Abstract:To investigate the variations in reservoir porosity during the geological storage of supercritical CO2 injection into saline aquifers under actual engineering conditions, the influence of CO2- brine -rock interaction on reservoir porosity is considered. A three-dimensional geological model was established based on the sandstone reservoir of the Donggou Formation in the Junggar Basin, and a fully coupled method was used to simulate the dissolution and diffusion processes of supercritical CO2 injection into saline aquifers after multiphase and multicomponent flow. The results show that the reservoir porosity presents four different trends during the simulation period as the CO2 plume migrates; The change of temperature and formation water salinity gradient will change the trend of porosity change. Based on data analysis, it was found that the interaction between CO2- brine -rock inhibited the migration rate of CO2, resulting in different mineral dissolution or precipitation states in different regions, which in turn caused differences in the impact on porosity; The continuous injection of CO2 during the sealing process leads to a decrease in pH value in the reservoir, resulting in mineral dissolution, which in turn increases the pore space. The dissolution of plagioclase is the most significant, and the continuous formation of calcite in the later stage leads to a slowdown or decrease in porosity growth; An increase in temperature can promote mineral reactions and lead to an increase in the amount of mineral changes, which in turn affects the amount of porosity changes in the reservoir; High-salinity formation conditions are not conducive to geochemical reactions, thereby reducing the amount of porosity change. The results of this study can provide technical support for the multi-field coupling simulation of CO2 geological storage reservoirs and the study of geochemical response characteristics, as well as provide theoretical basis for the long-term and stability evaluation of CO2 geological storage.