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.

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 &amp; 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  
       [0000]    
       
         
           
             Anderson, R. E. et al—“Method of Direct Steam Generation Using an Oxyfuel Combustor”, Intl Pat. WO2010/101647 A2, 2010. 
             Arabian Oil &amp; Gas Company, “Middle East Enhanced Oil Recovery”, May 5, 2011. 
             Balog, S. et al., “The Wet Air Oxidation Boiler for EOR”, JCP, September-October, 1982. 
             Bousard, “Recovery of Oil by a Combustion of LTO and Hot Water or Steam Injection”, U.S. Pat. No. 3,976,137, August, 1976. 
             Butler, R. M., “Thermal Recovery of Oil &amp; Bitumen”, Prentice Hall, 1991. 
             Carcoana, A. N., “Enhanced Oil Recovery in Rumania”, SPE, April 1982. 
             Donaldson, E. C. et al, “Enhanced Oil Recovery II, Process and Operations Elsevier, 1989. 
             Escobar, E., et al, “Optimization Methodology for Cyclic Steam Injection with Horizontal Wells”, SPE/CIM, November, 2000. 
             Farouq Ali, S. M., et al, “The Promise and Problems of Enhanced Oil Recovery Method. JCPT, July 1996. 
             Frauenfeld, T. W. J. et al., “Effect of an Initial Gas Content on Thermal EOR as Applied to Oil Sands”, JPT, March, 1988. 
             Green Car Congress, “Chevron leveraging information technology to optimize thermal production of heavy oil with increased recovery and reduced costs”. Jun. 23, 2011. 
             Hanzlik, E. J., et al, “Forty Years of Steam Injection in California—The Evolution of Heat Management”, SPE, October, 2003. 
             Heavyoilinfo.com, “Wafra pilot delivers for Chevron”, Oct. 21, 2010. 
             Hong, K. C., et al, “Effects of Noncondensable Gas Injection on Oil Recovery by Steam Floods, JPT, December 1984. 
             L. Lake et al, “A Niche for Enhanced Oil Recovery in the 1990&#39;s, Oilfield Rev., January 1992. 
             Leung, L. C., “Numerical Evaluation of the Effect of Simultaneous Steam and Carbon Dioxide Injection of the Recovery of Heavy Oil”, JPT, September, 1983. 
             Luo, R. et al, “Feasibility Study of CO 2  Injection for Heavy Oil Reservoir After Cyclic Steam Simulation: Liaohe Oil Field Test”, SPE, November 2005. 
             Kumar, M., et al, “Cyclic steaming in Heavy Oil Diatomite”, SPE, March, 1995. 
             Moore, R. G., et al, “In Situ Performance in Steam Flooded Heavy Oil Cores”, JCP, September, 1999. 
             Moore, R. G., et al, “Parametric Study of Steam Assisted In Situ Combustion”, unpublished, February, 1994. 
             Nasr, T. N., et al, “Thermal Techniques for the Recovery of Heavy Oil and Bitumen”. SPE, December, 2005. 
             OGJ, “More US EOR Projects start but EOR production continues to decline”. Apr. 21, 2008. 
             Parrish, D. R. et al, “Laboratory Study of a Combination of Forward Combustion and Waterflooding—the COFCAW Process”, JPT, June, 1969. 
             Pfefferle, W. C., “Method for CAGD Recovery of Heavy Oil”, Intl Pat. WO2008/060311 A2, May, 2008. 
             Praxair, website, 2010. 
             Sarathi, P. “In Situ Combustion EOR Status”, DOE, 1999. 
             Sarkar et al, “Comparison of Thermal EOR Process Using Combinations of Vertical and Horizontal Wells”, SPE, February, 1993. 
             Stevens, S. H. et al, “A Versatile Model for Evaluation Thermal EOR Economics” SPE 1998.113, 1998. 
             The Jakarta Post, “12 Oil Companies to use EOR methods to boost production”, Jun. 27, 2011. 
             Thomas. S. “Enhanced Oil Recovery—An Overview”, Oil &amp; Gas Sci&amp; Tech, 63, 2008. 
             Wylie et al, “Hot Fluid Recovery of Heavy Oil with Steam and Carbon Dioxide”, U.S. Pat. 2010/0276148 A1, November, 2010. 
             Yang, X. et al, “Combustion Kinetics of Athabasca Bitumen from 1D Combustion Tube Experiments”, Nat. Res. Res., 18, No. 3, September 2009(2). 
             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. 
             Yang, X. et al, “Design of Hybrid Steam—ISC Bitumen Recovery Processes”. Nat. Res. Res., Sep. 3, 2009(1). 
             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&#39;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&#39;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 &amp; Gas (2011)). Some of the issues with CSS include the following:
       (1) For heavy oils, recovery is limited to about 20% OOIP (Butler, (1992). Another process may be necessary, post CSS, to exploit the reservoir   (2) SOR deteriorates (increases) as the project matures.   (3) Production is not continuous, for isolated wells   (4) Inter well communication may develop and necessitate cycle coordination of several wells and/or a change in recovery process.   (5) For bitumen, steam injectivity is too poor to run CSS   (6) High pressure CSS requires monitoring to prevent well bore damage   (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&gt;10), oil viscosity (μ&lt;1000 cp.), depth (&lt;5000 ft.), pay thickness (&gt;20 ft.) and initial oil saturation (S 0 &gt;0.50). But, many of these limitations are economic and were evaluated in an economic environment with low oil prices (&lt;$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&#39;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 &amp; Gas (2011)). 
         [0083]    Some of the problems with SF include the following:
       (1) SOR can be poor (higher than for SAGD).   (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.   (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.   (4) If the reservoir is too deep, heat losses are a concern.   (5) Steam override is always an issue, unless we have a tilted reservoir with a gravity drive component.   (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 2  injected will produce steam+CO 2  in the reservoir. Several studies have looked at steam+CO 2  for CSS or SF EOR applications (Luo (2005), Frauenfeld (1988), Balog (1982)). There has also been some activity to produce steam+CO 2  or steam+flue gas mixtures using surface or down hole equipment (Balog (1982), Wylie (2010), Anderson (2010)). Steam+CO 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 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 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 2  injection. 
         [0095]    Yang ((2008), 2009(1)) also proposed an alternating steam/oxygen process as an alternative to continuous injection of steam+O 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:
       (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.
       
