Numerical Simulation Study on CO2–CH4 Cross-Layer Migration and CO2 Retention-Assisted Gas Recovery in High-CO2 Gas Reservoirs

High-CO2 natural gas reservoirs present a dual challenge: recovering methane economically while retaining CO2 securely. The capacity of overlying saline aquifers to combine in situ CO2 retention with CH4 recovery remains poorly quantified. This study proposes a CO2 retention-assisted gas recovery scheme for Block D in the Yinggehai Basin. The upper T18A saline aquifer serves as the retention interval, and a lower high-pressure interval supplies CO2–CH4 mixed gas. A CMG-GEM compositional model incorporating gas–water relative permeability hysteresis was used to evaluate aquifer pressure, injection–production well spacing, gas source interval, reinjection strategy, and component migration over 30 years. Depleting the T18A pressure to below 1 MPa strengthened self-driven migration; after 30 years, aquifer pressure increased by approximately 3 MPa, compared with 0.5 MPa under the original approximately 9 MPa condition. CO2 migrated more slowly than CH4 because of dissolution and residual trapping. A well spacing of 3–5 km delayed CO2 breakthrough while maintaining CH4 supply. Direct connection to the Huangliu Formation aquifer induced upward water channeling and weakened gas mobility. By contrast, produced-gas reinjection avoided this effect and yielded 9.3 × 109 gmole (approximately 2.1 × 108 m3 at standard conditions) of cumulative gas production by 2055, nearly one order of magnitude above self-driven injection. Reinjection from the Y2 II gas group increased cumulative CH4 production by 76–80% relative to the A5 interval. These results provide a practical operating window for coordinating methane recovery with subsurface CO2 retention.