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-oil15 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 H2S20 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 ζ25 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% to 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.