The effect of H2S content on acid gas migration and storage in sandstone reservoir via numerical simulation

Abstract

Acid gas injection, as one of the technologies for carbon dioxide capture, utilization and storage (CCUS) technologies, has been widely used in the development of sour oil and gas reservoirs. The current study numerically investigates the effect of hydrogen sulfide (H2S) content on the acid gas migration and storage in sandstone reservoir. The results suggest that the variations of acid gas density and viscosity induced by different H2S contents have little influence on the distribution of acid gas plume. However, the higher solubility of acid gas at higher H2S content results in a decrease of migration distance. The variation of relative permeability induced by different H2S contents has great influence on the acid gas migration. With the increase of H2S content, the horizontal migration distance decreases due to the decrease of gas relative permeability. Whereas, the water relative permeability increases and the gravity number increases with increasing H2S content. As a result, most of the horizontal flow occurs at the top of the reservoir and the lateral gas migration at the lower part of the reservoir is weakened. Furthermore, the variation of capillary pressure induced by different H2S contents has little influence on the distribution of acid gas plume during the injection period. However, capillary pressure hinders the migration of acid gas during post-injection period. Thus, for the sandstone reservoir with surface contamination, the horizontal and vertical migration distance decrease with increasing H2S content. For the sandstone reservoir with clean surface, the horizontal migration distance first increases and then remains unchanged with the increase of H2S content. After 50 years, the residual and mobile trapping of acid gas decrease with the increase of H2S content, and the solubility trapping of acid gas increases with the increase of H2S content.