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The hybrid Enhanced Oil Recovery (EOR) method of Low Salinity Polymer (LSP) injection is an advanced synergetic coalescence with remarkable additional oil recovery capability. Several studies have reported that the LSP process significantly enhances polymer rheology and viscoelasticity, along with improving the injectivity and displacement efficiency. However, to accurately simulate and capture the complex geochemistry of the Polymer-Brine-Rock (PBR) system during LSP-injection, sophisticated mechanistic predictive models are required, which the literature rarely discusses. Therefore, we modeled the PBR-system interactions in this study, using our coupled numerical simulator, in order to acquire new understandings of the LSP-injection process. Our coupled numerical simulator integrates the MATLAB-Reservoir-Simulation Toolbox (MRST) with the geochemical-software IPhreeqc. This study investigates the effects of variations in water chemistry (salinity and hardness), permeability, and polymer hydrolysis on polymer viscosity and adsorption through mechanistic modeling of the LSP process using the MRST-IPhreeqc coupled simulator. In this sensitivity analysis, the various injected water salinity and hardness models were generated by spiking and diluting both the salinity and the hardness of the baseline model by 3-, 5-, and 15-times each, and subsequently investigating their impact on polymer viscosity and adsorption. Furthermore, to evaluate the effect of various degrees of hydrolysis on polymer viscosity, we investigated the polymer hydrolysis degree of 30% (base-case), and then 15% and 80% polymer hydrolysis degrees. Next, the impact of different permeabilities on polymer adsorption was investigated for the base-case permeability (71 mD), low permeability (50 mD), and high permeability (150 mD) scenarios. A number of mineral dissolutions can occur in the PBR-system causing the calcium (Ca2+) and magnesium (Mg2+) ions to release, which then form polymer complexes to massively reduce the polymer-viscosity. Also, mechanical entrapment can lead to high polymer adsorption during LSP flooding. Based on the sensitivity analysis, the results of the investigation regarding the effect of salinity on polymer viscosity indicated that the scenario of 15-times spiked salinity (9345 ppm) is more beneficial than those of 5-times (3115 ppm) and 3-times (1869 ppm) spiked salinities, based on their corresponding polymer-viscosity losses of 8%, 10%, and 19%. The same effect was observed for the increase in hardness (Ca2+ + Mg2+) scenario where 15-times spiked hardness (165 ppm) is superior to the 5-times (55 ppm) and 3-times spiked (33 ppm) scenarios, based on their corresponding polymer-viscosity losses of 25%, 47%, and 52%. Similarly, examining the impact of polymer hydrolysis on polymer viscosity indicated that the viscosity of the polymer decreases as the degree of hydrolysis increases to 80% or decreases to 15%. Regarding the effect of salinity and hardness variations on polymer adsorption, the results showed that as the salinity and hardness increase, polymer adsorption increases too. Contrariwise, the diluted salinity and hardness solutions resulted in lower adsorption levels. In terms of the impact of permeability on polymer adsorption, mechanical entrapment causes the polymer adsorption to rise at a low permeability of 50 mD, and conversely, the adsorption starts to decline at high permeability of 150 mD. Finally, according to the CR calculations, if CR > 1, this implies low viscosity loss in the LSP-solution, which equates to the cation threshold concentration of 130 ppm. At CR < 0.5, the LSP-solution will likely have a significant decrease in viscosity. When 0.5 < CR < 1, additional assessment for risk of viscosity loss is needed. Therefore, the novel findings resulting from this study can help design more effective LSP-injection strategies at field-scale.