 
         [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:
       adjusting steam and oxygen flow ratios to attain a target.   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 2  in the reservoir and removing produced CO 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 2  well, during the “huff” cycle, by injecting steam and oxygen; and during the “puff” cycle removing produced gases (mainly CO 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° C.) where combustion produces mostly CO 2 , CO and H 2 O and LTO (150-300° 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&#39;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 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 2  is retained in the reservoir, CO 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 0.5 . This ignores trace components (S, N, O, . . . etc) and it doesn&#39;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&#39;s also assume:
       (1) CO in the product gases is about 10% of the carbon combusted (see Moore (1994)) for HTO.   (2) Water-gas-shift reactions occur to completion in the reservoir—i.e. CO+H 2 O→CO 2 +H 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 0.5 +1.075O 2 →0.9CO 2 +0.1CO+0.25H 2 O+HEAT 
         [0165]    Shift: 0.1CO+0.1H 2 O→0.1CO 2 +0.1H 2 +HEAT 
         [0166]    Net: CH 0.5 +1.075O 2 →CO 2 +0.1H 2   +).15 H 2 O+HEAT 
         [0167]    Features are as follows:
       (1) heat release=480 BTU/SCF O 2  (Butler (1991))   (2) non-condensable gas make=102% of oxygen used (v/v)   (3) combustion net water make=14% of oxygen used (v/v)   (4) hydrogen gas make 9.3% of oxygen used (v/v)   (5) produced gas composition ((v/v) %):       
 
         [0000]    
       
         
               
               
               
             
               
               
               
               
             
           
               
                   
                   
               
               
                   
                 Wet 
                 Dry 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 CO 2   
                 80.0 
                 90.9 
               
               
                   
                 H 2   
                 8.0 
                 9.1 
               
               
                   
                 H 2 O 
                 12.0 
                 — 
               
               
                   
                 Total 
                 100.0 
                 100.0 
               
               
                   
                   
               
             
          
         
       
       
         
