An Analytical Solution for Three-Component, Two-Phase Surfactant Flooding Dependent on the Hydrophilic/Lipophilic-Difference Equation and the Net-Average-Curvature Equation of State
- Luchao Jin (University of Oklahoma) | Zhitao Li (Ultimate EOR Services) | Ahmad Jamili (University of Oklahoma) | Mohannad Kadhum (University of Oklahoma) | Jun Lu (University of Tulsa) | Bor-Jier Shiau (University of Oklahoma) | Jeffrey H. Harwell (University of Oklahoma) | Mojdeh Delshad (University of Tulsa and University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- October 2017
- Document Type
- Journal Paper
- 1,424 - 1,436
- 2017.Society of Petroleum Engineers
- surfactant flooding, HLD-NAC, phase behavior, Analytical solution
- 2 in the last 30 days
- 375 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Microemulsion phase behavior is crucial to surfactant flooding performance and design. In previous studies, analytical/numerical solutions for surfactant flooding were developed dependent on the classical theory of multicomponent/multiphase displacement and empirical microemulsion phase-behavior models. These phase-behavior models were derived from empirical correlations for component-partition coefficients or from the Hand-rule model (Hand 1930), which empirically represents the ternary-phase diagram. These models may lack accuracy or predictive abilities, which may lead to improper formulation design or unreliable recovery predictions.
To provide a more-insightful understanding of the mechanisms of surfactant flooding, we introduced a novel microemulsion phase-behavior equation of state (EOS) dependent on the hydrophilic/lipophilic-difference (HLD) equation and the net-average curvature (NAC) model, which is called HLD-NAC EOS hereafter. An analytical model for surfactant flooding was developed dependent on coherence theory and this novel HLD-NAC EOS for two-phase three-component displacement. Composition routes, component profile along the core, and oil recovery can be determined from the analytical solution.
The analytical solution was validated against numerical simulation as well as experimental study. This HLD-NAC EOS based analytical solution enables a systematic study of the effects of phase-behavior-dependent variables on surfactant-flooding performance. The effects of solution gas and pressure on microemulsion phase behavior were investigated. It was found that an increase of solution gas and pressure would lead to enlarged microemulsion bank and narrowed oil bank. For a surfactant formulation designed at standard conditions, the analytical solution was able to quantitatively predict its performance under reservoir conditions.
|File Size||1 MB||Number of Pages||13|
Aanonsen, S. I. 1989. Application of Fractional-Flow Theory To 3-Phase, 1-Dimensional Surfactant Flooding. Oral presentation given at ECMOR I–1st European Conference on the Mathematics of Oil Recovery, Cambridge, UK, 1 July.
Acosta, E. J. 2008. The HLD–NAC Equation of State for Microemulsions Formulated With Nonionic Alcohol Ethoxylate and Alkylphenol Ethoxylate Surfactants. Colloid. Surface. A 320 (1–3): 193–204. https://doi.org/10.1016/j.colsurfa.2008.01.049.
Acosta, E. J. and Bhakta, A. S. 2009. The HLD-NAC Model for Mixtures of Ionic and Nonionic Surfactants. J. Surfactants Deterg. 12 (1): 7–19. https://doi.org/10.1007/s11743-008-1092-4.
Acosta, E. J., Kiran, S. K., and Hammond, C.E. 2012. The HLD-NAC Model for Extended Surfactant Microemulsions. J. Surfactants Deterg. 15 (4): 495–504. https://doi.org/10.1007/s11743-012-1343-2.
Acosta, E. J., Szekeres, E., Sabatini, D. A. et al. 2003. Net-Average Curvature Model for Solubilization and Supersolubilization in Surfactant Microemulsions. Langmuir 19 (1): 186–195. https://doi.org/10.1021/la026168a.
Acosta, E. J., Yuan, J. S., and Bhakta, A. S. 2008. The Characteristic Curvature of Ionic Surfactants. J. Surfactants Deterg. 11 (2): 145–158. https://doi.org/10.1007/s11743-008-1065-7.
