Simulation of the Effect of Pressure and Solution Gas on Oil Recovery From Surfactant/Polymer Floods
- Meghdad Roshanfekr (University of Texas at Austin) | Russell T. Johns (Pennsylvania State University at University Park) | Gary Pope (University of Texas at Austin) | Larry Britton (University of Texas at Austin) | Harold Linnemeyer (University of Texas at Austin) | Christopher Britton (University of Texas at Austin) | Alexander Vyssotski (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 2012
- Document Type
- Journal Paper
- 705 - 716
- 2012. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas
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- 754 since 2007
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Surfactant/polymer (SP) and alkali/surfactant/polymer flooding is of current interest because of the need to recover residual oil after primary and secondary recovery. If designed properly, these enhanced-oil-recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by performing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature, and the importance of those experimental results is conflicting.
This paper investigates the effect of pressure and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type II+) to lower microemulsion (Winsor Type II?), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. Using a numerical simulator, we show that these changes in the optimum conditions can significantly impact oil recovery if not accounted for in the SP design.
|File Size||1 MB||Number of Pages||12|
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