Amino Acid as a Novel Wettability Modifier for Enhanced Waterflooding in Carbonate Reservoirs
- Ricardo A. Lara Orozco (University of Texas at Austin) | Gayan A. Abeykoon (University of Texas at Austin) | Mingyuan Wang (University of Texas at Austin) | Francisco Arguelles-Vivas (University of Texas at Austin) | Ryosuke Okuno (University of Texas at Austin) | Larry W. Lake (University of Texas at Austin) | Subhash C. Ayirala (Saudi Aramco) | Abdulkareem M. AlSofi (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2020
- Document Type
- Journal Paper
- 741 - 757
- 2020.Society of Petroleum Engineers
- wettability alteration, waterflooding, low-salinity waterflooding, carbonate reservoirs, amino acids
- 19 in the last 30 days
- 168 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Reservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.
All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and ß-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.
The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the ß-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.
Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.
Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine’s isoelectric point (pI) and the surface’s point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.
The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution’s pH, and rock’s pzc.
|File Size||6 MB||Number of Pages||17|
Al Mahrouqi, D., Vinogradov, J., and Jackson, M. D. 2017. Zeta Potential of Artificial and Natural Calcite in Aqueous Solution. Adv Colloid Interface Sci 240: 60–76. https://doi.org/10.1016/j.cis.2016.12.006.
Alotaibi, M. B. and Yousef, A. A. 2017. The Role of Individual and Combined Ions in Waterflooding Carbonate Reservoirs: Electrokinetic Study. SPE Res Eval & Eng 20 (1): 77–86. SPE-177983-PA. https://doi.org/10.2118/177983-PA.
Ayirala, S. C., Saleh, M. E., Enezi, S. M. et al. 2018. Effect of Salinity and Water Ions on Electrokinetic Interactions in Carbonate Reservoirs Cores at Elevated Temperatures. SPE Res Eval & Eng 21 (3): 733–746. SPE-189444-PA. https://doi.org/10.2118/189444-PA.
Bartels, W. B., Mahani, H., Berg, S. et al. 2019. Literature Review of Low Salinity Waterflooding from a Length and Time Scale Perspective. Fuel 236: 338–353. https://doi.org/10.1016/j.fuel.2018.09.018.
Brantley, S. L., Kubicki, J. D., and White, A. F. 2007. Kinetics of Water-Rock Interaction, first edition. New York, New York, USA: Springer Science & Business Media.
Buckley, J. S., Takamura, K., and Morrow, N. R. 1989. Influence of Electrical Surface Charges on the Wetting Properties of Crude Oils. SPE Res Eng 4 (3): 332–340. SPE-16964-PA. https://doi.org/10.2118/16964-PA.
Chen, S., Kristiansen, K., Seo, D. et al. 2018. Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery. Langmuir 35 (1): 41–50. https://doi.org/10.1021/acs.langmuir.8b02711.
Churcher, P. L., French, P. R., and Shaw, J. C. 1991. Rock Properties of Berea Sandstone, Baker Dolomite, and Indiana Limestone. Paper presented at the SPE International Symposium on Oilfield Chemistry, Anaheim, California, USA, 20–22 February. SPE-21044-MS. https://doi.org/10.2118/21044-MS.
Churchill, H., Teng, H., and Hazen, R. M. 2004. Correlation of pH-Dependent Surface Interaction Forces to Amino Acid Adsorption: Implications for the Origin of Life. Am Mineral 89 (7): 1048–1055. https://doi.org/10.2138/am-2004-0716.
De Stefano, C., Foti, C., Gianguzza, A. et al. 2000. The Interaction of Amino Acids with the Major Constituents of Natural Waters at Different Ionic Strengths. Mar Chem 72 (1): 61–76. https://doi.org/10.1016/S0304-4203(00)00067-0.
Ghosh, P., Sharma, H., and Mohanty, K. K. 2018. Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs. Paper presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, 24–26 September. SPE-191733-MS. https://doi.org/10.2118/191733-MS.
Heberling, F., Trainor, T. P., Lützenkirchen, J. et al. 2011. Structure and Reactivity of the Calcite–Water Interface. J Colloid Interface Sci 354 (2): 843–857. https://doi.org/10.1016/j.jcis.2010.10.047.
Hiorth, A., Cathles, L. M., and Madland, M. V. 2010. The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability. Transp Porous Media 85 (1): 1–21. https://doi.org/10.1007/s11242-010-9543-6.
Hirasaki, G. J. 1991. Wettability: Fundamentals and Surface Forces. SPE Form Eval 6 (2): 217–226. SPE-17367-PA. https://doi.org/10.2118/17367-PA.
Høgnesen, E. J., Strand, S., and Austad, T. 2005. Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition. Paper presented at the SPE Europec/EAGE Annual Conference, Madrid, Spain, 13–16 June. SPE-94166-MS. https://doi.org/10.2118/94166-MS.