Austad, T. and Staurland, G. 1990. Multiphase Behavior of Live Oil Using a One-Component Surfactant; Effects of Temperature, Pressure and Salinity. In Situ 14 (4).
Austad, T. and Strand, S. 1996. Chemical Flooding of Oil Reservoirs 4. Effects of Temperature and Pressure on the Middle Phase Solubilization Parameters Close to Optimum Flood Conditions. Colloid. Surface. A 108 (2–3): 243–252. https://doi.org/10.1016/0927-7757(95)03406-4.
Austad, T., Hodne, H., and Staurland, G. 1990. Effects of Pressure, Temperature and Salinity on the Multiphase Behavior of the Surfactant/Methane and n-Decane/NaCl Brine System. In Surfactants and Macromolecules: Self-Assembly at Interfaces and in Bulk, ed. B. Lindman, J. B. Rosenholm, P. Stenius, 296–310. Dresden, Germany: Steinkopff.
Brooks, R. H. and Corey, A. T. 1966. Properties of Porous Media Affecting Fluid Flow. Journal of the Irrigation and Drainage Division 92 (2): 61–90.
Buckley, S. E. and Leverett, M. 1942. Mechanism of Fluid Displacement in Sands. In Transactions of the Society of Petroleum Engineers, Vol. 146, Part 1, 107–116, SPE-942107-G. Richardson, Texas: SPE. https://doi.org/10.2118/942107-G.
Budhathoki, M., Hsu, T. P., Lohateeraparp, P. et al. 2016. Design of an Optimal Middle Phase Microemulsion for Ultra High Saline Brine Using Hydrophilic Lipophilic Deviation (HLD) Method. Colloid. Surface. A 488 (5 January): 36–45. https://doi.org/10.1016/j.colsurfa.2015.09.066.
Camilleri, D., Fil, A., Pope, G. A. et al. 1987. Improvements in Physical-Property Models Used in Micellar/Polymer Flooding. SPE Res Eval & Eng 2 (4): 433–440. SPE-12723-PA. https://doi.org/10.2118/12723-PA.
Chou, S. I. and Bae, J. H. 1988. Phase-Behavior Correlation for High- Salinity Surfactant Formulations. SPE Res Eval & Eng 3 (3): 778–790. SPE-14913-PA. https://doi.org/10.2118/14913-PA.
De Gennes, P. G. and Taupin, C. 1982. Microemulsions and the Flexibility of Oil/Water Interfaces. J. Phys. Chem. 86 (13): 2294–2304. https://doi.org/10.1021/j100210a011.
Delshad, M. 1990. Trapping of Micellar Fluids in Berea Sandstone. PhD dissertation, University of Texas at Austin, Austin, Texas.
Delshad, M., Bhuyan, D., Pope, G. A. et al. 1986. Effect of Capillary Number on the Residual Saturation of a Three-Phase Micellar Solution. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, 20–23 April. SPE-14911-MS. https://doi.org/10.2118/14911-MS.
Delshad, M., Pope, G. A., and Sepehrnoori, K. 1996. A Compositional Simulator for Modeling Surfactant Enhanced Aquifer Remediation, 1 Formulation. J. Contam. Hydrol. 23 (4): 303–327. https://doi.org/10.1016/0169-7722(95)00106-9.
Fulcher, R. A. Jr., Ertekin, T., and Stahl, C. D. 1985. Effect of Capillary Number and Its Constituents on Two-Phase Relative Permeability Curves. J Pet Technol 37 (2): 249–260. SPE-12170-PA. https://doi.org/10.2118/12170-PA.
Ghosh, S. and Johns, R. T. 2014. A New HLD-NAC Based EOS Approach to Predict Surfactant-Oil-Brine Phase Behavior for Live Oil at Reservoir Pressure and Temperature. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-170927-MS. https://doi.org/10.2118/170927-MS.
