Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding
- Pål Østebø Andersen (University of Stavanger)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- February 2020
- Document Type
- Journal Paper
- 481 - 496
- 2020.Society of Petroleum Engineers
- waterflooding, wettability alteration, smart water injection, capillary end effects
- 11 in the last 30 days
- 199 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Many experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation.
This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.
|File Size||1 MB||Number of Pages||16|
Al-Khdheeawi, E. A., Vialle, S., Barifcani, A. et al. 2017. Impact of Reservoir Wettability and Heterogeneity on CO2-Plume Migration and Trapping Capacity. Int J Greenh Gas Con 58 (March): 142–158. https://doi.org/10.1016/j.ijggc.2017.01.012.
Andersen, P. Ø. and Berawala, D. 2019. Modeling of Creep-Compacting Outcrop Chalks Injected with Ca-Mg-Na-Cl Brines at Reservoir Conditions. SPE J. 24 (6): 2889–2910. SPE-192018-PA. https://doi.org/10.2118/192018-PA.
Andersen, P. Ø., Evje, S., Kleppe, H. et al. 2015. A Model for Wettability Alteration in Fractured Reservoirs. SPE J. 20 (6): 1261–1275. SPE-174555-PA. https://doi.org/10.2118/174555-PA.
Andersen, P. Ø., Standnes, D. C., and Skjæveland, S. M. 2017a. Waterflooding Oil-Saturated Core Samples—Analytical Solutions for Steady-State Capillary End Effects and Correction of Residual Saturation. J Pet Sci Eng 157 (August): 364–379. https://doi.org/10.1016/j.petrol.2017.07.027.
Andersen, P. Ø., Skjæveland, S. M., and Standnes, D. C. 2017b. A Novel Bounded Capillary Pressure Correlation with Application to Both Mixed and Strongly Wetted Porous Media. Paper presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 13–16 November. SPE-188291-MS. https://doi.org/10.2118/188291-MS.
Andersen, P. Ø., Wang, W., Madland, M. V. et al. 2018. Comparative Study of Five Outcrop Chalks Flooded at Reservoir Conditions: Chemo-Mechanical Behaviour and Profiles of Compositional Alteration. Transp Porous Media 121 (1): 135–181. https://doi.org/10.1007/s11242-017-0953-6.
Andersen, P. Ø., Lohne, A., Stavland, A. et al. 2019a. Core Scale Modeling of Polymer Gel Dehydration by Spontaneous Imbibition. SPE J. 24 (3): 1201–1219. SPE-190189-PA. https://doi.org/10.2118/190189-PA.
Andersen, P. Ø., Bratteka°s, B., Nødland, O. et al. 2019b. Darcy Scale Simulation of Boundary Condition Effects During Capillary Dominated Flow in High Permeability Systems. SPE Res Eval & Eng 22 (2): 673–691. SPE-188625-PA. https://doi.org/10.2118/188625-PA.
Andersen, P. Ø., Qiao, Y., Standnes, D. C. et al. 2019c. Cocurrent Spontaneous Imbibition in Porous Media with the Dynamics of Viscous Coupling and Capillary Backpressure. SPE J. 24 (1): 158–177. SPE-190267-PA. https://doi.org/10.2118/190267-PA.
Andersen, P. Ø., Walrond, K., Nainggolan, C. et al. 2020. Simulation Interpretation of Capillary Pressure and Relative Permeability from Waterflooding Laboratory Experiments in Preferentially Oil-Wet Porous Media. SPE Res Eval & Eng 23 (1): 230–246. SPE-197065-PA. https://doi.org/10.2118/197065-PA.
Anderson, W. G. 1987a. Wettability Literature Survey—Part 4: Effects of Wettability on Capillary Pressure. J Pet Technol 39 (10): 1283–1300. SPE-15271-PA. https://doi.org/10.2118/15271-PA.
Anderson, W. G. 1987b. Wettability Literature Survey Part 5: The Effects of Wettability on Relative Permeability. J Pet Technol 39 (11): 1453–1468. SPE-16323-PA. https://doi.org/10.2118/16323-PA.
Appelo, C. A. J. and Postma, D. 2004. Geochemistry, Groundwater and Pollution. Boca Raton, Florida, USA: CRC Press.
Brooks, R. H. and Corey, A. T. 1966. Properties of Porous Media Affecting Fluid Flow. J Irrig Drain Div-ASCE 92 (2): 61–90.
Buckley, J. S. and Fan, T. 2007. Crude Oil/Brine Interfacial Tensions. Petrophysics 48 (3): 175–185. SPWLA-2007-v48n3a1.
Buckley, S. E. and Leverett, M. C. 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, USA: Society of Petroleum Engineers.
Chen, Z., Huan, G., and Ma, Y. 2006. Computational Methods for Multiphase Flows in Porous Media, Vol. 2. Philadelphia, Pennsylvania, USA: Computational Science and Engineering Series, Society for Industrial and Applied Mathematics.
