Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding
- Mehrnoosh M. Bidhendi (University of Wyoming (now with NALCO Champion, an Ecolab company)) | Griselda Garcia-Olvera (University of Wyoming (now with PEMEX)) | Brendon Morin (University of Wyoming) | John S. Oakey (University of Wyoming) | Vladimir Alvarado (University of Wyoming)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2018
- Document Type
- Journal Paper
- 803 - 818
- 2018.Society of Petroleum Engineers
- Interfacial Rheology, Smart Waterflooding, EOR, Low Salinity Waterflooding
- 16 in the last 30 days
- 409 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.
|File Size||1 MB||Number of Pages||16|
Aggarwal, N. and Sarkar, K. 2007. Deformation and Breakup of a Viscoelastic Drop in a Newtonian Matrix Under Steady Shear. Journal of Fluid Mechanics 584: 1–21. https://doi.org/10.1017/S0022112007006210.
Aksulu, H., Håms, O. D., Strand, S. et al. 2012. Evaluation of Low-Salinity Enhanced Oil Recovery Effects in Sandstone: Effects of the Temperature and pH Gradient. Energy & Fuels 26 (6): 3497–3503. https://doi.org/10.1021/ef300162n.
Alagic, E., Spildo, K., Skauge, A. et al. 2011. Effect of Crude Oil Ageing on Low Salinity and Low Salinity Surfactant Flooding. Journal of Petroleum Science and Engineering 78 (2): 220–227. https://doi.org/10.1016/j.petrol.2011.06.021.
Anderson, W. G. 1986. Wettability Literature Survey—Part 1: Rock/Oil/Brine Interactions and the Effects of Core Handling on Wettability. J Pet Technol 38 (11): 1125–1144. SPE-13932-PA. https://doi.org/10.2118/13932-PA.
Anna, S. L, Bontoux, N., and Stone, H. A. 2003. Formation of Dispersions Using “Flow Focusing” in Microchannels. Applied Physics Letters 82 (3): 364–366. https://doi.org/10.1063/1.1537519.
Austad, T., Strand, S., Hgnesen, E. et al. 2005. Seawater as IOR Fluid in Fractured Chalk. Presented at the International Symposium on Oilfield Chemistry, The Woodlands, Texas, 2–4 February. SPE-93000-MS. https://doi.org/10.2118/93000-MS.
Austad, T., Shariatpanahi, S. F., Strand, S. et al. 2011. Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs. Energy & Fuels 26 (1): 569–575. https://doi.org/10.1021/ef201435g.
Buckley, J., Takamura, K., and Morrow, N. 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.
Cardinaels, R., Vananroye, A., Van Puyvelde, P. et al. 2011. Breakup Criteria for Confined Droplets: Effects of Compatibilization and Component Viscoelasticity. Macromolecular Materials and Engineering 296 (3–4): 214–222. https://doi.org/10.1002/mame.201000305.
Chukwudeme, E. A. and Hamouda, A. A. 2009. Oil Recovery From Polar Components (Asphaltene and SA) Treated Chalk Rocks by Low Salinity Water and Water Containing SO2+4 and Mg2+ at Different Temperatures. Colloids and Surfaces A: Physicochemical and Engineering Aspects 336 (13): 174–182. https://doi.org/10.1016/j.colsurfa.2008.11.051.
Clementz, D. M. 1976. Interaction of Petroleum Heavy Ends With Montmorillonite. Clays and Clay Minerals 24 (6): 312–319. https://doi.org/10.1346/CCMN.1976.0240607.
Delshad, M., Sepehrnoori, K., and Shalabi, E. A. 2013. Mechanisms Behind Low Salinity Water Flooding in Carbonate Reservoirs; Presented at the SPE Western Regional & AAPG Pacific Section Meeting 2013 Joint Technical Conference, Monterey, California, USA, 19–25 April, SPE-165339-MS. https://doi.org/10.2118/165339-MS.
Duffy, D. C., McDonald, J. C., Schueller, J. A. et al. 1998. Rapid Prototyping of Microfluidic Systems in Poly(dimethylsiloxane). Analytical Chemistry 90: 4974–4984.
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.
Fathi, S. J., Austad, T., and Strand, S. 2011. Effect of Water-Extractable Carboxylic Acids in Crude Oil on Wettability in Carbonates. Energy & Fuels 25 (6): 2587–2592. https://doi.org/10.1021/ef200302d.
Fogden, A. 2011. Effect of Water Salinity and pH on the Wettability of a Model Substrate. Energy & Fuels 25 (11): 5113–5125. https://doi.org/10.1021/ef200920s.
Fogden, A., Kumar, M., Morrow, N. R. et al. 2011. Mobilization of Fine Particles During Flooding of Sandstones and Possible Relations to Enhanced Oil Recovery. Energy & Fuels 25 (4): 1605–1616. https://doi.org/10.1021/ef101572n.
