and improves
cyclic steam stimulation (CSS) by adding oxygen gas (CSSOX).
Review of Prior Art
[0063] 2.1 Cyclic Steam Stimulation (CSS)
[0064] Perhaps the oldest process for thermal EOR is cyclic steam
stimulation (also called the "huff" and "puff" process).
[0065] As seen in FIG. 3, the process takes place using a vertical
well, in three steps--first, steam is injected until
injectivity/back-pressure limits injection rates or until a target
slug size of steam is injected (the "huff" part of the cycle). For
some reservoirs, fracture pressure may be exceeded during this
phase to create fractures that aid in steam distribution and
provide a conduit for oil flow. Second, the well is shut in and
allowed to "soak" for a few weeks/months. This helps to spread heat
by conduction and maximize the heated oil. Third, the well is put
on production and oil flows to surface or is pumped to surface (the
"puff" part of the cycle).
[0066] Although, a simple CSS process uses vertical wells. CSS can
also be conducted using horizontal or deviated wells (Sarker
(1993), Escobar (2000)). This can help distribute steam and shorten
the flow path of heated heavy oil during the production phase.
[0067] CSS heats oil and reduces viscosity so the oil can
more-easily flow to the production well. Steam also provides some
gas drive during the production cycle. CSS also uses a form of
gravity drainage, particularly if a partial steam chamber is
retained around the vertical well during the soak phase (FIG. 3).
Oil can drain downward and replace steam as it condenses (Butler
(1991)). The process has been labeled a "stimulation" process,
because even if the native oil has some mobility but rates are low,
by heating oil and the matrix rock, steam can reduce near-well-bore
resistance to oil flow and increase recovery rates.
[0068] CSS started in the 1950's in field trials. The largest CSS
project in the world is now the Imperial Oil (EXXON) project at
Cold Lake, Alberta (Table 4, FIG. 5, FIG. 8). For this project,
steam injection pressures cause vertical fractures to help
distribute steam and provide enhanced flow channels for heated
heavy oil. SAGD has now overtaken CSS as Canada's leading steam EOR
process (Table 4). Soon SAGD will be the largest single project for
steam EOR in Canada. But, CSS will remain a large producer.
[0069] CSS has also been recently introduced to the mid east
(Arabian Oil & Gas (2011)). Some of the issues with CSS include
the following: [0070] (1) For heavy oils, recovery is limited to
about 20% OOIP (Butler, (1992). Another process may be necessary,
post CSS, to exploit the reservoir [0071] (2) SOR deteriorates
(increases) as the project matures. [0072] (3) Production is not
continuous, for isolated wells [0073] (4) Inter well communication
may develop and necessitate cycle coordination of several wells
and/or a change in recovery process. [0074] (5) For bitumen, steam
injectivity is too poor to run CSS [0075] (6) High pressure CSS
requires monitoring to prevent well bore damage [0076] (7) Steam
override
[0077] 2.2 Steam Floods (SF)
[0078] If injectivity is good or if CSS wells start communicating,
the process can be changed to a steam flood, where steam is
injected continuously into one (or more) well and "pushes" heated
oil to one (or more) production wells. FIG. 9 shows the simple SF
geometry using vertical wells. Usually the wells are arranged in
regular patterns (e.g. FIG. 12). SF processes can recover more oil
than CSS, but, one of the problems with SF processes is steam
override, where steam rises to the top of the pay zone and breaks
through to the production well, bypassing the heated oil bank. This
can reduce productivity or even cause a premature abandonment of
the process. If the reservoir dips, it is advantageous to arrange
the wells so the steam injector is higher than the producer to take
advantage of gravity drainage and to minimize steam override (e.g.
California heavy oils).
[0079] One of the recent trends in SF is to consider the process,
at least partially, as a gravity drainage process and manage heat
input and production like SAGD (Green Car Cong. (2011). If this is
done, recovery factors can approach 70-80%, similar to SAGD
(ibid).
[0080] Horizontal wells are also being considered to improve
productivity and recovery (Green Car Cong. (2011)). SAGD (FIG. 2)
can be considered as a vertical SF using gravity drainage as the
dominant recovery mechanism (Butler, (1991)). Tangleflags, Sask. is
an example of a vertical SF using a combination of vertical steam
injectors and horizontal production wells (FIG. 7, Thomas (2008)).
SF based solely on horizontal wells is also feasible (FIG. 10).
[0081] Screening criteria for CSS and SF are similar (Table 2), but
SF processes can recover more oil than CSS and SF has dominated
world production for thermal EOR (FIG. 1). Both CSS and SF have
limitations in oil density (API>10), oil viscosity (.mu.<1000
cp.), depth (<5000 ft.), pay thickness (>20 ft.) and initial
oil saturation (S.sub.0>0.50). But, many of these limitations
are economic and were evaluated in an economic environment with low
oil prices (<$30/bbl), so the screens may be outdated. They are
not hard technical barriers. FIG. 6 shows thermal (steam) EOR is a
medium-cost EOR process (Lake (1992)).
