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

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