Influence of injection temperature on CO2 storage dynamics in saline aquifers: Insights from THC-coupled process modeling

Given the urgency of reducing global greenhouse gas emissions, CO2 storage in saline aquifers has garnered attention. In this study, a reservoir-caprock model at various injection temperatures (11 °C, 21 °C, 31.5 °C, and normal formation temperature) was established using the TOUGHREACT code to investigate the influence of CO2 injection temperature on storage dynamics in saline aquifers. The results show that decreasing the injection temperature promotes CO2 dissolution in formation water, reduces the dry-out zone area, increases CO2 density, and shortens migration distance. The primary storage mechanisms are structural trapping, solubility trapping, and mineral trapping. As the injection temperature decreases, solubility trapping within 100 m of the well increases, while mineral trapping decreases. The temperature effect diminishes over time. In the Shiqianfeng Formation, calcite and dawsonite are the primary carbon-storing minerals. Temperature changes create a temperature-influenced zone within approximately 100 m from the well. As the injection temperature decreases, the influence of solute migration and the inhibition of the water-rock reaction in this zone increase. Lower injection temperatures increase early-stage safety risks; however, over the next fifty years, they reduce formation pressure at the reservoir top near the well, thereby mitigating storage risks. This study provides insights for optimizing CO2 injection strategies.