Coupled Thermal-Hydraulic-Mechanism Simulation during Geological CO₂ Storage in Heterogeneous Saline Aquifers

A deep understanding of reservoir heterogeneity and multi-field coupling effects is important for assessing CO₂ flow and migration behavior during geological CO₂ storage. This study comprehensively considers the two-phase flow mechanism, the dynamic evolution of reservoir porosity and permeability structures, and the influence of temperature on the physical properties of CO₂ under non-isothermal conditions. A thermal-hydraulic-gas-mechanical (THGM) coupled model is developed to investigate CO₂ migration behavior and storage efficiency behavior in heterogeneous saline aquifers. Simulation results indicate that reservoir heterogeneity significantly influences average pressure build-up within the reservoir. In low-porosity reservoirs, the increase in pore pressure is approximately 1.96 MPa, whereas in higher-porosity reservoirs, it is only approximately 1.64 MPa, thereby affecting the physical properties and migration pathways of injected CO₂. Additionally, the maximum migration distance of the thermal front is only approximately 161 m, while the maximum lateral migration distance of the CO₂ plume can reach approximately 1 782 m. The permeability and porosity within the reservoir vary at a ratio of approximately 1.01-1.13 and an amplitude of 2.10%-12.8% during CO₂ injection, respectively. The porosity and permeability of low-permeability reservoirs is more sensitive to pressure disturbances. The maximum CO₂ storage efficiency factor reached approximately 0.88 in low-permeability heterogeneous reservoirs, significantly higher than those in high-permeability reservoirs, demonstrating that maintaining an injection rate below the rock fracture pressure in such formations helps enhance the effective storage capacity and long-term stability of CO₂.