The hybrid Enhanced Oil Recovery (EOR) method of Low Salinity Polymer (LSP) injection is an advanced synergetic coalescence with remarkable additional oil recovery capability. Several studies have reported that the LSP process significantly enhances polymer rheology and viscoelasticity, along with improving the injectivity and displacement efficiency. However, to accurately simulate and capture the complex geochemistry of the Polymer-Brine-Rock (PBR) system during LSP-injection, sophisticated mechanistic predictive models are required, which the literature rarely discusses. Therefore, we modeled the PBR-system interactions in this study, using our coupled numerical simulator, in order to acquire new understandings of the LSP-injection process. Our coupled numerical simulator integrates the MATLAB-Reservoir-Simulation Toolbox (MRST) with the geochemical-software IPhreeqc. This study investigates the effects of variations in water chemistry (salinity and hardness), permeability, and polymer hydrolysis on polymer viscosity and adsorption through mechanistic modeling of the LSP process using the MRST-IPhreeqc coupled simulator. In this sensitivity analysis, the various injected water salinity and hardness models were generated by spiking and diluting both the salinity and the hardness of the baseline model by 3-, 5-, and 15-times each, and subsequently investigating their impact on polymer viscosity and adsorption. Furthermore, to evaluate the effect of various degrees of hydrolysis on polymer viscosity, we investigated the polymer hydrolysis degree of 30% (base-case), and then 15% and 80% polymer hydrolysis degrees. Next, the impact of different permeabilities on polymer adsorption was investigated for the base-case permeability (71 mD), low permeability (50 mD), and high permeability (150 mD) scenarios. A number of mineral dissolutions can occur in the PBR-system causing the calcium (Ca2+) and magnesium (Mg2+) ions to release, which then form polymer complexes to massively reduce the polymer-viscosity. Also, mechanical entrapment can lead to high polymer adsorption during LSP flooding. Based on the sensitivity analysis, the results of the investigation regarding the effect of salinity on polymer viscosity indicated that the scenario of 15-times spiked salinity (9345 ppm) is more beneficial than those of 5-times (3115 ppm) and 3-times (1869 ppm) spiked salinities, based on their corresponding polymer-viscosity losses of 8%, 10%, and 19%. The same effect was observed for the increase in hardness (Ca2+ + Mg2+) scenario where 15-times spiked hardness (165 ppm) is superior to the 5-times (55 ppm) and 3-times spiked (33 ppm) scenarios, based on their corresponding polymer-viscosity losses of 25%, 47%, and 52%. Similarly, examining the impact of polymer hydrolysis on polymer viscosity indicated that the viscosity of the polymer decreases as the degree of hydrolysis increases to 80% or decreases to 15%. Regarding the effect of salinity and hardness variations on polymer adsorption, the results showed that as the salinity and hardness increase, polymer adsorption increases too. Contrariwise, the diluted salinity and hardness solutions resulted in lower adsorption levels. In terms of the impact of permeability on polymer adsorption, mechanical entrapment causes the polymer adsorption to rise at a low permeability of 50 mD, and conversely, the adsorption starts to decline at high permeability of 150 mD. Finally, according to the CR calculations, if CR > 1, this implies low viscosity loss in the LSP-solution, which equates to the cation threshold concentration of 130 ppm. At CR < 0.5, the LSP-solution will likely have a significant decrease in viscosity. When 0.5 < CR < 1, additional assessment for risk of viscosity loss is needed. Therefore, the novel findings resulting from this study can help design more effective LSP-injection strategies at field-scale.