Garcia-Olvera, G. and Alvarado, V. 2016. Interfacial Rheological Insights of Sulfate-Enriched Smart-Water at Low- and High-Salinity in Carbonates. Fuel 207 (November): 402–412. https://doi.org/10.1016/j.fuel.2017.06.094.
Garcia-Olvera, G., Reilly, T. M., Lehmann, T. E. et al. 2016. Effect of Asphaltenes and Organic Acids on Crude Oil-Brine Interfacial Visco-Elasticity and Oil Recovery in Low-Salinity Waterflooding. Fuel 185: 151–163. https://doi.org/10.1016/j.fuel.2016.07.104.
Gupta, R., Smith, G. G., Hu, L. et al. 2011. Enhanced Waterflood for Middle East Carbonate Cores-Impact of Injection Water Composition. Presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25–28 September. SPE-142668-MS. https://doi.org/10.2118/142668-MS.
Hadia, N. J., Hansen, T., Tweheyo, M. T. et al. 2012. Influence of Crude Oil Components on Recovery by High and Low Salinity Waterflooding. Energy & Fuels 26 (7): 4328–4335. https://doi.org/10.1021/ef3003119.
Hemmilä, S., Cauich-Ridríguez, J. V., Kreutzer, J. et al. 2012. Rapid, Simple, and Cost-Effective Treatments to Achieve Long-Term Hydrophilic PDMS Surfaces. Applied Surface Science 258 (24): 9864–9875. https://doi.org/10.1016/j.apsusc.2012.06.044.
Hoyer, P., Carvalho, M. S., and Alvarado, V. 2016. Snap-Off in Constricted Capillary With Elastic Interface. Physics of Fluids 28 (1): 012104. https://doi.org/10.1063/1.4939150.
Husny, J. and Cooper-White, J. J. 2006. The Effect of Elasticity on Drop Creation in T-Shaped Microchannels. Journal of Non-Newtonian Fluid Mechanics 137 (1–3): 121–136. https://doi.org/10.1016/j.jnnfm.2006.03.007.
Janssen, J. J. M., Boon, A., and Agterof, W. G. M. 1997. Influence of Dynamic Interfacial Properties on Droplet Breakup in Plane Hyperbolic Flow. AICHE Journal 43 (6): 1436–1447. https://doi.org/10.1002/aic.690430607.
Jerauld, G. R., Webb, K. J., Lin, C.-Y. et al. 2006. Modeling Low-Salinity Waterflooding. Presented at the SPE Annual Technical Conference and Exhibition, San, Antonio, Texas, USA, 24–27 September. SPE-102239-MS. https://doi.org/10.2118/102239-MS.
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.
Lebedeva, E. V. and Fogden, A. 2011. Micro-CT and Wettability Analysis of Oil Recovery From Sand Packs and the Effect of Waterflood Salinity and Kaolinite. Energy & Fuels 25 (12): 5683–5694. https://doi.org/10.1021/ef201242s.
Lever, A. and Dawe, R. A. 1984. Water-Sensitivity and Migration of Fines in the Hopeman Sandstone. Journal of Petroleum Geology 7 (1): 97–107. https://doi.org/10.1111/j.1747-5457.1984.tb00165.x.
Ligthelm, D. J., Gronsveld, J., Hofman, J. et al. 2005. Novel Waterflooding Strategy by Manipulation of Injection Brine Composition. Presented at the EUROPEC/EAGE Conference and Exhibition, Amsterdam, 8–11 June. SPE-119835-MS. https://doi.org/10.2118/119835-MS.
McGuire, P., Chatham, J., Paskvan, F. et al. 2005. Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska’s North Slope. Presented at the SPE Western Regional Meeting, Irvine, California, USA, 30 March–1 April. SPE-93903-MS. https://doi.org/10.2118/93903-MS.
Moradi, M., Kazempour, M., French, J. et al. 2014. Crude-Oil-in Water Emulsion Flooding for EOR. Fuel 154: 38–45. https://doi.org/10.3997/2214-4609.20148427.
Moradi, M. and Alvarado, V. 2016. Influence of Aqueous-Phase Ionic Strength and Composition on the Dynamics of Water–Crude Oil Interfacial Film Formation. Energy & Fuels 30 (11): 9170–9180. https://doi.org/10.1021/acs.energyfuels.6b01841.
Morin, B., Liu, Y., Alvarado, V. et al. 2016. A Microfluidic Flow Focusing Platform to Screen the Evolution of Crude Oil-Brine Interfacial Elasticity. Lab Chip 16: 3074–3081. https://doi.org/10.1039/c61c00287k.
Morrow N. R., Tang, G., Valat, M. et al. 1998. Prospects of Improved Oil Recovery Related to Wettability and Brine Composition. Journal of Petroleum Science and Engineering 20 (3–4): 267–276. https://doi.org/10.1016/S0920-4105(98)00030-8.