Ghosh, S. and Johns, R. T. 2015. A Modified HLD-NAC Equation of State to Predict Alkali-Surfactant-Oil-Brine Phase Behavior. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. SPE-175132-MS. https://doi.org/10.2118/175132-MS.
Ghosh, S. and Johns, R. T. 2016. An Equation-of-State Model to Predict Surfactant/Oil/Brine-Phase Behavior. SPE J. 21 (4): 1106–1125. SPE-170927-PA. https://doi.org/10.2118/170927-PA.
Green, D. W. and Willhite, G. P. 1998. Enhanced Oil Recovery, Vol. 6. Richardson, Texas: Textbook Series, Society of Petroleum Engineers.
Hand, D. B. 1930. The Distribution of a Consulate Liquid Between Two Immiscible Liquids. J. Phys. Chem. 1930: 1961–2000.
Harwell, J. H., Helfferich, F. G., and Schechter, R. S. 1982. Effect of Micelle Formation on Chromatographic Movement of Surfactant Mixtures. AIChE J. 28 (3): 448–459. https://doi.org/10.1002/aic.690280313.
Healy, R. N. and Reed, R. L. 1977. Immiscible Microemulsion Flooding. SPE J. 17 (2): 129–139. SPE-5817-PA. https://doi.org/10.2118/5817-PA.
Healy, R. N., Reed, R. L., and Stenmark, D. G. 1976. Multiphase Microemulsion Systems. SPE J. 16 (3): 147–160. SPE-5565-PA. https://doi.org/10.2118/5565-PA.
Helfferich, F. G. 1981. Theory of Multicomponent, Multiphase Displacement in Porous Media. SPE J. 21 (1): 51–62. SPE-8372-PA. https://doi.org/10.2118/8372-PA.
Hirasaki, G. J. 1981. Application of the Theory of Multicomponent, Multiphase Displacement to Three-Component, Two-Phase Surfactant Flooding. SPE J. 21 (2): 191–204. SPE-8373-PA. https://doi.org/10.2118/8373-PA.
Huh, C. 1979. Interfacial Tensions and Solubilizing Ability of a Microemulsion Phase that Coexists With Oil and Brine. J. Colloid. Interf. Sci. 71 (2): 408–426. https://doi.org/10.1016/0021-9797(79)90249-2.
Jang, S. H., Liyanage, P. J., Lu, J. et al. 2014. Microemulsion Phase Behavior Measurements Using Live Oils at High Temperature and Pressure. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 12–16 April. SPE-169169-MS. https://doi.org/10.2118/169169-MS.
Jin, L., Jamili, A., Li, Z. et al. 2015a. Physics-Based HLD–NAC Phase Behavior Model for Surfactant/Crude Oil/Brine Systems. J. Pet. Sci. Eng. 136 (December): 68–77. https://doi.org/10.1016/j.petrol.2015.10.039.
Jin, L., Jamili, A., Harwell, J. H. et al. 2015b. Modeling and Interpretation of Single Well Chemical Tracer Tests (SWCTT) for Pre and Post Chemical EOR in Two High Salinity Reservoirs. Presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 1–5 March. SPE-173618-MS. https://doi.org/10.2118/173618-MS.
Jin, L., Budhathoki, M., Jamili, A. et al. 2016a. Predicting Microemulsion Phase Behavior for Surfactant Flooding. Presented at the SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179701-MS. https://doi.org/10.2118/179701-MS.
Jin, L., Li, Z., Jamili, A. et al. 2016b. Development of a Chemical Flood Simulator Based on Predictive HLD-NAC Equation of State for Surfactant. Presented at the SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. SPE-181655-MS. https://doi.org/10.2118/181655-MS.
Juanes, R. and Patzek, T. W. 2004. Analytical Solution to the Riemann Problem of Three-Phase Flow in Porous Media. Transport Porous Med. 55 (1): 47–70. https://doi.org/10.1023/B:TIPM.0000007316.43871.1e.
