Well-scale coal permeability evolution during cyclic flue gas injection under flow and mechanical effects: modeling and implications

Flue gas injection is a promising method for enhanced coalbed methane (ECBM) recovery in deep coal seams. However, the multicomponent nature of flue gas (mainly CO2 and N2) induces complex adsorption–mechanical coupling effects that strongly influence coal permeability and methane transport. In this study, a coupled permeability evolution model considering competitive adsorption, adsorption-induced matrix deformation, and effective stress is established. The model is implemented in a numerical simulation of a hydraulically fractured horizontal well to investigate flue gas huff-and-puff ECBM recovery. The results show that flue gas injection effectively enhances methane recovery by maintaining reservoir energy and promoting methane displacement. Coal permeability exhibits a non-linear evolution controlled by the competition between adsorption-induced matrix swelling and stress-dependent fracture deformation. Compared with pure CO2 injection, mixed-gas injection better preserves reservoir permeability while maintaining strong methane displacement capability. Sensitivity analysis indicates that an injection rate of ∼5000 m³/day and a CO2/N2 ratio of 3:1 provide the optimal recovery performance. In addition, soaking time significantly affects production behavior, and excessive soaking may aggravate permeability reduction near the injection region.