[0082] SF EOR began in the USA in the 1950-1960's (Lake (1992)) and
the USA has continued as a dominant player (FIG. 5). In 1998,
California SF projects produced about 400 KBD using 20,000 vertical
wells in the Bakersfield area (Stevens (1998)). Chevron is the
largest US producer (Green, (2011)). The largest single SF project
is the Duri field, operated by Caltex, in Indonesia, currently
producing about 300 KBD (Jakarta Post (2011), FIG. 8). SF
technology has also been introduced to the Mid East (heavyoilinfo
(2010), Arabian Oil & Gas (2011)).
[0083] Some of the problems with SF include the following: [0084]
(1) SOR can be poor (higher than for SAGD). [0085] (2) Start-up may
be difficult or prolonged because of injectivity limitations or
lack of communication between injectors and producers. Often, SF is
started by CSS. [0086] (3) Fracturing can also be an issue. if a
fracture is formed, steam will flow in the fracture and transfer
heat, by conduction, to surrounding oil. But, production will be
slow because the steam is not driving the oil to the production
well. [0087] (4) If the reservoir is too deep, heat losses are a
concern. [0088] (5) Steam override is always an issue, unless we
have a tilted reservoir with a gravity drive component. [0089] (6)
Ultimate recovery, without gravity drainage, can still be poor (30
to 40% OOIP).
[0090] 2.3 Steam+Oxygen
[0091] COFCAW (combination of forward combustion and waterflood) is
a version of an ISC process that injects water to produce steam in
the reservoir. It produces a steam +oxygen (or air) mixture,
upstream of the combustion front (Parrish (1969)). But, the process
is a modified ISC process, not a modified SF process, and it is
suited to a vertical well geometry, not to a horizontal well
geometry. If liquid water is allowed to impinge on the combustion
front, HTO will be quenched and either oxygen gas will break
through to the production well or LTO oxidation will occur. LTO is
undesirable because oxygen use is incomplete, heat release per unit
oxygen consumed is less than HTO, and oxidation products include
organic acids that can create undesirable emulsions that can cause
reservoir blockages and/or oil/water (treating) separation
problems.
[0092] When oxygen combusts in a hydrocarbon reservoir, the
dominant, non-condensable gas produced is carbon dioxide.
Steam+O.sub.2 injected will produce steam+CO.sub.2 in the
reservoir. Several studies have looked at steam+CO.sub.2 for CSS or
SF EOR applications (Luo (2005), Frauenfeld (1988), Balog (1982)).
There has also been some activity to produce steam+CO.sub.2 or
steam+flue gas mixtures using surface or down hole equipment (Balog
(1982), Wylie (2010), Anderson (2010)). Steam+CO.sub.2 generally
has been shown to improve steam-only processes (CSS or SF). The
incremental benefits of CO, may be reduced if the heavy oil already
contains some dissolved gas (Frauenfeld (1988)). In some cases the
improvement due to CO.sub.2 was manifest in oil production rates,
not in ultimate recovery (Leung, (1983)).
[0093] Activity based on steam+oxygen injection has been much less
than steam+CO.sub.2. Laboratory combustion tube tests have been
performed using mixtures of steam+oxygen (Moore (1994), (1999)).
Combustion was very robust, showing good HTO combustion, even for
very low oxygen concentrations in the mixture. The combustion was
stable and more complete (less CO) than other oxidants (steam+air;
air). Oxygen concentrations in the mix varied from under 3 to over
12% (v/v).
[0094] Yang (2008) (2009(1)) proposed to use steam+oxygen as an
alternative to steam in a SAGD process. The process was simulated
using a modified STARS simulation model, incorporating combustion
kinetics. Yang demonstrated that for all oxygen mixes, the
combustion zone was contained in the gas/steam chamber, using
residual bitumen as a fuel. The combustion front never intersected
the steam chamber walls. But, the steam/gas chamber was contained
with no provision to remove non-condensable gases. So, back
pressure in the gas chamber inhibited gas injection and bitumen
production, using steam+oxygen mixtures. Also, there was no
consideration of the corrosion issue for steam+oxygen injection in
a horizontal well, nor was there any consideration of minimum
oxygen flux rates to initiate and sustain HTO combustion using a
long horizontal well for O.sub.2 injection.
[0095] Yang ((2008), 2009(1)) also proposed an alternating
steam/oxygen process as an alternative to continuous injection of
steam+O.sub.2 mixes. But, issues of corrosion, minimum oxygen flux
maintenance, ignition risks and combustion stability maintenance,
were not addressed.
[0096] Bousard (1976) proposed to inject air or oxygen with hot
water or steam to propagate LTO combustion as a method to inject
heat into a heavy oil reservoir. But HTO is desirable and LTO is
undesirable, as discussed above.
