Reduction of Surfactant Retention in Limestones Using Sodium Hydroxide
- Denning Wang (University of Texas at Austin) | Mathieu Maubert (University of Texas at Austin) | Gary A. Pope (University of Texas at Austin) | Pathma J. Liyanage (University of Texas at Austin) | Sung Hyun Jang (University of Texas at Austin) | Karasinghe A. N. Upamali (University of Texas at Austin) | Leonard Chang (University of Texas at Austin) | Mohsen Tagavifar (University of Texas at Austin) | Himanshu Sharma (University of Texas at Austin) | Guangwei Ren (Total) | Khalid Mateen (Total) | Kun Ma (Total) | Gilles Bourdarot (Total) | Danielle Morel (Total)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- February 2019
- Document Type
- Journal Paper
- 92 - 115
- 2019.Society of Petroleum Engineers
- carbonates, sodium hydroxide, surfactant flooding, Chemical EOR, adsorption
- 14 in the last 30 days
- 226 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Geochemical modeling was used to design and conduct a series of alkaline/surfactant/polymer (ASP) coreflood experiments to measure the surfactant retention in limestone cores using sodium hydroxide (NaOH) as the alkali. Surfactant/polymer (SP) coreflood experiments were conducted under the same conditions for comparison. NaOH has been used for ASP floods of sandstones, but these are the first experiments to test it for ASP floods of limestones. Two studies performed under different reservoir conditions showed that NaOH significantly reduced the surfactant retention in Indiana Limestone. An ASP solution with 0.3 wt% NaOH has a pH of approximately 12.6 at 25°C. The high pH increases the negative surface charge of the carbonate, which favors lower adsorption of anionic surfactants. Another advantage of NaOH is that low concentrations of only approximately 0.3 wt% can be used because of its low molecular weight and its low consumption in limestones. Most reservoir carbonates contain gypsum or anhydrite, and therefore sodium carbonate (Na2CO3) will be consumed by the precipitation of calcium carbonate (CaCO3). As shown in the two studies, NaOH can be used in limestone reservoirs containing gypsum or anhydrite.
|File Size||1 MB||Number of Pages||24|
Adams, W. T. and Schievelbein, V. H. 1987. Surfactant Flooding Carbonate Reservoirs. SPE Res Eng 2 (4): 619–626. SPE-12686-PA. https://doi.org/10.2118/12686-PA.
Adkins, S., Arachchilage, G. W. P. P., Solairaj, S. et al. 2012. Development of Thermally and Chemically Stable Large-Hydrophobe Alkoxy Carboxylate Surfactants. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 14–18 April. SPE-154256-MS. https://doi.org/10.2118/154256-MS.
Adkins, S., Liyanage, P. J., Archchilage, G. W. P. et al. 2010. A New Process for Manufacturing and Stabilizing High-Performance EOR Surfactants at Low Cost for High-Temperature, High-Salinity Oil Reservoirs. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 24–28 April. SPE-129923-MS. https://doi.org/10.2118/129923-MS.
Al-Hashim, H. S., Obiora, V., Al-Yousef, H. Y. et al. 1996. Alkaline Surfactant Polymer Formulation for Saudi Arabian Carbonate Reservoirs. Presented at SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 21–24 April. SPE-35353-MS. https://doi.org/10.2118/35353-MS.
Al Mahrouqi, D., Vinogradov, J., and Jackson, M. D. 2017. Zeta Potential of Artificial and Natural Calcite in Aqueous Solution. Adv. Colloid Interfac. Sci. 240 (February): 60–76. https://doi.org/10.1016/j.cis.2016.12.006.
Alroudhan, A., Vinogradov, J., and Jackson, M. D. 2016. Zeta Potential of Intact Natural Limestone: Impact of Potential-Determining Ions Ca, Mg, and SO4. Colloid. Surface. A 493 (20 March): 83–98. https://doi.org/10.1016/j.colsurfa.2015.11.068.
Alshakhs, M. J. and Kovscek, A. R. 2016. Understanding the Role of Brine Ionic Composition on Oil Recovery by Assessment of Wettability From Colloidal Forces. Adv. Colloid Interfac. Sci. 233 (July): 126–138. https://doi.org/10.1016/j.cis.2015.08.004.