Chilingar, G. V. and Yen, T. F. 1983. Some Notes on Wettability and Relative Permeabilities of Carbonate Reservoir Rocks, II. Energy Sources 7 (1): 67–75. https://doi.org/10.1080/00908318308908076.
Dullien, F. A. 2012. Porous Media: Fluid Transport and Pore Structure. San Diego, California, USA: Academic Press.
El-Dessouky, H. T. and Ettouney, H. M. 2002. Fundamentals of Salt Water Desalination. Amsterdam, The Netherlands: Elsevier Science B.V.
Fathi, S. J., Austad, T., and Strand, S. 2010. “Smart Water” as a Wettability Modifier in Chalk: The Effect of Salinity and Ionic Composition. Energy Fuels 24 (4): 2514–2519. https://doi.org/10.1021/ef901304m.
Finn, R. 1999. Capillary Surface Interfaces. Notices AMS 46 (7): 770–781.
Gelhar, L. W., Welty, C., and Rehfeldt, K. R. 1992. A Critical Review of Data on Field-Scale Dispersion in Aquifers. Water Resour Res 28 (7): 1955–1974. https://doi.org/10.1029/92WR00607.
Gupta, R. and Maloney, D. R. 2016. Intercept Method—A Novel Technique To Correct Steady-State Relative Permeability Data for Capillary End Effects. SPE Res Eval & Eng 19 (2): 316–330. SPE-171797-PA. https://doi.org/10.2118/171797-PA.
Hao, J., Mohammadkhani, S., Shahverdi, H. et al. 2019. Mechanisms of Smart Waterflooding in Carbonate Oil Reservoirs—A Review. J Pet Sci Eng 179 (August): 276–291. https://doi.org/10.1016/j.petrol.2019.04.049.
Hirasaki, G. and Zhang, D. L. 2004. Surface Chemistry of Oil Recovery from Fractured, Oil-Wet, Carbonate Formations. SPE J. 9 (2): 151–162. SPE-88365-PA. https://doi.org/10.2118/88365-PA.
Huang, D. D. and Honarpour, M. M. 1998. Capillary End Effects in Coreflood Calculations. J Pet Sci Eng 19 (1–2): 103–117. https://doi.org/10.1016/S0920-4105(97)00040-5.
Johnson, E., Bossler, D., and Bossler, V. 1959. Calculation of Relative Permeability from Displacement Experiments. SPE-1023-G.
Lager, A., Webb, K. J., Black, C. J. J. et al. 2008. Low Salinity Oil Recovery—An Experimental Investigation. Petrophysics 49 (1): 28–35. SPWLA-2008-v49n1a2.
Lee, A. L. and Ellington, R. T. 1965. Viscosity of n-Decane in the Liquid Phase. J. Chem. Eng. Data 10 (4): 346–348. https://doi.org/10.1021/je60027a013.
Leverett, M. C. 1941. Capillary Behavior in Porous Solids. In Transactions of the Society of Petroleum Engineers, Vol. 142, Part 1, 152–169, SPE-941152-G. Richardson, Texas, USA: Society of Petroleum Engineers.
Lucia, F. J. 1995. Rock-Fabric/Petrophysical Classification of Carbonate Pore Space for Reservoir Characterization. AAPG Bull. 79 (9): 1275–1300.
Madland, M. V., Hiorth, A., Omdal, E. et al. 2011. Chemical Alterations Induced by Rock–Fluid Interactions When Injecting Brines in High Porosity Chalks. Transp Porous Media 87 (3): 679–702. https://doi.org/10.1007/s11242-010-9708-3.
Masalmeh, S. K. 2012. Impact of Capillary Forces on Residual Oil Saturation and Flooding Experiments for Mixed to Oil-Wet Carbonate Reservoirs. Paper presented at the International Symposium of the Society of Core Analysts, Aberdeen, Scotland, 27–30 August. SCA2012-11.
Masalmeh, S. K., Sorop, T. G., Suijkerbuijk, B. M. et al. 2014. Low Salinity Flooding: Experimental Evaluation and Numerical Interpretation. Paper presented at the International Petroleum Technology Conference, Doha, Qatar, 19–22 January. IPTC-17558-MS. https://doi.org/10.2523/IPTC-17558-MS.
McPhee, C., Reed, J., and Zubizarreta, I. 2015. Core Analysis: A Best Practice Guide, Vol. 64, first edition. Waltham, Massachusetts, USA: Elsevier.
Megawati, M., Hiorth, A., and Madland, M. 2013. The Impact of Surface Charge on the Mechanical Behavior of High-Porosity Chalk. Rock Mech Rock Eng 46 (5): 1073–1090. https://doi.org/10.1007/s00603-012-0317-z.
Morrow, N. R. and Mason, G. 2001. Recovery of Oil by Spontaneous Imbibition. Curr Opin Colloid Interface Sci 6 (4): 321–337. https://doi.org/10.1016/S1359-0294(01)00100-5.
Qiao, Y., Andersen, P. Ø., Evje, S. et al. 2018. A Mixture Theory Approach to Model Co- and Counter-Current Two-Phase Flow in Porous Media Accounting for Viscous Coupling. Adv Water Resour 112 (February): 170–188. https://doi.org/10.1016/j.advwatres.2017.12.016.