[0097] Pfefferle (2008) suggested using oxygen +steam mixtures in a
SAGD process, as a way to reduce steam demands and to partially
upgrade heavy oil. Combustion was purported to occur at the bitumen
interface (the chamber wall) and combustion temperature was
controlled by adjusting oxygen concentrations. But, as shown by
Yang, combustion will not occur at the chamber walls. It will occur
inside the steam chamber, using residual bitumen as a fuel not
bitumen from/at the chamber wall. Also, combustion temperature is
almost independent of oxygen concentration (Butler, 1991). It is
dependant on fuel (coke) lay-down rates by the combustion/pyrolysis
process. Pfefferle also suggested oxygen injection over the full
length of a horizontal well and did not address the issues of
corrosion, nor of maintaining minimum oxygen flux rates if a long
horizontal well is used for injection.
[0098] It is therefore a primary object of the invention to provide
an enhanced oil recovery process for both steam flooding and cyclic
steam stimulation wherein oxygen and steam are injected separately
into a heavy oil reservoir.
[0099] It is a further object of the invention to provide at least
one well to vent produced gases from the reservoir to control
reservoir pressures.
[0100] It is yet a further object of the invention to provide
oxygen at an amount of substantially 35% (v/v) and corresponding
steam levels at 65%.
[0101] It is yet a further object of the invention to provide pipe
sizes for CSSOX or SFOX wells that may be much smaller than for
steam-only processes because oxygen carries about ten times the
heat content, per unit volume.
[0102] Further and other objects of the invention will be apparent
to one skilled in the art when considering the following summary of
the invention and the more detailed description of the preferred
embodiments illustrated herein.
SUMMARY OF INVENTION
[0103] According to a primary aspect of the invention there is
provided a process to recover heavy oil from a hydrocarbon
reservoir, said process comprising injecting oxygen-containing gas
and steam separately injected via separate wells into the reservoir
to cause heated hydrocarbon fluids to flow more readily to a
production well, wherein: [0104] (i) the hydrocarbon is heavy oil
(API from 10 to 20; with some initial gas injectivity) [0105] (ii)
the ratio of oxygen/steam injectant gas is controlled in the range
from 0.05 to 1.00 (v/v) [0106] (iii) the process uses Cyclic Steam
Stimulation or Steam Flooding techniques and well geometry, with
extra well(s) or a segregated zone to inject oxygen gas, wherein
the oxygen contact zone within the reservoir is less than
substantially 50 metres long.
[0107] Preferably a separate well or segregation is used for
non-condensable gas produced by combustion.
[0108] In one embodiment the oxygen-containing gas has an oxygen
content of 95 to 99.9% (v/v).and preferably wherein the
oxygen-containing gas has an oxygen content of 95 to 97% (v/v).
[0109] In another embodiment the oxygen-containing gas is air.
[0110] Preferably the oxygen-containing gas is enriched air with an
oxygen content of substantially 20 to 95% (v/v).
[0111] In one embodiment the oxygen injection well within the
reservoir is less than substantially 50 metres long proximate a
steam swept zone.
[0112] Preferably the oxygen-containing gas injection step is
started only after a steam-swept zone is formed around the
injection point, preferably controlled by: [0113] adjusting steam
and oxygen flow ratios to attain a target. [0114] adjusting
steam+oxygen flows to attain an energy rate target.
[0115] In a preferred embodiment a separate produced gas removal
well is used to minimize steam override to production wells.
[0116] Preferably oxygen/steam (v/v) ratios start at about 0.05 and
ramp up to 1.00 as the process matures.
[0117] In another embodiment the oxygen/steam (v/v) ratio is held
between 0.4 and 0.7 and most preferably 0.35.
[0118] In a further embodiment the ratio of oxygen/steam (v/v) is
between 0.4 and 0.7 and the oxygen purity in the oxygen-containing
gas is between 95 and 97% (v/v).
[0119] In another embodiment the process further comprises an
injector well (either a separate vertical well or the segregated
portion of a well) having a maximum perforated zone (or zone with
slotted liners) of less than substantially 50 m so that oxygen flux
rates can be maximized.
[0120] Preferably Oxygen is injected proximate a steam-swept zone,
whereby combustion of residual fuel in the reservoir is the source
of energy for said combustion, said zone being preheated, at
start-up, so spontaneous High Temperature Oxidation can occur.
[0121] According to yet another embodiment of the invention there
is provided an improved Cyclic Steam Stimulation Enhanced Oil
Recovery process to recover heavy oil comprising adding oxygen gas
during a typical steam-injection cycle (the "huff"), the "soak" and
"puff" cycles being similar to conventional CSS, wherein the
injection of Oxygen provides extra energy from combustion of
residual oil, for heavy oil recovery while creating CO.sub.2 in the
reservoir and removing produced CO.sub.2 separately to better
control the process.
[0122] Preferably an extra oxygen injection well is utilized.
[0123] Preferably the process further comprises segregating oxygen
injection within steam injection wells using separate tubing and a
packer.
[0124] Steam and oxygen are injected at separate times, as long as
oxygen injection follows steam, so the reservoir is preheated for
auto-ignition of High Temperature Oxidation combustion.