Arvidson, R. S., Ertan, I. E., Amonette, J. E. et al. 2003. Variation in Calcite Dissolution Rates: A Fundamental Problem? Geochim. Cosmochim. Ac. 67 (9): 1623–1634. https://doi.org/10.1016/S0016-7037(02)01177-8.
Bataweel, M. A. and Nasr-El-Din, H. A. 2011. Minimizing Scale Precipitation in Carbonate Cores Caused by Alkalis in ASP Flooding in High Salinity/High Temperature Applications. Presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 11–13 April. SPE-141451-MS. https://doi.org/10.2118/141451-MS.
Bunn, R. A., Magelky, R. D., Ryan, J. N. et al. 2002. Mobilization of Natural Colloids From an Iron Oxide-Coated Sand Aquifer: Effect of pH and Ionic Strength. Environ. Sci. Technol. 36 (3): 314–322. https://doi.org/10.1021/es0109141.
Chen, L., Zhang, G., Wang, L. et al. 2014. Zeta Potential of Limestone in a Large Range of Salinity. Colloid. Surface. A 450 (20 May): 1–8. https://doi.org/10.1016/j.colsurfa.2014.03.006.
Chevallier, E., Moreau, P., Renard, S. et al. 2013. Recent Progress in Surfactant Flooding in Carbonate Reservoirs. Presented at IOR 2013–17th European Symposium on Improved Oil Recovery, St. Petersburg, Russia, 16–18 April. https://doi.org/10.3997/2214-4609.20142634.
Cottin, C., Morel., D. C., Levitt, D. et al. 2012. (Alkali) Surfactant Gas Injection: Attractive Laboratory Results Under the Harsh Salinity and Temperature Conditions of the Middle East Carbonates. Presented at the Abu Dhabi International Petroleum Conference and Exhibition, Abu Dhabi, 11–14 November. SPE-161727-MS. https://doi.org/10.2118/161727-MS.
Ding, L., Zhang, G., Behling, J. et al. 2016. Determination of the Active Soap Number of Crude Oil and Soap Partitioning Behavior. Energy Fuels 30 (12): 10106–10116. https://doi.org/10.1021/acs.energyfuels.6b01603.
Ehrlich, R. and Wygal, R. J. Jr. 1977. Interrelation of Crude Oil and Rock Properties With the Recovery of Oil by Caustic Waterflooding. SPE J. 17 (4): 263–270. SPE-5830-PA. https://doi.org/10.2118/5830-PA.
Eriksson, R., Merta, J., and Rosenholm, J. B. 2007. The Calcite/Water Interface: I. Surface Charge in Indifferent Electrolyte Media and the Influence of Low-Molecular-Weight Polyelectrolyte. J. Colloid Interfac. Sci. 313 (1): 184–193. https://doi.org/10.1016/j.jcis.2007.04.034.
Heberling, F., Trainor, T. P., Lu¨tzenkirchen, J. et al. 2011. Structure and Reactivity of the Calcite–Water Interface. J. Colloid Interfac. Sci. 354 (2): 843–857. https://doi.org/10.1016/j.jcis.2010.10.047.
Hem, J. D. and Roberson, C. E. 1967. Form and Stability of Aluminum Hydroxide Complexes in Dilute Solution. Washington, DC: US Government Printing Office.
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.
Hirasaki, G. J., van Domselaar, H. R., and Nelson, R. C. 1983. Evaluation of the Salinity Gradient Concept in Surfactant Flooding. SPE J. 23 (3): 486–500. SPE-8825-PA. https://doi.org/10.2118/8825-PA.
Hirasaki, G., Miller, C. A., and Puerto, M. 2011. Recent Advances in Surfactant EOR. SPE J. 16 (4): 889–907. SPE-115386-PA. https://doi.org/10.2118/115386-PA.
Hocine, S., Cuenca, A., Magnan, A. et al. 2016. An Extensive Study of the Thermal Stability of Anionic Chemical EOR Surfactants—Part 1 Stability in Aqueous Solutions. Presented at the International Petroleum Technology Conference, Bangkok, 14–16 November. IPTC-18974-MS. https://doi.org/10.2523/IPTC-18974-MS.
Jang, S. H., Liyanage, P. J., Tagavifar, M. et al. 2016. A Systematic Method for Reducing Surfactant Retention to Extremely Low Levels. Presented at the SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179685-MS. https://doi.org/10.2118/179685-MS.