Nasralla, R. A. and Nasr-El-Din, H. A. 2011. Impact of Electrical Surface Charges and Cation Exchange on Oil Recovery by Low Salinity Water. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 20–22 September. SPE-147937-MS. https://doi.org/10.2118/147937-MS.
Olbricht, W. L and, Leal, L. G. 1983. The Creeping Motion of Immiscible Drops Through a Converging/Diverging Tube. Journal of Fluid Mechanics 134: 329–355. https://doi.org/10.1017/S0022112083003390.
Parracello, V. P., Pizzinelli, C. S., Nobili, M. et al. 2013. Opportunity of Enhanced Oil Recovery Low Salinity Water Injection: From Experimental Work to Simulation Study up to Field Proposal. Presented at the EAGE Annual Conference and Exhibition incorporating SPE Europec, London, 10–13 June. SPE-164827-MS. https://doi.org/10.2118/164827-MS.
Pu, H., Xie, X., Yin, P. et al. 2010. Low Salinity Waterflooding and Mineral Dissolution. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19–22 September. SPE-134042-MS. https://doi.org/10.2118/134042-MS.
RezaeiDoust, A., Puntervold, T., Strand, S. et al. 2009. Smart Water as Wettability Modifier in Carbonate and Sandstone: A Discussion of Similarities/Differences in the Chemical Mechanisms. Energy Fuels 23 (9): 4479–4485. https://doi.org/10.1021/ef900185q.
Rivet, S., Lake, L. W., and Pope, G. A. 2010. A Coreflood Investigation of Low-Salinity Enhanced Oil Recovery. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19–22 September. SPE-134297-MS. https://doi.org/10.2118/134297-MS.
Robertson, E. P. 2007. Low-Salinity Waterflooding to Improve Oil Recovery—Historical Field Evidence. Presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, 11–14 November. SPE-109965-MS. https://doi.org/10.2118/109965-MS.
Tang, G. Q. and Morrow N. R. 1997. Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding. SPE Res Eng 12 (4): 269–276. SPE-36680-PA. https://doi.org/10.2118/36680-PA.
Tang, G. Q. and Morrow, N. R. 1999. Influence of Brine Composition and Fines Migration on Crude Oil/Brine/Rock Interactions and Oil Recovery. Journal of Petroleum Science and Engineering 24 (2–4): 99–111. https://doi.org/10.1016/S0920-4105(99)00034-0.
Vijapurapu, C. S. and Rao, D. N. 2003. Effect of Brine Dilution and Surfactant Concentration on Spreading and Wettability. Presented at the International Symposium on Oilfield Chemistry, Houston, 5–7 February. SPE-80273-MS. https://doi.org/10.2118/80273-MS.
Webb, K., Black, C., and Al-Ajeel, H. 2004. Low Salinity Oil Recovery—Log-Inject-Log. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17–21 April. SPE-89379-MS. https://doi.org/10.2118/89379-MS.
Yi, Z. and Sarma, H. K. 2012. Improving Waterflood Recovery Efficiency in Carbonate Reservoirs Through Salinity Variations and Ionic Exchanges: A Promising Low-Cost Smart-Waterflood Approach. Presented at the Abu Dhabi International Petroleum Conference and Exhibition, Abu Dhabi, 11–14 November. SPE-161631-MS. https://doi.org/10.2118/161631-MS.
Yildiz, H. O., Valat, M., and Morrow, N. R. 1999. Effect of Brine Composition on Wettability and Oil Recovery of a Prudhoe Bay Crude Oil. J Can Pet Technol 38 (1): 26–31. PETSOC-99-01-02. https://doi.org/10.2118/99-01-02.
Zahid, A., Stenby, E. H., and Shapiro, A. A. 2010. Improved Oil Recovery in Chalk: Wettability Alteration or Something Else? Presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, 14–17 June. SPE-131300-MS. https://doi.org/10.2118/131300-MS.
Zahid, A., Shapiro, A. A., Stenby, E. H. et al. 2012a. Managing Injected Water Composition To Improve Oil Recovery: A Case Study of North Sea Chalk Reservoirs. Energy & Fuels 26 (6): 3407–3415. https://doi.org/10.1021/ef2008979.
Zahid, A., Stenby, E. H., and Shapiro, A. A. 2012b. Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs. Presented at the SPE Europec/EAGE Annual Conference, Copenhagen, Denmark, 4–7 June. SPE-154508-MS. https://doi.org/10.2118/154508-MS.
Zhang, Y., Xie, X., and Morrow, N. R. 2007. Waterflood Performance by Injection of Brine With Different Salinity for Reservoir Cores. Presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, 11–14 November. SPE-109849-MS. https://doi.org/10.2118/109849-MS.