Artificial Intelligence Used to Evaluate 23 Single-Well Surfactant-Soak Treatments
- William W. Weiss (Correlations Co.) | Xina Xie (INL & Correlations Co) | Jason Weiss (Correlations Co.) | Vishu Subramanian (Correlations Co.) | Archie R. Taylor (Continental Resources Inc.) | Fred J. Edens (Cimarex Energy Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2006
- Document Type
- Journal Paper
- 209 - 216
- 2006. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.4.1 Waterflooding, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.5 Geologic Modeling, 4.3.4 Scale, 2.2.2 Perforating, 5.3.2 Multiphase Flow, 7.6.6 Artificial Intelligence, 2 Well Completion, 4.1.2 Separation and Treating, 5.6.1 Open hole/cased hole log analysis, 1.6.9 Coring, Fishing, 5.8.7 Carbonate Reservoir
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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.
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.
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