Kennel, C. F., Blandford, R. D. and Coppi, P. 1989. MHD Intermediate Shock Discontinuities. Part 1. Rankine–Hugoniot Conditions. Journal of Plasma Physics 42 (2): 299–319. https://doi.org/10.1017/S0022377800014379.
Khorsandi, S. and Johns, R. T. 2016. Robust Flash Calculation Algorithm for Microemulsion Phase Behavior. J. Surfactants Deterg. 19 (6): 1–15. https://doi.org/10.1007/s11743-016-1877-9.
LaForce, T. C. and Johns, R. T. 2005. Composition Routes for Three-Phase Partially Miscible Flow in Ternary Systems. SPE J. 10 (2): 161–174. SPE-89438-PA. https://doi.org/10.2118/89438-PA.
Lake, L. W. 1989. Enhanced Oil Recovery. Upper Saddle River, New Jersey: Prentice Hall.
Larson, R. G. 1979. The Influence of Phase Behavior on Surfactant Flooding. SPE J. 19 (6): 411–422. SPE-6774-PA. https://doi.org/10.2118/6774-PA.
Liu, S., Zhang, D., Yan, W. et al. 2008. Favorable Attributes of Alkaline-Surfactant-Polymer Flooding. SPE J. 13 (1): 5–16. SPE-99744-PA. https://doi.org/10.2118/99744-PA.
Morrow, N. R. and Songkran, B. 1981. Effect of Viscous and Buoyancy Forces on Nonwetting Phase Trapping in Porous Media. In Surface Phenomena in Enhanced Oil Recovery, ed. D. O. Shah, 387–411. New York City: Springer.
Morrow, N. R., Chatzis, I., and Taber, J. J. 1988. Entrapment and Mobilization of Residual Oil in Bead Packs. SPE Res Eval & Eng 3 (3): 927–934. SPE-14423-PA. https://doi.org/10.2118/14423-PA.
Orr, F. M. 2007. Theory of Gas Injection Processes. Holte, Denmark: Tie-Line Publications.
Pennell, K. D., Pope, G. A., and Abriola, L. M. 1996. Influence of Viscous and Buoyancy Forces on the Mobilization of Residual Tetrachloroethylene during Surfactant Flushing. Environ. Sci. Technol. 30 (4): 1328–1335. https://doi.org/10.1021/es9505311.
Pope, G. A. 1980. The Application of Fractional Flow Theory to Enhanced Oil Recovery. SPE J. 20 (3): 191–205. SPE-7660-PA. https://doi.org/10.2118/7660-PA.
Pope, G. A. and Nelson, R. C. 1978. A Chemical Flooding Compositional Simulator. SPE J. 18 (5): 339–354. SPE-6725-PA. https://doi.org/10.2118/6725-PA.
Prausnitz, J. M., Lichtenthaler, R. N., and de Azevedo, E. G. 1998. Molecular Thermodynamics of Fluid-Phase Equilibria. Upper Saddle River, New Jersey: Prentice Hall.
Prouvost, L. P., Satoh, T., Sepehrnoori, K. et al. 1984. A New Micellar Phase-Behavior Model for Simulating Systems With Up to Three Amphiphilic Species. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 16–19 September. SPE-13031-MS. https://doi.org/10.2118/13031-MS.
Rosen, M. J. 2004. Surfactants and Interfacial Phenomena, third edition. New York City: John Wiley & Sons.
Roshanfekr, M. and Johns, R. T. 2011. Prediction of Optimum Salinity and Solubilization Ratio for Microemulsion Phase Behavior with Live Crude at Reservoir Pressure. Fluid Phase Equilibr. 304 (1): 52–60. https://doi.org/10.1016/j.fluid.2011.02.004.
Roshanfekr, M., Johns, R. T., Pope, G. et al. 2012. Simulation of the Effect of Pressure and Solution Gas on Oil Recovery From Surfactant/Polymer Floods. SPE J. 17 (3): 705–716. SPE-125095-PA. https://doi.org/10.2118/125095-PA.