[0125] In one embodiment of the process oxygen injection is
segregated near the top of the injector well or using a separate
O.sub.2 well, during the "huff" cycle, by injecting steam and
oxygen; and during the "puff" cycle removing produced gases (mainly
CO.sub.2) separately to better control the process.
[0126] In a preferred embodiment the CSSOX process is the startup
process for a SFOX process.
[0127] According to yet another aspect of the invention there is
provided an improved Steam Flooding (SFOX EOR) process Enhanced Oil
Recovery to recover heavy oil, basically similar to a conventional
SF process, the improvement comprising injection of oxygen gas
continuously injected near (or at) the steam injector to provide an
added source of energy from in situ combustion of residual fuels,
said Steam and oxygen being injected in a vertical-well geometry,
with producer/injector wells arranged in regular patterns.
[0128] In a preferred embodiment separate wells are provided to
remove non-condensable combustion gases.
[0129] Preferably the process further comprises use of horizontal
wells, especially for the more viscous heavy oils.
[0130] In a preferred embodiment of the process the pipe sizes for
CSSOX or SFOX wells can be much smaller than for steam-only
processes because oxygen carries about ten times the heat content,
per unit volume.
BRIEF DESCRIPTION OF THE FIGURES
[0131] FIG. 1 illustrates World EOR Production.
[0132] FIG. 2 illustrates the SAGD EOR Process.
[0133] FIG. 3 illustrates the CSS Process.
[0134] FIG. 4 illustrates an oil viscosity chart.
[0135] FIG. 5 illustrates USA/Canada Steam EOR.
[0136] FIG. 6 illustrates a cost comparison of EOR methods.
[0137] FIG. 7 illustrates Tangleflags steam flood.
[0138] FIG. 8 charts the Kern River, California and Duri, Indonesia
SF projects.
[0139] FIG. 9 illustrates SF geometry.
[0140] FIG. 10 illustrates a horizontal well SF.
[0141] FIG. 11 illustrates a SFOX geometry.
[0142] FIG. 12 illustrates a 5-spot pattern for SFOX.
[0143] FIG. 13 illustrates well geometry for CSSOX 1.
[0144] FIG. 14 illustrates well geometry for CSSOX 2.
[0145] FIG. 15 illustrates residual bitumen in steam-swept
zones.
[0146] FIG. 16 illustrates SFOX geometry.
[0147] FIG. 17 illustrates another SFOX geometry.
[0148] FIG. 18 illustrates CSSOX with produced gas removal.
DETAILED DESCRIPTION OF THE INVENTION
[0149] 3.1 Steam+Oxygen
[0150] If we inject steam and oxygen, in separate or segregated
streams, into a heavy oil reservoir, we have two separate sources
of heat. Oxygen will cause combustion of the residual heavy oil
left behind by steam. As shown in FIG. 15, we can expect residual
heavy oil to be about 10% (v/v) (of pore space). This is sufficient
to support and sustain combustion. Steam can transfer heat directly
to the reservoir constituents from latent heat (heat released when
steam condenses) or from sensible heat (heat transferred as hot
condensate cools).
[0151] As previously discussed (2.3), there are two kinds of
oxidation that can occur HTO (380-800.degree. C.) where combustion
produces mostly CO.sub.2, CO and H.sub.2O and LTO (150-300.degree.
C.) where combustion produces partially oxidized compounds
including organic acids that can cause production difficulties. HTO
is desirable and LTO is undesirable.
[0152] A convenient way to label steam+oxygen processes, for CSS or
SF applications, is to consider the oxygen content in the
steam+oxygen mix. (This doesn't imply that we inject a mixture or
that we expect good mixing in the reservoir). Using this
terminology, CSSOX (10) implies a 10% (v/v) oxygen concentration in
a steam/oxygen mix used fora CSS application (CSSOX=CSS with
oxygen). SFOX (10) implies the same mix used for an SF
application.
[0153] Table 1 shows the properties of various steam+oxygen mixes,
where we assume the heat release for oxygen combustion is 480
BTU/SCF (Butler (1991)) and we use an average steam heat content of
1000 BTU/lb. Because oxygen contains about 10 times the heat
content of a similar volume of steam, as oxygen concentration in
the mix increases, oxygen quickly dominates heat delivery. The
transition point where oxygen heat=steam heat is for a mixture
containing 9% (v/v) oxygen.
[0154] Mixtures of saturated steam and oxygen are very corrosive to
carbon steel and other alloys (Zawierucha (1988)). Separate wells
or a segregation system are needed. One suggestion (Yang (2009)) is
to use a steam injector for alternating volumes of steam and
oxygen. But, to sustain HTO combustion, we need a constant supply
and a minimum flux of oxygen (Sarathi (1999)), otherwise oxygen
will break through to production wells or LTO combustion may
start.
