Affiliation:
1. Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE
2. Chemical and Petroleum Engineering Department, Research and Innovation Center on CO2 and Hydrogen, RICH, Khalifa University of Science and Technology, Abu Dhabi, UAE
3. College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals, Dhahran, KSA
Abstract
Abstract
The low salinity polymer (LSP) injection is a hybrid enhanced oil recovery (EOR) technique, which synergistically enhances the displacement and sweep efficiencies through compounding the advantages of low-salinity water (LSW) and polymer floodings (PF). While an appropriate LSP-flooding field-scale design typically requires a predictive mechanistic model for capturing the polymer-brine-rock (PBR) interactions, few studies have focused on this issue till date. Therefore, the present study investigates the impact of water chemistry on polymer behavior in porous media using a surface complexation model (SCM), with the purpose of refining our understanding of the PBR-system. In particular, this work examines the effect of salinity and hardness on polymer viscosity and adsorption in dolomite formations during LSP-injection with the use of our in-house developed coupled MRST-IPHREEQC simulator. Hence, to comprehensively capture the geochemistry of the LSP process, the coupled MRST-IPHREEQC simulator included the chemical reactions, such as aqueous, mineral dissolution and/or precipitation, along with the surface complexation reactions.
The findings of this study showed polymer viscosity losses of 82% and 63% for the 10-times spiked salinity (6230 ppm) and 10-times spiked hardness (110 ppm) cases, respectively. Thus, the base case low-salinity (LS) brine of 623 ppm was more effective in reducing the risk of polymer viscosity loss for the dolomite model (i.e., viscosity loss of 55%). The polymer viscosity losses calculated for the various potential determining ions (PDIs) concentrations of 10-times spiked Mg2+ (40 ppm) and 2-times spiked SO42- (156 ppm) were 61%, and 46%, respectively. Moreover, investigating the impact of salinity on polymer adsorption revealed that dynamic polymer adsorption increased from 53 μg/g-rock to 68 mg/g-rock and 64 mg/g-rock, when the salinity and hardness were increased from the base case (623 ppm) to 10-times spiked salinity and 10-times spiked hardness cases, respectively. Furthermore, the analysis showed that the 10-times spiked magnesium case exhibited higher polymer adsorption (87 μg/g-rock) compared to the 2-times spiked sulfate case (64 mg/g-rock), which is related to the formation of Mg-polymer surface complexes as a result of surface complexation processes between polymer molecules and magnesium surface species at the surface of dolomite rock. Overall, the surface complexation model has demonstrated that during LSP-injection, the stability of the water-film is enhanced, suggesting a significant alteration in wettability towards a more water-wetting state. This wettability alteration plays a crucial role in increasing oil production. Consequently, our findings underscore the effectiveness of LSP-flooding in enhancing oil recovery processes by modifying the wettability of the reservoir rock surfaces, leading to a more efficient displacement of oil.
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