Establishing a fault sealing discrimination method to determine the optimal injection sites and injection rate for CO2 storage in complex fault-block geological bodies

Abstract

The long-term stability of CO₂ storage represents a pivotal challenge in geological CO₂ storage (CGS), particularly within deep saline aquifers characterized by complex fault-block systems. While the injection sites and rate under different fault structures will directly affect the CO₂ storage effect and the risk of leakage. This study investigates the Gaoyou Sag in the Subei Basin, a representative fault-block reservoir, through an integrated numerical-experimental approach. A three-dimensional simulation model incorporating multiphase flow dynamics was developed to characterize subsurface CO₂ transport and dissolution processes. A novel fault seal capacity evaluation framework was proposed, integrating three critical geological indices (fault throw/reservoir thickness/caprock thicknesses) with the coupling of formation physical properties, temperature, and pressure for the rational selection of injection sites and rates. The results show that Optimal storage performance is observed when the fault throw is lower than the reservoir and caprock thicknesses. Furthermore, higher temperature and pressure promote the dissolution and diffusion of CO₂, while compared to the structural form of faults, the physical properties of faults have a more significant effect on CO₂ leakage. The larger reservoir space and the presence of an interlayer reduce the risk of CO₂ leakage, and augmenting storage potential. Decreasing the injection rate increases the proportion of dissolved CO₂, thereby enhancing the safety of CO₂ storage.