The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO2-EGR (enhanced gas recovery), and CO2-storage. A generic 3D planer model (20,000 × 3,000 × 100 m, consisting of 1,200 m overburden, 100 m caprock, 200 m gas reservoir, and 1,500 m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO2-EGR phase under a balanced injection rate (31,500 tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4 % in the 5-year CO2-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83 % for 5 km distance, instead of 1.2 km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO2-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6 MPa which is determined by the penetration criterion of the caprock.