Alkaline/Surfactant/Polymer Chemical Flooding Without the Need for Soft Water
- Adam K. Flaaten (University of Texas at Austin) | Quoc P. Nguyen (University of Texas at Austin) | Jieyuan Zhang (Tiorco LLC) | Hourshad Mohammadi (University of Texas at Austin) | Gary A. Pope (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- March 2010
- Document Type
- Journal Paper
- 184 - 196
- 2010. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 5.3.4 Reduction of Residual Oil Saturation, 5.8.5 Oil Sand, Oil Shale, Bitumen, 1.6.9 Coring, Fishing, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 2.3 Completion Monitoring Systems/Intelligent Wells, 5.4.1 Waterflooding, 5.6.5 Tracers, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 4.6 Natural Gas, 5.5.8 History Matching, 4.3.1 Hydrates, 5.2.1 Phase Behavior and PVT Measurements
- surfactant, high salinity, microemulsion, metaborate, oil mobilization
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- 2,372 since 2007
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Alkaline/surfactant/polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition, and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines having high salinity and hardness. We demonstrate this approach by combining high-performance, low-cost surfactants with cosurfactants that tolerate high salinity and hardness and with metaborate that can tolerate hardness as well. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase-behavior experiments and crude at reservoir temperature. A formulation was found that, with an optimum salinity of 120,000 ppm total dissolved solids (TDS), 6,600 ppm divalent cations, performed well in corefloods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery with no indication of precipitate formation. Metaborate chemistry was incorporated into a mechanistic, compositional chemical flooding simulator, and the simulator was then used to model the corefloods. Overall, novel ASP with metaborate performed comparably to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding.
This paper describes a laboratory and modeling approach to ASP flooding in reservoirs containing very hard, saline brines without the need for soft brine. Our target reservoir is a low temperature (52°C), light oil (45°API) sandstone reservoir containing hard, saline formation brine with 157,000 mg/L TDS of salinity, of which 8600 mg/L are Ca++ and Mg++. Our objective was to design an ASP slug to use as much of the formation brine as possible and eliminate the need for soft water. We show that a novel alkali, sodium metaborate, can provide tolerance to high divalent cation concentrations that the conventional alkali sodium carbonate cannot. Our laboratory approach uses quick, inexpensive microemulsion phase-behavior experiments to screen chemical formulations for both performance and tolerance to salinity and hardness. Well performing formulations are validated in coreflood experiments for good oil recovery, low pressure gradient, and low surfactant retention using prepared Berea sandstone cores saturated with very hard, saline brine at residual oil saturation.
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