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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).
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).
Anthropogenic CO2 emissions have accumulated significantly in the last few decades aggravating global warming. Mineral trapping is a key mechanism for the global energy transition during which injected CO2 is sequestered within the subsurface formations via dissolution/precipitation. However, the data of CO2 mineralization are extremely scarce, which limits our understanding of suitable candidate formations for mineral trapping. The aim of this study is to emphasize the impacts of wettability and rock heterogeneity on mineral trapping occurring during CO2 sequestration in carbonate formations. In this study, a numerical approach was followed by setting up one-spot pilot test-scale models of homogeneous and heterogeneous carbonate formations to predict the mineral trapping capacity of CO2 gas for two distinct wetting states: Strongly Water-Wet (SWW) and Intermediately Water-Wet (IWW). Accordingly, a 3D Cartesian base case model was created with upscaled petrophysical parameters to mimic the subsurface conditions of a representative carbonate formation from UAE. The study highlighted the relationship between carbonate wettability, rock heterogeneity, and fate of CO2 plume and mineralization potential. In this study, the effect of wettability and heterogeneity were analyzed in terms of CO2 mineralized after 1 year of injection and 200 years of storage. The mineral trapping capacities computed showed a monotonic increase as the wettability shifted from SWW to IWW irrespective of reservoir heterogeneity with different extents. Notably, after 115 years of storage, the heterogeneous formations started to sequester more CO2 attributed to permeability variance increase. In the same context, plume of CO2 extended upwardly and laterally further in case of intermediately water-wet compared to strongly water-wet, especially at earlier stages of storage duration. Classical trapping mechanisms such as solubility trapping gained more attention than mineralization. This is attributed to the time-dependency of mineralization with slow reaction rate scaling up to millennia. Thus, CO2 mineralization potential assessment is important to de-risk large-scale pilot tests. This work provides new insights into underpinning the effects of wettability and rock heterogeneity on CO2 storage capacity in carbonate formations. The findings suggest that mineralization within carbonate immobilizes CO2 and thus, assists in stable and long-term storage.
The wettability of the solid/fluid systems is an important property in several applications. The accurate determination of wettability in rock/fluid systems has a paramount role due to its fundamental influence on fluid distribution and the dynamics of multiphase flow in porous media. While various methodologies are available for the assessment of the wettability behavior of rocks, the goniometric approach, employed for contact angle measurements, is widely acknowledged for its direct applicability and appropriateness. This technique has the distinct advantage of facilitating wettability characterization for a broad spectrum of physicochemical conditions e.g., variations in pressure, temperature, and salinity. Several investigations have reported contact angles under diverse conditions for various rock/fluid systems. However, contact angles often depict an inconsistency in terms of the observed wetting behavior of specific rock/fluid systems under identical conditions. One prominent contributing factor to these discrepancies is rock's surface roughness. Typically, smooth and polished rock surfaces are utilized for contact angle measurements, and this study depicts that ignoring the inherent surface roughness of rocks can have notable impact on its wettability. This study analyzes the wetting characteristics of two distinct carbonate samples, each engineered to exhibit a spectrum of surface roughness values. Additionally, our investigation explores the impact of varying polish-abrasive sizes and types on both surface roughness and wettability, utilizing commercially accessible abrasives spanning a wide spectrum of dimensions, which include liquid silicon carbide (Si-C) and sandpaper. The results contribute to an enhanced comprehension of the mechanisms governing wettability fluctuations at the millimeter scale and thus explain the underlying mechanisms influencing wetting properties.
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