           
             (6) Combustion temperature is controlled by “coke” content and matrix properties. Typically, HTO combustion T is between (380-800° 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 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 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 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:
       (1) Lower energy costs (per unit heat delivered to the reservoir, oxygen gas costs less than steam).   (2) Reduced water use, per bbl. of production.   (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.   (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.   (5) Combustion also produces water directly as a product of hydrocarbon oxidation.   (6) Carbon dioxide is produced by combustion. When CO 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)).   (7) Steam stimulates and helps HTO combustion (Moore (1994)).   (8) Steam also causes combustion to be more complete—less CO more CO 2 .   (9) If non-condensable gas is produced, it is mostly CO 2  and suitable for capture and sequestration.   (10) For the same reservoir pressure, average temperatures will be higher. Oxidation or HTO combustion occurs at 380-800° C., much higher than saturated steam temperatures for typical reservoir pressures (1 to 4 MPa).   (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).   (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.   (13) If some of the combustion CO 2  is left-behind in the reservoir or if some of the produced CO 2  is captured and sequestered, CSSOX or SFOX can have reduced CO 2  emissions compared to their steam-only counterparts.   (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.   (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&lt;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:
       (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.
           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.   
           (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)).
           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:
       (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:
           (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.   (ii) It also becomes difficult to vaporize and mobilize all connate water.   (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).   
           (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:
           (i) Steam inventory in the reservoir drops to low levels, even with some reflux. (steam is the preferred fluid for heat transfer).   (ii) The net bitumen (“coke”) fuel that is consumed by oxidation starts to exceed the residual fuel left behind in the steam-swept zone.   (iii) Above this limit it becomes difficult (impossible) to produce steam and oxygen from an integrated ASU: Cogen plant.   (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:
       (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.   (ii) The reservoir where we wish combustion to occur has been preheated to about 200° C. so oxygen will spontaneously combust.   (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:
       (i) Start oxygen (and adjust steam) rates to achieve a target energy injection rate.   (ii) Adjust steam and oxygen rates to achieve a target flow ratio.   (iii) Monitor reservoir pressure and adjust rates or the ratio to achieve a target pressure.   (iv) For SFOX, adjust production rates to control back pressure and/or to minimize steam losses or oxygen losses to gas override.   (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
       (1) Utilizes simultaneous injection of steam and oxygen   (2) Segregates oxygen injection   (3) Has a preferred range of oxygen/steam (v/v) ratios   (4) Recognizes synergy benefits of steam and oxygen   (5) Has a preferred range of oxygen purity   (6) May have separate wells to remove non-condensable gases produced by combustion   (7) A procedure (criteria) to start up SFOX and CSSOX processes   (8) A procedure to control/operate SFOX and CSSOX processes   (9) Specific, proposed well geometries   (10) Reduced water use compared to CSS or SF   (11) Production of a “pure” CO 2  gas stream   (12) With some CO 2  capture or sequestration, reduced CO 2  emissions compared to SF or CSS.   (13) Can be added to existing SF or CSS processes   (14) Compared to SF or CSS, SFOX or CSSOX produce less fluid for the same oil production.   (15) Since oxygen is less costly than steam, CSSOX and SFOX projects can be run longer than CSS or SF with inherently extra reserves.       
 
         [0000]    
       
         
               
             
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 Steam + Oxygen Mixtures 
               
               
                 % (v/v) Oxygen in Mixture 
               
             
          
           
               
                   
                 0 
                 5 
                 9 
                 35 
                 50 
                 75 
                 100 
               
               
                   
                   
               
             
          
           
               
                 % heat from O 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 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 2  heat value = 480 BTU/SCF (Butler (1991)) 
               
               
                 (3) 0% oxygen = pure steam 
               
             
          
         
       
     
         [0000]    
       
         
               
             
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Screening Criteria for SF EOR 
               
             
          
           
               
                   
                 φ 
                 S 0   
                 API 
                 H (ft) 
                 D (ft) 
                 μ(cp) 
               
               
                   
                   
               
             
          
           
               
                 F. Ali 
                 .30 
                 — 
                 12-15 
                 30 
                 &lt;3000 
                 &lt;1000 
               
               
                 (1979) 
               
               
                 Geffen 
                 — 
                 — 
                 &gt;10 
                 &gt;20 
                 &lt;4000 
                 — 
               
               
                 (1973) 
               
               
                 Lewin 
                 — 
                 &gt;.50 
                 &gt;10 
                 &gt;20 
                 &lt;5000 
                 — 
               
               
                 (1976) 
               
               
                 Iyoho 
                 &gt;.30 
                 &gt;.50 
                 10-20 
                 30-400 
                 2500-5000 
                 200-1000 
               
               
                 (1978) 
               
               
                 Chu 
                 &gt;.20 
                 &gt;.40 
                 &lt;36 
                 &gt;10 
                 &gt;400 
                 — 
               
               
                 (1985) 
               
               
                 Donaldson 
                 &gt;.20 
                 &gt;.40 
                 10-36 
                 — 
                 &lt;5000 
                 &lt;1000 
               
               
                 (1989) 
               
               
                   
               
               
                 Where (1) the first 5 references are taken from Butler, 1991 
               
               
                 (2) φ = fractional porosity 
               
               
                 S 0  = original oil saturation 
               
               
                 API = density (API scale) 
               
               
                 H = net pay (ft.) 
               
               
                 D = depth (ft.) 
               
               
                 μ = viscosity (cp) 
               
             
          
         
       
     
         [0000]    
       
         
               
             
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 Steam + O 2  Pipe Sizes 
               
               
                 % O 2  (v/v) in steam + O 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 α square of diameter 
               
               
                 (4) numbers may not add due to rounding 
               
             
          
         
       
     
         [0000]    
       
         
               
             
               
               
             
               
               
               
             
           
               
                 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.