[0155] It has also been suggested that we can simply inject
mixtures of steam+oxygen and control corrosion using appropriate
alloys or inhibitors (Yang (2009), Pfefferle (2008)) but this is
difficult (Zawierucha (1988)). If a horizontal well is used as an
injector, we have corrosion issues, and oxygen flux rates may be a
concern. Oxygen flux is diluted over the length of the horizontal
well. In some areas, oxygen flux may be too low to sustain HTO.
Even if average flux rates are satisfactory, inhomogeneties in the
reservoir may cause local oxygen depletions.
[0156] Oxygen needs to be injected into (or near to) a steam-swept
zone, so combustion of residual fuel is the source of energy and
injectivity is not a problem. The zone needs to be preheated, at
start-up, so spontaneous HTO occurs.
[0157] There is a synergy between steam and oxygen for in situ EOR
processes. Steam helps combustion by preheating the reservoir so
auto-ignition can occur. In the combustion zone, steam adds OH and
H radicals that improve (accelerate) and stabilize HTO combustion
(ana)ogous to smokeless flare technology). Steam is an effective
heat transfer medium to attain high productivity. Steam also
increases combustion completeness (Moore (1994)). Oxygen helps
steam by reducing steam/water demands per unit energy injected,
generating extra steam by reflux, vaporizing connate water and
producing steam directly as a product of combustion. Oxygen also
increases energy efficiency. Oxygen adds CO.sub.2 that can dissolve
into heavy oil to reduce viscosity; providing dissolved gas drive
recovery mechanisms. When non-condensable gases migrate to the top
of the pay zone they will partially insulate the process from heat
loss to the overburden, extending the economic limit (oxygen costs
less than steam per unit heat delivered to the reservoir) to
increase ultimate recovery. Lastly, if some CO.sub.2 is retained in
the reservoir, CO.sub.2 emissions can be reduced.
[0158] 3.2 In Situ Combustion Chemistry
[0159] Oxygen creates energy in a heavy oil reservoir by
combustion. The "coke" that is prepared by hot combustion gases
fractionating and polymerizing residual heavy oil, can be
represented by a reduced formula of CH.sub.0.5. This ignores trace
components (S, N, O, . . . etc) and it doesn't imply a molecular
structure nor a molecular size. It only means that the "coke" has
an H/C atomic ratio of 0.5.
[0160] Let's also assume: [0161] (1) CO in the product gases is
about 10% of the carbon combusted (see Moore (1994)) for HTO.
[0162] (2) Water-gas-shift reactions occur to completion in the
reservoir--i.e. CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2+HEAT. This
reaction is favored by lower T (lower than combustion) and by high
concentrations of steam. The heat release is small compared to
combustion.
[0163] Then, our net combustion stoichiometry is determined as
follows:
[0164] Combustion:
CH.sub.0.5+1.075O.sub.2.fwdarw.0.9CO.sub.2+0.1CO+0.25H.sub.2O+HEAT
[0165] Shift:
0.1CO+0.1H.sub.2O.fwdarw.0.1CO.sub.2+0.1H.sub.2+HEAT
[0166] Net:
CH.sub.0.5+1.075O.sub.2.fwdarw.CO.sub.2+0.1H.sub.2+).15H.sub.2O+HEAT
[0167] Features are as follows: [0168] (1) heat release=480 BTU/SCF
O.sub.2 (Butler (1991)) [0169] (2) non-condensable gas make=102% of
oxygen used (v/v) [0170] (3) combustion net water make=14% of
oxygen used (v/v) [0171] (4) hydrogen gas make 9.3% of oxygen used
(v/v) [0172] (5) produced gas composition ((v/v) %):
TABLE-US-00001 [0172] Wet Dry CO.sub.2 80.0 90.9 H.sub.2 8.0 9.1
H.sub.2O 12.0 -- Total 100.0 100.0
[0173] (6) Combustion temperature is controlled by "coke" content
and matrix properties. Typically, HTO combustion T is between
(380-800.degree. C.).
[0174] 3.3 CSSOX
[0175] The CSSOX EOR process to recover heavy oil is similar to CSS
(previously described) but oxygen gas is added during the
steam-injection cycle (the "huff"). The "soak" and "puff" cycles
are similar to CSS. Oxygen provides extra energy from combustion,
and creates CO.sub.2 in the reservoir.
[0176] FIGS. 13 and 14 show how CSSOX can be conducted using an
extra oxygen injection well or by segregating oxygen injection
within the steam injection wells using separate tubing and a
packer. Alternately, steam and oxygen can be injected at separate
times, as long as oxygen injection follows steam, so the reservoir
is preheated for auto-ignition of HTO combustion.
[0177] If we segregate oxygen injection near the top of the
injector or using a separate O.sub.2 well, as shown in FIG. 18
during the "huff" cycle we inject steam and oxygen; during the
"puff" cycle we can remove produced gases (mainly CO.sub.2)
separately to better control the process.
[0178] 3.4 SFOX
[0179] The SFOX FOR process to recover heavy oil is similar to SF
(previously described) but oxygen gas is continuously injected near
(or at) the steam injector to provide an added source of energy
from in situ combustion. Steam+oxygen are injected in a
vertical-well geometry, with producer/injector wells arranged in
regular patterns.
