Evaluation of sour gas-low salinity waterflooding in carbonate reservoirs - A numerical simulation approach

Although significant amount of H₂S (sour gas) rich natural gas is estimated globally, but not much attention has been given to the application of H₂S in the oil recovery process. Recent studies on the use of H₂S in oil recovery processes showed that H₂S has the potential of improving the oil recovery, and it can be even more effective than using CO₂ in some processes. H₂S can equally dissolve in the water, react with the reservoir rock to change its surface charge, porosity, and permeability. However, previous investigations on H₂S oil recovery attributed the improved oil recoveries to the higher miscibility of H₂S in the oil, and the reduction in the oil viscosity. Therefore, there is limited understanding on the H₂S-oil-brine-rock geochemical interactions, and how they impact the oil recovery process. This study aims to investigate the interactions between H₂S, oil, and carbonate formations, and to assess how the combination of H₂S and low salinity water can impact the wettability and porosity of the reservoirs. A triple layer surface complexation model was used to understand the influence of key parameters (e.g., pressure, brine salinity, and composition) on the H₂S-brine-oil-rock interactions. Moreover, the effects of mineral content of the carbonate rock on H₂S interactions were studied. Thereafter, the results of the H₂S-oil-brine-rock interactions were compared with a study where CO₂ was used as the injected gas. Results of the study showed that the seawater and its diluted forms yielded identical ζ-potential values of about 3.31 mV at a pH of 3.24. This indicates that at very low pH condition, pH controls the ζ-potential of the oil-brine interface regardless of the brine's ionic strength. The study further demonstrated that the presence of other minerals in the carbonate rock greatly reduced the calcite dissolution. For instance, the calcite dissolution was reduced by 4.5% when anhydrite mineral was present in the carbonate rock. Findings from the simulation also indicated that CO₂ produced negative ζ-potential values for the carbonate rocks, and these values were reduced by 18.4%–20% when H₂S was used as the gas phase. This implies that the H₂S shifted the carbonate rock ζ-potentials towards positive. The outcomes of this study can be applied when designing CO₂ flooding and CO₂ storage where the gas stream contains H₂S gas since H₂S greatly influences the dissolution of the carbonate mineral.