Karazincir, O., Thach, S., Wei, W. et al. 2011. Scale Formation Prevention During ASP Flooding. Presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 11–13 April. SPE-141410-MS. https://doi.org/10.2118/141410-MS.
Kasha, A., Al-Hashim, H., Abdallah, W. et al. 2015. Effect of Ca2+, Mg2+ and SO42– Ions on the Zeta Potential of Calcite and Dolomite Particles Aged With Stearic Acid. Colloid Surface A 482 (5 October): 290–299. https://doi.org/10.1016/j.colsurfa.2015.05.043.
Kazempour, M., Gregersen, C. S., and Alvarado, V. 2013. Mitigation of Anhydrite Dissolution in Alkaline Floods Through Injection. Fuel 107 (May): 330–342. https://doi.org/10.1016/j.fuel.2012.10.003.
Krumrine, P. H., Mayer, E. H., and Brock, G. F. 1985. Scale Formation During Alkaline Flooding. J Pet Technol 37 (8): 1466–1474. SPE-12671-PA. https://doi.org/10.2118/12671-PA.
Lake, L., Johns, R. T., Rossen, W. R. et al. 2014. Fundamentals of Enhanced Oil Recovery, second edition. Richardson, Texas: Society of PetroleumEngineers.
Levitt, D. and Bourrel, M. 2016. Adsorption of EOR Chemicals Under Laboratory and Reservoir Conditions, Part III: Chemical Treatment Methods. Presented at the SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179636-MS. https://doi.org/10.2118/179636-MS.
Levitt, D., Jackson, A., Heinson, C. et al. 2009. Identification and Evaluation of High-Performance EOR Surfactants. SPE Res Eval & Eng 12 (2): 243–253. SPE-100089-PA. https://doi.org/10.2118/100089-PA.
Levitt, D., Klimenko, A., Jouenne, S. et al. 2013. Overcoming Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates. Presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 10–13 March. SPE-164241-MS. https://doi.org/10.2118/164241-MS.
Maubert, M., Liyanage, P., Pope, G. et al. 2018. ASP Experiments in Indiana Limestone Using NaOH To Reduce Surfactant Retention. Presented at SPE Improved Oil Recovery Conference, Tulsa, 14–18 April SPE-190187-MS. https://doi.org/10.2118/190187-MS.
Mohnot, S. M. and Bae, J. H. 1989. A Study of Mineral/Alkali Reactions—Part 2. SPE Res Eng 4 (3): 381–390. SPE-13576-PA. https://doi.org/10.2118/13576-PA.
Nelson, R. C., Lawson, J. B., Thigpen, D. R. et al. 1984. Cosurfactant-Enhanced Alkaline Flooding. Presented at the SPE/DOE Symposium on Enhanced Oil Recovery, Tulsa, 15–18 April. SPE-12672-MS. https://doi.org/10.2118/12672-MS.
Parkhurst, D. L. and Appelo, C. A. J. 2013. Description of Input and Examples for PHREEQC Version 3—A Computer Program for Speciation, Batch-Reaction, One-Dimensional Transport, and Inverse Geochemical Calculations. In US Geological Survey Techniques and Methods, Book 6, Chap. A43. Denver: US Geological Survey.
Parra Perez, J. E. 2016. Experimental Investigation of Viscous Forces During Surfactant Flooding of Fractured Carbonate Cores. Master’s thesis, University of Texas at Austin, Austin, Texas (August 2016).
Pokrovsky, O. S. and Schott, J. 2002. Surface Chemistry and Dissolution Kinetics of Divalent Metal Carbonates. Environ. Sci. Technol. 36 (3): 426–432. https://doi.org/10.1021/es010925u.
Sagi, A. R., Puerto, M. C, Bian, Y. et al. 2013. Laboratory Studies for Surfactant Flood in Low-Temperature, Low-Salinity Fractured Carbonate Reservoir. Presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 8–10 April. SPE-164062-MS. https://doi.org/10.2118/164062-MS.
ShamsiJazeyi, H., Verduzco, R., and Hirasaki, G. J. 2014. Reducing Adsorption of Anionic Surfactant for Enhanced Oil Recovery: Part II. Applied Aspects. Colloid. Surface. A 453 (5 July): 168–175. https://doi.org/10.1016/j.colsurfa.2014.02.021.
Sharma, H. 2016. Study of Geochemical Interactions During Chemical EOR Processes. PhD dissertation, University of Texas at Austin, Austin, Texas.