[0180] FIGS. 9, 11 and 12 show how SFOX can be arranged. We can
also use horizontal wells as shown in FIG. 10, especially for the
more viscous heavy oils.
[0181] The distinction between SF and SAGD process can sometimes be
subtle. SAGD can be considered as a top-down steamflood, aided by
gravity drainage. FIG. 7 shows an example of a hybrid process (SF
and SAGD) where a vertical well is used as an injector and a lower
horizontal well is used as a producer.
[0182] Gas (steam) override is an issue for SF processes. It may be
advantageous in SFOX to include separate wells to remove
non-condensable combustion gases as shown in FIG. 16 or to
segregate production as shown in FIG. 17. Gas volumes are small and
these wells need not be large (Table 3).
[0183] 3.5 CSSOX/SFOX Advantages
[0184] Because, many times, a CSS project can be converted to a SF
project, or CSS is deliberately used as a start-up process for SF;
the advantages of the steam+oxygen version of each are similar--as
follows, comparing CSSOX and SFOX to their non-oxygen cousins:
[0185] (1) Lower energy costs (per unit heat delivered to the
reservoir, oxygen gas costs less than steam). [0186] (2) Reduced
water use, per bbl. of production. [0187] (3) More energy injected
per unit volume of injectant gas. Table 1 shows that and equal mix
(v/v) of oxygen and steam contains over 450 percent more energy
than pure steam. This can increase production rates. [0188] (4)
Excess water production. A combustion process will mobilize connate
water, in the combustion-swept zone, as steam. When produced, as
water, this will contribute to an excess water production if all
the injected steam is also produced as water. [0189] (5) Combustion
also produces water directly as a product of hydrocarbon oxidation.
[0190] (6) Carbon dioxide is produced by combustion. When CO.sub.2
dissolves into periphery heavy oil, it will provide a
dissolved-gas-drive mechanism and add to production and to ultimate
recovery (Balog (1982), Luo (2005)). [0191] (7) Steam stimulates
and helps HTO combustion (Moore (1994)). [0192] (8) Steam also
causes combustion to be more complete--less CO more CO.sub.2.
[0193] (9) If non-condensable gas is produced, it is mostly
CO.sub.2 and suitable for capture and sequestration. [0194] (10)
For the same reservoir pressure, average temperatures will be
higher. Oxidation or HTO combustion occurs at 380-800.degree. C.,
much higher than saturated steam temperatures for typical reservoir
pressures (1 to 4 MPa). [0195] (11) Up to a limit of oxygen
injection, the heavy oil (residual coke) that is combusted is oil
that would otherwise not be recovered (residual oil in the
steam-swept zone). [0196] (12) Steam-only processes leave behind
residual oil (about 10% of the pore space) Some of this oil is
mobilized and recovered by the steam+oxygen processes. [0197] (13)
If some of the combustion CO.sub.2 is left-behind in the reservoir
or if some of the produced CO.sub.2 is captured and sequestered,
CSSOX or SFOX can have reduced CO.sub.2 emissions compared to their
steam-only counterparts. [0198] (14) As shown in Table 3, because
oxygen carries about ten times the heat content, per unit volume,
pipe sizes for CSSOX or SFOX wells can be much smaller than for
steam-only processes. [0199] (15) Table 3 also demonstrates for a
wide range of oxygen+steam mixes, if we wish to deliver oxygen gas
at a segregated section in an existing steam injector (e.g. FIG.
14), there is enough room for an oxygen tube and steam in the
annulus, even for mixes as lean as 5% oxygen.
4. Preferred Embodiments
[0200] 4.1 Heavy Oil
[0201] This invention applies to heavy oil with some initial oil
mobility and initial gas injectivity. It does not apply to bitumen
(API<10) that is better suited to the SAGD-version SAGDOX (in a
separate patent).
[0202] For the purpose of this document we will define "heavy oil"
as between 10 API and 20 API, with some initial gas injectivity in
the reservoir.
[0203] 4.2 Separate Oxygen Injection
[0204] It has been suggested that EOR using a conventional SAGD
geometry could be conducted by substituting an oxygen +steam
mixture for steam (Yang (2009); Pfefferle (2008)). This is not a
good idea for two reasons: [0205] (1) Oxygen is different in its
effectiveness compared to steam. Steam has a positive effect
(adding heat) no matter how low the flux rate is or no matter how
low the concentration. For oxygen to initiate and sustain the
desired HTO combustion there is a minimum flux rate (Sarathi
(1999)). This minimum rate is expected to depend on the properties
of reservoir fluids, the properties of the reservoir and the
condition of the reservoir. If oxygen flux is too low, either
oxygen will break through, unused, to the produced gas removal well
and/or the production well and/or remain in the reservoir, or the
oxygen will initiate undesirable LTO reactions. [0206] If oxygen is
mixed with steam and injected into a long horizontal well (500 to
1000 m) the oxygen flux is dispersed/diluted over a long distance.
