High-pressure air injection (HPAI) is an increased-oil-recovery (IOR) process in which compressed air is injected into a deep light-oil reservoir with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. The resulting flue-gas mixture provides the main mobilizing force to the oil downstream of the reaction region, sweeping it toward production wells. The combustion zone itself may provide a critical part of the sweep mechanism.In 1994, proposed a method for estimating recovery factors of light-oil air-injection projects on the basis of the performance of two successful HPAI projects. Their suggested method relies on the extrapolation of the field gas/oil ratio (GOR) up to an economic limit. In other words, it treats HPAI as an immiscible gasflood and neglects any potential oil that could be recovered by the combustion front. The truth is that, although early production during an HPAI process is mostly caused by repressurization and gasflood effects, once a pore volume of air has been injected, the combustion front becomes the main driving mechanism. Moreover, one of the unique features of air injection is the self-correcting nature of the combustion zone, which promotes good volumetric sweep of the reservoir. This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and its beneficial impact on oil recovery. An analysis of the three HPAI projects in Buffalo field, which are the oldest HPAI projects currently in operation, shows that only a small fraction of the reservoir has been burned and, if time allows and the projects are managed appropriately, burning of more reservoir volumes could result in much higher oil recoveries than predicted by the gasflood approach. (482-572°F) range, while in heavier oils, bond-scission reactions are more likely to occur above 450°C (842°F). During oxygenaddition reactions, oxygen atoms are chemically bound into the molecular structure of the oil, producing various oxygenated compounds such as hydroperoxides, aldehydes, ketones, and acids. The compounds tend to further react and polymerize with each other, forming heavier, less-desirable fractions. To compound the problem, because oxygen is being removed from the gas phase to the

The Buffalo field air-injection units, located in northwest South Dakota, are the oldest high-pressure-air-injection (HPAI) projects currently in operation. Air injection began in January 1979, and as of December 2007, approximately 240 Bscf of air has been injected into the field. A total of 17.2 million bbl of incremental oil has been produced by the HPAI process, which is equivalent to 9.4% of the original oil in place (OOIP). The cumulative air/oil ratio (AOR) after 29 years of air injection is approximately 14 Mscf of air/bbl of incremental oil.This paper summarizes the performance of the projects and the overall experience gained by the operators after nearly 30 years of air injection. It covers almost every aspect of the entire operation since its inception; it discusses general management practices, technical and operational challenges encountered, injection and production facilities, and drilling and well-completion practices. It also includes estimates of incremental oil recovery caused by air injection and discusses how the air use has changed over time To date, the three HPAI projects in the Buffalo field continue to be a commercial success. In the last 3 years, horizontal laterals have been drilled out of more than 40 old vertical wells to enhance production, to take advantage of accumulated reservoir energy, and to improve sweep efficiency. Drilling injection wells out of old vertical wells was not possible because the openhole laterals cross a porosity zone that would have taken away some of the injection into nonproductive reservoir.

Following a series of laboratory imbibition cell experiments, field tests were conducted to determine the effectiveness of surfactant soak treatments as a single well EOR technique. The tests were conducted in the dolomite interval of the Phosphoria formation. Artificial intelligence was applied to analyze the mixed test results. The analysis suggested that the gamma ray log can be used to predict results and that a minimum amount of surfactant is required to improve production. Introduction Water imbibition as a recovery process was tested in the Spraberry field during the 1950's.1,2 This early work was followed by a test of the process in Cottonwood Creek field during the 1960's.3 About the time of these field tests a patent was issued4 that suggested surfactants could enhance the imbibition recovery process. A later patent5 implied that a Sprayberry field test was designed but results were not reported. Forty years later researchers6,7,8 returned to the subject of wettability alteration. A great deal of effort was expended during 70s and 80s in designing systems and field testing surfactants as a flooding EOR process. Maintaining the integrity of the chemical slug from injection well to producing wells was fraught with problems. However, slug integrity problems are diminished in single well EOR applications. Recent laboratory work focused on the easily performed and interpreted imbibition cell experiments. These experiments, with and without surfactants plus the reported success of pressure pulsing at Cottonwood Creek, prompted further laboratory testing with reservoir rock and fluids.9,10 This recent work indicated that a non-ionic surfactant could substantially increase recovery from Phosphoria wells in the Cottonwood Creek field. The shallow shelf carbonate reservoir is characterized as a steeply dipping, algal reef of the Phosphoria formation producing sour, 27° API, black oil from a dolomitized interval. Thickness of the dolomite varies from 20–100 ft. The average porosity is ~10% with ~1.0 md matrix permeability. The connate water saturation is ~10%. The low pressure and low temperature reservoir is believed to be naturally fractured and oil wet. The Cottonwood Creek Field is located in the Bighorn Basin of WY as shown in Fig. 1 and is operated by Continental Resources Incorporated. Statement of Theory and Definitions Fig. 2 shows three imbibition capillary pressure curve caricatures. Pc1 represents an oil-wet rock system. This system is expressed as a function of the J-factor with respect to oil saturation, J(So), in eq. 1. Capillary pressure is negative when oil spreads on the surface and cos ?o is negative.Equation 1 Pc2 represents a fluid rock system with surfactant present that both reduces the oil-water interfacial tension, s, and changes the contact angle, ?, from oil-wet to water-wet and a positive capillary pressure. The capillary pressure of this system is expressed as a function of the J-factor with respect to water saturation, J(Sw), in eq. 2.Equation 2 The surfactant fluid has been removed from the Pc3 system and replaced with water leaving only the water-wet contact angle. The Pc3 of this system is expressed as a function of the J-factor with respect to water saturation, J(Sw), in eq. 3.Equation 3