Karty, K. 2018. Organic Chemistry: Principles and Mechanisms, second edition. New York, New York, USA: W.W. Norton & Company.
Lake, L. W., Johns, R., Rossen, W. R. et al. 2014. Fundamentals of Enhanced Oil Recovery, second edition. Richardson, Texas, USA: Society of Petroleum Engineers.
Langmuir, D. 1997. Aqueous Environmental Geochemistry, first edition. Upper Saddle River, New Jersey, USA: Prentice Hall.
Madani, M., Zargar, G., Takassi, M. A. et al. 2019. Fundamental Investigation of an Environmentally-Friendly Surfactant Agent for Chemical Enhanced Oil Recovery. Fuel 238 (15): 186–197. https://doi.org/10.1016/j.fuel.2018.10.105.
Mahani, H., Keya, A. L., Berg, S. et al. 2017. Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ζ-Potential and a Surface-Complexation Model. SPE J. 22 (1): 53–68. SPE-181745-PA. https://doi.org/10.2118/181745-PA.
Mason, G. and Morrow, N. R. 2013. Developments in Spontaneous Imbibition and Possibilities for Future Work. J Pet Sci Eng 110: 268–293. https://doi.org/10.1016/j.petrol.2013.08.018.
Meng, Q., Liu, H., and Wang, J. 2017. A Critical Review on Fundamental Mechanisms of Spontaneous Imbibition and the Impact of Boundary Condition, Fluid Viscosity and Wettability. Adv Geo-Energy Res 1 (1): 1–17. https://doi.org/10.26804/ager.2017.01.01.
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.
Myint, P. C. and Firoozabadi, A. 2015. Thin Liquid Films in Improved Oil Recovery from Low-Salinity Brine. Curr Opin Colloid Interface Sci 20 (2): 105–114. https://doi.org/10.1016/j.cocis.2015.03.002.
Plummer, L. N., Wigley, T. M. L., and Parkhurst, D. L. 1978. The Kinetics of Calcite Dissolution in CO2-Water Systems at 5° to 60°C and 0.0 to 1.0 atm CO2. Am J Sci 278 (2): 179–216. https://doi.org/10.2475/ajs.278.2.179.
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.
Sjöberg, E. L. and Rickard, D. T. 1984. Temperature Dependence of Calcite Dissolution Kinetics between 1 and 62°C at pH 2.7 to 8.4 in Aqueous Solutions. Geochim Cosmochim Acta 48 (3): 485–493. https://doi.org/10.1016/0016-7037(84)90276-X.
Strand, S., Høgnesen, E. J., and Austad, T. 2006. Wettability Alteration of Carbonates—Effects of Potential Determining Ions (Ca2+ and SO2-4) and Temperature. Colloids Surf A Physicochem Eng Asp 75 (1–3): 1–10. https://doi.org/10.1016/j.colsurfa.2005.10.061.
Tagavifar, M., Sharma, H., Wang, D. et al. 2018. Alkaline/Surfactant/Polymer Flooding with Sodium Hydroxide in Indiana Limestone: Analysis of Water/Rock Interactions and Surfactant Adsorption. SPE J. 23 (6): 2279–2301. SPE-191146-PA. https://doi.org/10.2118/191146-PA.
Tripathy, D. B., Mishra, A., Clark, J. et al. 2018. Synthesis, Chemistry, Physicochemical Properties and Industrial Applications of Amino Acid Surfactants: A Review. C R Chim 21 (2): 112–130. https://doi.org/10.1016/j.crci.2017.11.005.
Vceláková, K., Zusková, I., Kenndler, E. et al. 2004. Determination of Cationic Mobilities and pKa values of 22 Amino Acids by Capillary Zone Electrophoresis. Electrophoresis 25 (2): 309–317. https://doi.org/10.1002/elps.200305751.
Wang, D., Maubert, M., Pope, G. A. et al. 2019. Reduction of Surfactant Retention in Limestones Using Sodium Hydroxide. SPE J. 24 (1): 92–115. SPE-194009-PA. https://doi.org/10.2118/194009-PA.
Xie, X. and Morrow, N. R. 2001. Oil Recovery by Spontaneous Imbibition from Weakly Water-Wet Rocks. Petrophysics 42 (4): SPWLA-2001-v42n4a1.
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.
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 SO2-4. Colloids Surf A Physicochem Eng Asp 301 (1–3): 199–208. https://doi.org/10.1016/j.colsurfa.2006.12.058.
Zhou, D., Jia, L., Kamath, J. et al. 2002. Scaling of Counter-Current Imbibition Processes in Low-Permeability Porous Media. J Pet Sci Eng 33 (1–3): 61–74. https://doi.org/10.1016/S0920-4105(01)00176-0.