Modeling of Pressure and Solution Gas for Chemical Floods
- Meghdad Roshanfekr (University of Texas at Austin) | Russell T. Johns (Pennsylvania State University) | Gary Pope (University of Texas at Austin) | Mojdeh Delshad (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- January 2013
- Document Type
- Journal Paper
- 428 - 439
- 2013. Society of Petroleum Engineers
- 5.2.1 Phase behavior and PVT measurements, 5.4.7 Chemical flooding methods, 5.2.2 Fluid Modeling, Equations of State
- 1 in the last 30 days
- 349 since 2007
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The goal of surfactant/polymer (SP) flooding is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimal salinity and optimal solubilization ratios that correspond to ultralow IFT have recently been shown, in some cases, to be a strong function of the methane mole fraction in the oil at reservoir pressure. We incorporate a recently developed methodology to determine the optimal salinity and solubilization ratio at reservoir pressure into a chemical-flooding simulator (UTCHEM). The proposed method determines the optimal conditions on the basis of density estimates by use of a cubic equation of state (EOS) and measured phase-behavior data at atmospheric pressure. The microemulsion phase-behavior (Winsor I, II, and III) are adjusted on the basis of this predicted optimal salinity and solubilization ratio in the simulator. Parameters for the surfactant phase-behavior equation are modified to account for these changes, and the trend in the equivalent alkane carbon number (EACN) is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase-behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase-behavior model into a chemical-flooding simulator allows for a better design of SP floods and more-accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir; however, the SP-flood simulation when free gas is present is not the focus of this paper. We show that not accounting for the phase-behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of an SP flood can lead to production of more oil as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical-flooding simulator, which requires the phase-behavior data measured at atmospheric pressure.
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