Sharma, H., Weerasooriya, U., Pope, G. A. et al. 2016. Ammonia-Based ASP Floods in Carbonate Cores Containing Gypsum. Fuel 184 (15 November): 362–370. https://doi.org/10.1016/j.fuel.2016.07.014.
Siffert, D. and Fimbel, P. 1984. Parameters Affecting the Sign and Magnitude of the Electrokinetic Potential of Calcite. Colloid. Surface. 11 (3–4): 377–389. https://doi.org/10.1016/0166-6622(84)80291-7.
Solairaj, S., Britton, C., Kim, D. H. et al. 2012. Measurement and Analysis of Surfactant Retention. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 14–18 April. SPE-154247-MS. https://doi.org/10.2118/154247-MS.
Somasundaran, P. and Agar, G. E. 1967. The Zero Point of Charge of Calcite. J. Colloid Interfac. Sci. 24 (4): 433–440. https://doi.org/10.1016/0021-9797(67)90241-X.
Song, J., Zeng, Y., Wang, L. et al. 2017. Surface Complexation Modeling of Calcite Zeta Potential Measurements in Brines With Mixed Potential Determining Ions (Ca2+, CO32–, Mg2+, SO42–) for Characterizing Carbonate Wettability. J. Colloid Interfac. Sci. 506 (15 November): 169–179. https://doi.org/10.1016/j.jcis.2017.06.096.
Southwick, J. G. 1985. Solubility of Silica in Alkaline Solutions: Implications for Alkaline Flooding. SPE J. 25 (6): 857–864. SPE-12771-PA. https://doi.org/10.2118/12771-PA.
Tagavifar, M., Herath, S., Weerasooriya, U. P. et al. 2016. Measurement of Microemulsion Viscosity and Its Implications for Chemical EOR. Presented at the SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179672-MS. https://doi.org/10.2118/179672-MS.
Tagavifar, M., Jang, S. H., Sharma, H. et al. 2018a. Effect of pH on Adsorption of Anionic Surfactants on Limestone: Experimental Study and Surface Complexation Modeling. Colloid. Surface. A 538 (5 February): 549–558. https://doi.org/10.1016/j.colsurfa.2017.11.050.
Tagavifar, M., Sharma, H., Wang, D. et al. 2018b. ASP Flooding With NaOH in Indiana Limestone: Analysis of Water-Rock Interactions and Surfactant Adsorption. SPE J. SPE-191146-PA (in press; posted online 10 September 2018). https://doi.org/10.2118/191146-PA.
Upamali, K. A. N., Liyanage, P. J., Jang, S. H. et al. 2018. New Surfactants and Cosolvents Increase Oil Recovery and Reduce Cost. SPE J. SPE-179702-PA (in press; posted online October 2018). https://doi.org/10.2118/179702-PA.
Van Cappellen, P., Charlet, L., Stumm, W. et al. 1993. A Surface Complexation Model of the Carbonate Mineral-Aqueous Solution Interface. Geochim. Cosmochim. Ac. 57 (15): 3505–3518. https://doi.org/10.1016/0016-7037(93)90135-J.
Walker, D., Britton, C., Kim, D. H. et al. 2012. The Impact of Microemulsion Viscosity on Oil Recovery. Presented at SPE Improved Oil Recovery Symposium, Tulsa, 14–18 April. SPE-154275-MS. https://doi.org/10.2118/154275-MS.
Wang, D. 2018. Surfactant Retention in Limestones. Master’s thesis, University of Texas at Austin. Austin, Texas.
Yang, H. T., Britton, C., Liyanage, P. J. et al. 2010. Low-Cost, High-Performance Chemicals for Enhanced Oil Recovery. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 24–28 April. SPE-129978-MS. https://doi.org/10.2118/129978-MS.
Zeltner, W. A. and Anderson, M. A. 1988. Surface Charge Development at the Goethite/Aqueous Solution Interface: Effects of CO2 Adsorption. Langmuir 4 (2): 469–474. https://doi.org/10.1021/la00080a039.
Zhang, P. and Austad, T. 2006. Wettability and Oil Recovery From Carbonates: Effects of Temperature and Potential Determining Ions. Colloid. Surface. A 279 (1–3): 179–187. https://doi.org/10.1016/j.colsurfa.2006.01.009.