Even if the average oxygen flux is suitable to initiate and sustain
HTO combustion, heterogeneities in the reservoir can cause local
flux rates to be below the minimum needed. [0207] (2) Oxygen+steam
mixtures are very corrosive particularly to carbon steel. The
metallurgy of a conventional SAGD steam injector well could not
withstand a switch to steam+oxygen mixtures without significant
corrosion that could (quickly) compromise the well integrity.
Corrosion has been cited as one of the issues for ISC projects that
used enriched air or oxygen (Sarathi (1999)). [0208] The preferred
embodiment solution to these issues is to inject oxygen and steam
in separate wells or at segregated points to minimize corrosion.
Secondly, the injector well (either a separate vertical well or the
segregated portion of well) should have a maximum perforated zone
(or zone with slotted liners) of about 50 m so that oxygen flux
rates can be maximized.
[0209] 4.3 Oxygen Concentration Ranges
[0210] Oxygen concentration in steam/oxygen injectant mix is a
convenient way to quantify oxygen levels and to label processes
(e.g. SFOX (35) is a process that has 35% oxygen in the mix). But,
in reality we expect to inject oxygen and steam as separate gas
streams without any expectations of mixing in the reservoir or in
average or actual in situ gas concentrations. Rather than
controlling "concentrations", in practice would control to flow
ratios of oxygen/steam (or the inverse). So SFOX (35) would be a
SFOX process where the flow ratio of oxygen/steam was 0.5385
(v/v).
[0211] Our preferred range for CSSOX and SFOX has minimum and
maximum oxygen ratios, with the following rationale: [0212] (1) Our
minimum oxygen/steam ratio is 0.05 (v/v) (oxygen concentration of
about 5% (v/v)). Below this we start getting increased problems as
follows: [0213] (i) HTO combustion starts to become unstable. It
becomes more difficult to attain minimum oxygen flux rates to
sustain HTO, particularly for a mature SAGDOX process where the
combustion front is far away from the injector. [0214] (ii) It also
becomes difficult to vaporize and mobilize all connate water.
[0215] (iii) Below 5% it is difficult to inject oxygen and steam in
the same pipe, with a segregated oxygen tube, and maintain energy
injection rates (see Table 3). [0216] (2) Our maximum oxygen/steam
ratio is 1.00 (v/v) (oxygen concentration of 50.0% (v/v)). Above
this limit we start getting the following problems: [0217] (i)
Steam inventory in the reservoir drops to low levels, even with
some reflux. (steam is the preferred fluid for heat transfer).
[0218] (ii) The net bitumen ("coke") fuel that is consumed by
oxidation starts to exceed the residual fuel left behind in the
steam-swept zone. [0219] (iii) Above this limit it becomes
difficult (impossible) to produce steam and oxygen from an
integrated ASU: Cogen plant. [0220] (iv) The oil cut in the
production well increases and it may increase bulk viscosity and
impair productivity.
[0221] So, the preferred range for oxygen/steam ratios is 0.05 to
1.00 (v/v) corresponding to a concentration range of 5 to 50% (v/v)
of oxygen in the mix.
[0222] 4.4 Oxygen Purity
[0223] A cryogenic air separation unit (ASU) can produce oxygen gas
with a purity variation from about 95 to 99.9 (v/v) % oxygen
concentration. The higher end (99.0-99.9%) purity produces
"chemical" grade oxygen. The lower end of the range (95-97%) purity
consumes about 25% less energy (electricity) per unit oxygen
produced (Praxair (2010)). The "contaminant" gas is primarily
argon. Argon and oxygen have boiling points that are close, so
cryogenic separation becomes difficult and costly. If argon and
nitrogen in air remain unseparated, the resulting mixture is 95.7%
"pure" oxygen.
[0224] For EOR purposes, argon is an inert gas that should have no
impact on the process.
[0225] The preferred oxygen concentration is 95-97% purity (i.e.
the least energy consumed in ASU operations) 4.5 Operation
Strategy
[0226] In order to start oxygen injection as part of the CSSOX
process or for the SFOX process we need to meet the following
criteria: [0227] (i) When oxygen is first injected, the injection
point (well completion) is near to or inside a steam-swept zone, so
we can minimize temperatures near an injection point, consume oil
that would otherwise not be produced, and we have good gas
injectivity. [0228] (ii) The reservoir where we wish combustion to
occur has been preheated to about 200.degree. C. so oxygen will
spontaneously combust. [0229] (iii) The oxygen flux rate is high
enough to initiate and sustain HTO combustion.
[0230] After we have achieved these conditions we can start CSSOX
(in the "huff" cycle) or SFOX by: [0231] (i) Start oxygen (and
adjust steam) rates to achieve a target energy injection rate.
[0232] (ii) Adjust steam and oxygen rates to achieve a target flow
ratio. [0233] (iii) Monitor reservoir pressure and adjust rates or
the ratio to achieve a target pressure. [0234] (iv) For SFOX,
adjust production rates to control back pressure and/or to minimize
steam losses or oxygen losses to gas override. [0235] (v) Also for
CSSOX and SFOX, if we have a separate produced gas removal system
(FIGS. 16, 17, 18) controlling produced gas removal rate to
minimize steam (gas) override to the production well(s).