Rapoport, L. A. and Leas, W. J. 1953. Properties of Linear Waterfloods. J Pet Technol 5 (5): 139–148. SPE-213-G. https://doi.org/10.2118/213-G.
Reed, J., and Cense, A. 2019. In-Situ Saturation Monitoring (ISSM)-Recommendations for Improved Processing. Petrophysics 60 (2): 273–282. SPWLA-2019-v60n2a5.
Richardson, J. G., Kerver, J. K., Hafford, J. A. et al. 1952. Laboratory Determination of Relative Permeability. J Pet Technol 4 (8): 187–196. SPE-952187-G. https://doi.org/10.2118/952187-G.
Salathiel, R. A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks. J Pet Technol 25 (10): 1216–1224. SPE-4104-PA. https://doi.org/10.2118/4104-PA.
Sheng, J. J. 2014. Critical Review of Low-Salinity Waterflooding. J Pet Sci Eng 120 (August): 216–224. https://doi.org/10.1016/j.petrol.2014.05.026.
Shouxiang, M., Morrow, N. R., and Zhang, X. 1997. Generalized Scaling of Spontaneous Imbibition Data for Strongly Water-Wet Systems. J Pet Sci Eng 18 (3–4): 165–178. https://doi.org/10.1016/S0920-4105(97)00020-X.
Skjaeveland, S. M., Siqveland, L. M., Kjosavik, A. et al. 2000. Capillary Pressure Correlation for Mixed-Wet Reservoirs. SPE Res Eval & Eng 3 (1): 60–67. SPE-60900-PA. https://doi.org/10.2118/60900-PA.
Standnes, D. C. and Andersen, P. Ø. 2017. Analysis of the Impact of Fluid Viscosities on the Rate of Countercurrent Spontaneous Imbibition. Energy Fuels 31 (7): 6928–6940. https://doi.org/10.1021/acs.energyfuels.7b00863.
Strand, S., Høgnesen, E. J., and Austad, T. 2006. Wettability Alteration of Carbonates–Effects of Potential Determining Ions (Ca2+ and SO42– ) and Temperature. Colloids Surf A Physicochem Eng Asp 275 (1–3): 1–10. https://doi.org/10.1016/j.colsurfa.2005.10.061.
Strand, S., Puntervold, T., and Austad, T. 2008. Effect of Temperature on Enhanced Oil Recovery from Mixed-Wet Chalk Cores by Spontaneous Imbibition and Forced Displacement Using Seawater. Energy Fuels 22 (5): 3222–3225. https://doi.org/10.1021/ef800244v.
Tanino, Y. and Christensen, M. 2019. Imbibition Capillary Pressure and Relative Permeability of Mixed-Wet Microporous Rock: New Insights from History Matching. Transp Porous Media 129 (1): 121–148. https://doi.org/10.1007%2Fs11242-019-01280-4.
Treiber, L. E. and Owens, W. W. 1972. A Laboratory Evaluation of the Wettability of Fifty Oil-Producing Reservoirs. SPE J. 12 (6): 531–540. SPE-3526-PA. https://doi.org/10.2118/3526-PA.
Viksund, B. G., Morrow, N. R., Ma, S. et al. 1998. Initial Water Saturation and Oil Recovery from Chalk and Sandstone by Spontaneous Imbibition. Paper presented at the 1998 International Symposium of the Society of Core Analysts, The Hague, The Netherlands, 14–16 September. SCA-9814.
Virnovsky, G., Guo, Y., and Skjæveland, S. M. 1995. Relative Permeability and Capillary Pressure Concurrently Determined from Steady-State Flow Experiments. Paper presented at IOR 1995–8th European Symposium on Improved Oil Recovery, Vienna, Austria, 15–17 May. https://doi.org/10.3997/2214-4609.201406916.
Yousef, A. A., Al-Saleh, S. H., Al-Kaabi, A. et al. 2011. Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery from Carbonate Reservoirs. SPE Res Eval & Eng 14 (5): 578–593. SPE-137634-PA. https://doi.org/10.2118/137634-PA.
Yu, L., Kleppe, H., Kaarstad, T. et al. 2008. Modelling of Wettability Alteration Processes in Carbonate Oil Reservoirs. Netw Heterog Media 3 (1): 149–183. https://doi.org/10.3934/nhm.2008.3.149.
Zeppieri, S., Rodriguez, J., and Lopez de Ramos, A. L. 2001. Interfacial Tension of Alkane + Water Systems. J. Chem. Eng. Data 46 (5): 1086–1088. https://doi.org/10.1021/je000245r.
Zhang, P., Tweheyo, M. T., and Austad, T. 2007. Wettability Alteration and Improved Oil Recovery by Spontaneous Imbibition of Seawater into Chalk: Impact of the Potential Determining Ions Ca2+, Mg2+, and SO42–. Colloids Surf A Physicochem Eng Asp 301 (1–3): 199–208. https://doi.org/10.1016/j.colsurfa.2006.12.058.