Summary Following a series of laboratory imbibition-cell experiments, field tests were conducted to determine the effectiveness of surfactant-soak treatments as a single-well enhanced-oil-recovery (EOR) technique. The tests were conducted in the dolomite interval of the Phosphoria formation. Artificial intelligence was applied to analyze the mixed test results. The analysis suggested that the gamma ray log can be used to predict results and that a minimum amount of surfactant is required to improve production. Introduction Water imbibition as a recovery process was tested in the Spraberry field during the 1950s (Elkins and Skov 1962, 1963). This early work was followed by a test of the process in Cottonwood Creek field during the 1960s (Willingham and McCaleb 1967). Around the time of these field tests, a patent was issued (Graham et al. 1957) that suggested surfactants could enhance the imbibition recovery process. A later patent (Stone et al. 1970) implied that a Spraberry field test was designed, but results were not reported. Forty years later, researchers (Spindler et al. 2000; Standnes and Austad 2000; Chen et al. 2000) returned to the subject of wettability alteration. One description of a field test of the surfactant-soak process has been published (Chen et al. 2000). A great deal of effort was expended during the 1970s and 1980s in designing systems and field testing surfactant fluids with ultralow interfacial tensions (IFTs) as a flooding EOR process. Maintaining the integrity of the chemical slug from the injection well to the producing wells was fraught with problems. However, slug-integrity problems are diminished in single-well EOR applications. Recent laboratory work focused on the easily performed and interpreted imbibition-cell experiments. These experiments (with and without surfactants) and the reported success of pressure pulsing at Cottonwood Creek prompted further laboratory testing with reservoir rock and fluids (Xie 2002; Xie et al. 2004). This recent work indicated that a nonionic surfactant could substantially increase recovery from Phosphoria wells in the Cottonwood Creek field. The shallow-shelf carbonate reservoir is characterized as a steeply dipping, algal reef of the Phosphoria formation producing sour, 27°API, black oil from a dolomitized interval. Thickness of the dolomite varies from 20 to 100 ft. The average porosity is ~10% with ~1.0 md matrix permeability. The connate-water saturation is ~10%. Pan American Petroleum reported the low-pressure and low-temperature reservoir to be naturally fractured and oil-wet (Willingham and McCaleb 1967). Their description was based on laboratory core studies. Tests performed in the 1990s generated U.S. Bureau of Mines (USBM) wettability values of -0.1, -0.12, -0.18, and -0.26. The Cottonwood Creek field is located in the Bighorn basin of Wyoming, as shown in Fig. 1, and is operated by Continental Resources Inc.

fax 01-972-952-9435. AbstractHigh-Pressure Air Injection (HPAI) is an IOR process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. The resulting flue gas mixture provides the main mobilizing force to the oil downstream of the reaction region, sweeping it to production wells. The combustion zone itself may provide a critical part of the sweep mechanism.In 1994 Fassihi et al. (SPE 28733) proposed a method for estimating recovery factors of light-oil air-injection projects based on the performance of two successful HPAI projects. Their suggested method relies on the extrapolation of the field gas-oil ratio up to an economic limit. In other words, it treats HPAI as an immiscible gasflood and neglects any potential oil that could be recovered by the combustion front. The truth is that, although early production during a HPAI process is mostly due to re-pressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism. Moreover, one of the unique features of air injection is the self-correcting nature of the combustion zone, which promotes good volumetric sweep of the reservoir. This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and its beneficial impact on oil recovery. An analysis of the three HPAI projects in Buffalo Field, which are the oldest HPAI projects currently in operation, shows that only a small fraction of the reservoir has been burned and, if time allows and the projects are managed appropriately, burning of more reservoir volumes could result in much higher oil recoveries than predicted by the gasflood approach.