Low-Salinity Polymer (LSP) flooding is a hybrid enhanced-oil-recovery (EOR) technique, which can improve the displacement efficiency by synergistically combining the advantages of low-salinity (LS) waterflooding and polymer-injection methods. However, comprehensive design of the LSP technique at field-scale requires a predictive mechanistic model that captures the polymer-brine-rock (PBR) interactions accurately. So far, very few studies have described the effects of surface complexes, surface potential, and effluent concentrations of potential-determining-ions (PDIs) within the PBR-system on water-film stability during LSP-flooding. Therefore, this study evaluates the effects of surface complexes, surface potential, and effluent-concentrations of PDIs (SO42-, Ca2+, and Mg2+) on water-film stability in carbonates by performing surface complexation modeling (SCM) of the LSP process using the PHREEQC software. Firstly, the effects of water chemistry in terms of different salinities were investigated, which involved utilizing a LS-solution (623 ppm) and a high-salinity (HS)-solution (124,600 ppm) along with 420 ppm of polymer concentration. These analyses were performed at both ambient (25℃) and high (100℃) temperatures that mimic the challenging carbonate-reservoir conditions in the Middle-East. Also, several oil, calcite, and polymer surface species were considered in our SCM modeling, such as Oil_NH+, Cal_CaOH2+, and Cal_CO3HPoly-, respectively. Then, we estimated the surface potential from the surface charge-distribution, wherein the surface charge-distribution is the surface species concentrations multiplied by the charge of the ions. Accordingly, water-film stability is inferred when both surface potentials of the brine-oil and brine-calcite interfaces exhibit the same sign. Furthermore, the effluent concentrations of PDIs were investigated to evaluate their effects on water-film stability. The outcomes of this study showed that for both the HS and LS brines, the surface species Oil_NH+ and Cal_CaOH2+ are the main contributors to the surface complexes of oil-brine and calcite-brine interfaces, respectively. Also, for both HS and LS brine cases at 100°C and above a pH value of 5, the water film tends to become unstable due to different surface potential signs between the oil-brine and calcite-brine interfaces. For the LSP case at 100°C, the results show that the surface species Oil_NH+ and Cal_CaOH2+ remain the main contributors to the surface complexes of the oil-brine and calcite-brine interfaces, respectively. Above a pH value of 4.5, similar negative signs of both oil-brine and calcite-brine interfaces were observed in this case, signifying repulsive forces and hence, improving water-film stability. This outcome suggests that the LSP solution produces a more stable water-film compared to the HS and LS brine solutions. Additionally, examining the changes in PDIs at both 25°C and 100°C showed that Mg2+and Ca2+ ions consumed with sulfate increase during LSP injection due to their consumption in reaction with polymer. Hence, these findings provide more insights into the PBR-interactions occurring during the LSP-injection in carbonates, based on which further research can be conducted into optimizing the LSP-flooding strategy in carbonates under harsh conditions (i.e., high temperature and high salinity, HTHS).
Surfactant flooding is a well-known chemical enhanced oil recovery (cEOR) technique. However, surfactant surface chemistry and the associated interactions with rock surfaces are complex and have not been fully investigated. Here, we experimentally investigate the surface chemistry of 15 rock surfaces (10 carbonate and 5 sandstones) upon interaction with different types of surfactants, including cationic, anionic, non-ionic, and zwitterionic surfactants at different concentrations (before, at, and after the critical micelle concentration, CMC). The rock samples were examined using Scanning Electron Microscopy (SEM) to investigate their structure and surface morphology. To understand the interactions at the surfactant-mineral interface and surfactant behavior, the zeta potential measurements of surfactant-brine-rock emulsions were performed, while surface chemical functional groups were identified by Fourier-transform infrared (FTIR) spectroscopy. The zeta potential results show that both anionic (SDS) and cationic (CTAB) surfactants depict better stability, in carbonates and sandstones, compared to the non-ionic (Triton X-100) and zwitterionic (3- (N, N-Dimethylmyristylammonio) surfactants, which is due to the nature of the charge of each surfactant. Also, the FITR results indicate the existence of different chemical bonds and functional groups at different concentrations for each surfactant type, and the magnitude of these bonds differs as a function of rock type and mineralogy. For instance, the rock samples treated with CTAB cationic surfactant reveal the presence of C-O, Mg-C, and Ca-C groups at all concentrations. However, despite being present at all concentrations, these responses show different magnitudes at different surfactant concentrations. The results of this study provide valuable data set to understand the surfactant surface chemistry interactions with different carbonate and sandstone rock surfaces and thus have direct implications for chemical enhanced oil recovery.
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