Numerical Simulation of CO₂ Geological Storage in Deep Saline Aquifers: A Multiphase Flow Approach with Coupled Trapping Mechanisms

Geological storage of carbon dioxide (CO₂) in deep saline aquifers represents a critical climate mitigation strategy for reducing atmospheric greenhouse gas concentrations. This study presents a comprehensive numerical simulation framework for CO₂ storage that integrates multiphase flow dynamics, hysteretic relative permeability, and coupled trapping mechanisms including structural, residual, and solubility trapping. We implement an Implicit Pressure Explicit Saturation (IMPES) formulation coupled with Brooks-Corey relative permeability functions (Brooks and Corey, 1964) to model CO₂ migration and entrapment in a representative 5 km × 5 km × 100 m reservoir domain containing 12,800 computational cells. The simulation encompasses a 50-year period with 25 years of active injection at 20 Mt/year, followed by 25 years of post-injection monitoring. Results demonstrate that structural trapping dominates storage (87.0%), followed by residual trapping (13.0%), with minimal solubility trapping due to slow dissolution kinetics. Maximum reservoir pressure reaches 343.6 MPa with a CO₂ plume extent of 8.45 km² at the end of simulation. The storage efficiency of 21.6% indicates substantial interaction between injected CO₂ and formation brine, with hysteresis effects playing a critical role in residual trapping evolution as described by Land (1968). This work provides quantitative insights into long-term CO₂ storage behavior and validates computational frameworks essential for site-scale carbon sequestration project design and risk assessment.