5. CSSOX/SFOX Uniqueness
[0236] 5.1 Distinguishing Features of CSSOX, SFOX [0237] (1)
Utilizes simultaneous injection of steam and oxygen [0238] (2)
Segregates oxygen injection [0239] (3) Has a preferred range of
oxygen/steam (v/v) ratios [0240] (4) Recognizes synergy benefits of
steam and oxygen [0241] (5) Has a preferred range of oxygen purity
[0242] (6) May have separate wells to remove non-condensable gases
produced by combustion [0243] (7) A procedure (criteria) to start
up SFOX and CSSOX processes [0244] (8) A procedure to
control/operate SFOX and CSSOX processes [0245] (9) Specific,
proposed well geometries [0246] (10) Reduced water use compared to
CSS or SF [0247] (11) Production of a "pure" CO.sub.2 gas stream
[0248] (12) With some CO.sub.2 capture or sequestration, reduced
CO.sub.2 emissions compared to SF or CSS. [0249] (13) Can be added
to existing SF or CSS processes [0250] (14) Compared to SF or CSS,
SFOX or CSSOX produce less fluid for the same oil production.
[0251] (15) Since oxygen is less costly than steam, CSSOX and SFOX
projects can be run longer than CSS or SF with inherently extra
reserves.
TABLE-US-00002 [0251] TABLE 1 Steam + Oxygen Mixtures % (v/v)
Oxygen in Mixture 0 5 9 35 50 75 100 % heat from O.sub.2 0 34.8
50.0 84.5 91.0 96.8 100 BTU/SCF Mix 47.4 69.0 86.3 198.8 263.7
371.9 480.0 MSCF/MMBTU 21.1 14.5 11.6 5.0 3.8 2.7 2.1 MSCF 0.0 0.7
1.0 1.8 1.9 2.0 2.1 O.sub.2/MMBTU MSCF 21.1 13.8 10.6 3.3 1.9 0.7
0.0 Steam/MMBTU Where: (1) Steam heat value = 1000 BTU/lb (avg.)
(2) O.sub.2 heat value = 480 BTU/SCF (Butler (1991)) (3) 0% oxygen
= pure steam
TABLE-US-00003 TABLE 2 Screening Criteria for SF EOR .phi. S.sub.0
API H (ft) D (ft) .mu.(cp) F. Ali .30 -- 12-15 30 <3000 <1000
(1979) Geffen -- -- >10 >20 <4000 -- (1973) Lewin --
>.50 >10 >20 <5000 -- (1976) Iyoho >.30 >.50
10-20 30-400 2500-5000 200-1000 (1978) Chu >.20 >.40 <36
>10 >400 -- (1985) Donaldson >.20 >.40 10-36 --
<5000 <1000 (1989) Where (1) the first 5 references are taken
from Butler, 1991 (2) .phi. = fractional porosity S.sub.0 =
original oil saturation API = density (API scale) H = net pay (ft.)
D = depth (ft.) .mu. = viscosity (cp)
TABLE-US-00004 TABLE 3 Steam + O.sub.2 Pipe Sizes % O.sub.2 (v/v)
in steam + O.sub.2 0 5 9 35 50 75 100 Per MMBTU SCF 21.1 13.8 10.6
3.3 1.9 0.7 0 Steam SCF 0.0 0.7 1.0 1.8 1.9 2.0 2.1 Oxygen SCF 21.1
14.5 11.6 5.0 3.8 2.7 2.1 Total Rel. pipe Dia. Steam 1 0.81 0.71
0.40 0.30 0.18 0 Oxygen 0 0.18 0.22 0.29 .30 .31 .32 Total 1 0.99
0.93 0.69 0.60 0.49 0.32 Where: (1) see also Table 1 (2) assumes
same linear velocity in pipe (3) volume rate capacity .alpha.
square of diameter (4) numbers may not add due to rounding
TABLE-US-00005 TABLE 4 Canadian Steam EOR Production Mar-(2011)
(kBD) SAGD Cenovus (Foster Creek) 118.7 Suncor (Firebag) 53.9 Devon
(Jackfish) 31.8 Suncor (Mackay) 31.2 MEG (Christina Lk.) 27.1 Nexen
(Long Lk.) 26.2 Conoco Phillips (Surmont) 22.3 Others 47.8 SAGD
Total 359.0 CSS Imp. Oil (Cold Lake) 162.0 Can Nat. (Primrose/Wolf
Lk.) 77.2 Others 5.1 CSS total 244.3 Canada Total 603.3 Where - (1)
First Energy Corp. Jun. 9, 2011.
[0252] As many changes therefore may be made to the embodiments of
the invention without departing from the scope thereof. It is
considered that all matter contained herein be considered
illustrative of the invention and not in a limiting sense.
* * * * *