Roshanfekr, M., Johns, R. T., Pope, G. et al. 2013. Modeling of Pressure and Solution Gas for Chemical Floods. SPE J. 18 (3): 428–439. SPE-147473-PA. https://doi.org/10.2118/147473-PA.
Salager, J. L. and Antón, R. E. 1999. Handbook of Microemulsion Science and Technology, ed. P. Kumar and K. L. Mittal. Boca Raton, Florida: CRC Press.
Salager, J. L., Morgan, J. C., Schechter, R. S. et al. 1979. Optimum Formulation of Surfactant/Water/Oil Systems for Minimum Interfacial Tension or Phase Behavior. SPE J. 19 (2): 107–115. SPE-7054-PA. https://doi.org/10.2118/7054-PA.
Sandersen, S. B., Stenby, E. H., and von Solms, N. 2012. The Effect of Pressure on the Phase Behavior of Surfactant Systems: An Experimental Study. Colloid. Surface. A 415 (5 December): 159–166. https://doi.org/10.1016/j.colsurfa.2012.09.006.
Skauge, A. and Fotland, P. 1990. Effect of Pressure and Temperature on the Phase Behavior of Microemulsions. SPE Res Eval & Eng 5 (4): 601–608. SPE-14932-PA. https://doi.org/10.2118/14932-PA.
Sheng, J. 2010. Modern Chemical Enhanced Oil Recovery: Theory and Practice. Houston: Gulf Professional Publishing.
Tanford, C. 1980. The Hydrophobic Effect: Formation of Micelles and Biological Membranes, second edition. New York City: J. Wiley & Sons.
Trogus, F. J., Schechter, R. S., and Wade, W. H. 1979. A New Interpretation of Adsorption Maxima and Minima. J. Colloid. Interf. Sci. 70 (2): 293–305. https://doi.org/10.1016/0021-9797(79)90033-X.
UTCHEM. 2000. Technical Documentation for UTCHEM-9.0. Austin, Texas: University of Texas at Austin.
Welge, H. J., Johnson, E. F., Ewing, S. P. Jr. et al. 1961. The Linear Displacement of Oil from Porous Media by Enriched Gas. J Pet Technol 13 (8): 787–796. SPE-1525-G-PA. https://doi.org/10.2118/1525-G-PA.
Willhite, G. P., Green, D. W., Okoye, D. M. et al. 1980. A Study of Oil Displacement by Microemulsion Systems Mechanisms and Phase Behavior. SPE J. 20 (6): 459–472. SPE-7580-PA. https://doi.org/10.2118/7580-PA.
Wingard, J. S. and Orr, F. M. Jr. 1994. An Analytical Solution for Steam/Oil/Water Displacements. SPE Advanced Technology Series 2 (2): 167–176. SPE-19667-PA. https://doi.org/10.2118/19667-PA.
Winsor, P. A. 1954. Solvent Properties of Amphiphilic Compounds. London: Butterworths.
Yuan, B., Moghanloo, R. G., and Pattamasingh, P. 2015. Applying Method of Characteristics to Study Utilization of Nanoparticles to
Reduce Fines Migration in Deepwater Reservoirs. Presented at the SPE European Formation Damage Conference and Exhibition, Budapest, Hungary, 3–5 June. SPE-174192-MS. https://doi.org/10.2118/174192-MS.
Yuan, B., Moghanloo, R. G., and Zheng, D. 2016. Analytical Modeling of Nanofluid Injection to Improve the Performance of Low Salinity Water Flooding. Presented at the Offshore Technology Conference Asia, Kuala Lampur, 22–25 March. OTC-26363-MS. https://doi.org/10.4043/26363-MS.
Zanganeh, M. N., Kam, S. I., LaForce, T. et al. 2011. The Method of Characteristics Applied to Oil Displacement by Foam. SPE J. 16 (1): 8–23. SPE-121580-PA. https://doi.org/10.2118/121580-PA.