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
- 2 in the last 30 days
- 743 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
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|
Abrams, D.S. and Prausnitz, J.M. 1975. Statistical thermodynamics of liquidmixtures: A new expression for the excess Gibbs energy of partly or completelymiscible systems. AIChE J. 21 (1): 116-128. http://dx.doi.org/10.1002/aic.690210115.
Austad, T. and Strand, S. 1996. Chemical flooding of oil reservoirs 4.Effects of temperature and pressure on the middle phase solubilizationparameters close to optimum flood conditions. Colloids Surf., A 108 (2-3): 243-252. http://dx.doi.org/10.1016/0927-7757(95)03406-4.
Austad, T., Hodne, H., Strand, S., and Veggeland, K. 1996. Chemical floodingof oil reservoirs 5. The multiphase behavior of oil/brine/surfactant systems inrelation to changes in pressure, temperature, and oil composition. ColloidsSurf., A 108 (2-3): 253-262. http://dx.doi.org/10.1016/0927-7757(95)03405-6.
Bennett, K.E., Phelps, C.H.K., Davis, H.T., and Scriven, L.E. 1981.Microemulsion Phase Behavior Observations, Thermodynamic Essentials,Mathematical Simulation. SPE J. 21 (6): 747-762.SPE-9351-PA. http://dx.doi.org/10.2118/9351-PA.
Bourrel, M. and Schechter, R.S. 1988. Microemulsions and Related Systems:Formulation, Solvency, and Physical Properties, Vol. 30. New York:Surfactant Science Series, Marcel Dekker.
Delshad, M., Asakawa, K., Pope, G., and Sepehrnoori, K. 2002. Simulations ofChemical and Microbial Enhanced Oil Recovery Methods. Paper SPE 75237 presentedat the SPE/DOE Improved Oil Recovery Symposium, Tulsa, 13-17 April. http://dx.doi.org/10.2118/75237-MS.
Delshad, M., Pope, G.A., and Sepehrnoori, K. 1996. A compositional simulatorfor modeling surfactant enhanced aquifer remediation, 1 formulation. J.Contam. Hydrol. 23 (4): 303-327. http://dx.doi.org/10.1016/0169-7722(95)00106-9.
Healy, R.N., Reed, R.L., and Stenmark, D.K. 1976. Multiphase MicroemulsionSystems. SPE J. 16 (3): 147-160. SPE-5565-PA. http://dx.doi.org/10.2118/5565-PA.
Huh, C. 1979. Interfacial tensions and solubilizing ability of amicroemulsion phase that coexists with oil and brine. J. Colloid InterfaceSci. 71 (2): 408-426. http://dx.doi.org/10.1016/0021-9797(79)90249-2.
Kahlweit, M., Strey, R., Firman, P., Haase, D., Jen, J., and Schomaecker, R.1988. General patterns of the phase behavior of mixtures of water, nonpolarsolvents, amphiphiles, and electrolytes. 1. Langmuir 4 (3):499-511. http://dx.doi.org/10.1021/la00081a002.
Knudsen, K., Stenby, E.H., and Andersen, J.G. 1994. Modelling the influenceof pressure on the phase behavior of systems containing water oil and nonionicsurfactants. Fluid Phase Equilib. 93 (11 February 1994):55-74. http://dx.doi.org/10.1016/0378-3812(94)87003-9.
Koukounis, C., Wade, W.H., and Schechter, R.S. 1983. Phase Partitioning ofAnionic and Nonionic Surfactant Mixtures. SPE J. 23 (2):301-310. SPE-8261-PA. http://dx.doi.org/10.2118/8261-PA.
Lake, L.W. 1989. Enhanced Oil Recovery. Englewood Cliffs, New Jersey:Prentice Hall.
Michelsen, M.L. 1990. A method for incorporating excess Gibbs energy modelsin equations of state. Fluid Phase Equilib. 60 (1-2):47-58. http://dx.doi.org/10.1016/0378-3812(90)85042-9.
Nelson, R.C. 1983. The Effect of Live Crude on Phase Behavior andOil-Recovery Efficiency of Surfactant Flooding Systems. SPE J. 23 (3): 501-510. SPE-10677-PA. http://dx.doi.org/10.2118/10677-PA.
Pope, G.A. and Nelson, R.C. 1978. A Chemical Flooding CompositionalSimulator. SPE J. 18 (5): 339-354. SPE-6725-PA. http://dx.doi.org/10.2118/6725-PA.
Puerto, M.C. and Reed, R.L. 1983. A Three-Parameter Representation ofSurfactant/Oil/Brine Interaction. SPE J. 23 (4): 669-682.SPE-10678-PA. http://dx.doi.org/10.2118/10678-PA.
Roshanfekr, M. 2010. Effect of Pressure and Methane on MicroemulsionPhase Behavior and Its Impace on Surfactant-Polymer Flood Oil Recovery. PhDdissertation, The University of Texas at Austin, Austin, Texas (December2010).
Roshanfekr, M. and Johns, R.T. 2011. Prediction of optimum salinity andsolubilization ratio for microemulsion phase behavior with live crude atreservoir pressure. Paper presented at the 12th European Conference on theMathematics of Oil Recovery (ECMOR XII), Oxford, UK, 6-9 September.
Roshanfekr, M., Li, Y., and Johns, R.T. 2010. Non-iterative phase behaviormodel with application to surfactant flooding and limited compositionalsimulation. Fluid Phase Equilib. 289 (2): 166-175. http://dx.doi.org/10.1016/j.fluid.2009.11.024.
Salager, J.L., Morgan, J.C., Schechter, R.S., Wade, W.H., and Vasquez, E.1979. Optimum Formulation of Surfactant/Water/Oil Systems for MinimumInterfacial Tension or Phase Behavior. SPE J. 19 (2):107-115. SPE-7054-PA. http://dx.doi.org/10.2118/7054-PA.
Sassen, C.L., De Loos, T.W., and De Swaan Arons, J. 1991. Influence ofpressure on the phase behavior of the systemH2O+C10+C4E1 using a newexperimental setup. The Journal of Physical Chemistry 95(26): 10760-10763. http://dx.doi.org/10.1021/j100179a044.
Skauge, A. and Fotland, P. 1990. Effect of Pressure and Temperature on thePhase Behavior of Microemulsions. SPE Res Eng 5 (4):601-608. SPE-14932-PA. http://dx.doi.org/10.2118/14932-PA.
Soave, G. 1972. Equilibrium constants from a modified Redlich-Kwong equationof state. Chem. Eng. Sci. 27 (6): 1197-1203. http://dx.doi.org/10.1016/0009-2509(72)80096-4.
Southwick, J., Svec, Y., Chilek, G., and Shahin, G.T. 2010. The Effect ofLive Crude on Alkaline-Surfactant Polymer Formulations: Implications for FinalFormulation Design. Paper SPE 135357 presented at the SPE Annual TechnicalConference and Exhibition, Florence, Italy, 19-22 September. http://dx.doi.org/10.2118/135357-MS.