This study presents development and application of a fully coupled two-phase (methane and water) and poromechanics numerical model for the analysis of geomechanical impact on coalbed methane (CBM) production. The model considers changes in two-phase fluid flow properties, i.e., coal porosity, permeability, water retention, and relative permeability curves through changes in cleat fractures induced by effective stress variations and desorptioninduced shrinkage. The coupled simulator is first verified for poromechamics coupling and simulation parameters of a CBM reservoir model are calibrated by history matching against one year of CBM production field data from Shanxi Province, China. Then, the verified simulator and calibrated CBM reservoir model are used for predicting the impact of geomechanics on production rate for twenty years of continuous CBM production. The simulation results show that desorption-induced shrinkage is the dominant process in increasing permeability in the near wellbore region. Away from the wellbore, desorptioninduced shrinkage is weaker and permeability is reduced by pressure depletion and increased effective stress. A sensitivity analysis shows that for coal with a higher sorption strain, a larger initial Young's modulus and smaller Poisson's ratio promote the enhancement of permeability as well as the production rate. Moreover, the conceptual model of the cleat system, whether dominated by vertical cleats with permeability correlated to horizontal stress or with permeability correlated to mean stress can have a significant impact on the predicted production rate. Overall, the study clearly demonstrates and confirms the critical importance of considering geomechanics for an accurate prediction of CBM production. (1) A fully coupled two-phase flow and poromechanics model for methane recovery (2) Simulation parameters are calibrated by history matching against field data (3) The geomechanics behaviors significantly affect the prediction of CBM production

Understanding methane adsorption behavior on deep shales is crucial for estimating the original gas in place and enhancing gas recovery in deep shale gas formations. In this study, the methane adsorption on deep shales within the lower Silurian Longmaxi formation from the Sichuan Basin, South China was conducted at pressures up to 50 MPa. The effects of total organic carbon (TOC), temperatures, clay minerals, and moisture content on the adsorption capacity were discussed. The results indicated that the methane excess adsorption on deep shales increased, then reached its peak, and finally decreased with the pressure. The excess adsorption data were fitted using the adsorption models, and it was found that the Dubinin–Radushkevich (D–R) model was superior to other models in predicting the methane adsorption behavior. The methane adsorption capacities exhibited strong positive correlations with the TOC content and negative relationships with clay minerals. The methane excess adsorption decreased with the temperature, while the opposite trend would occur once it exceeded some pressure. The presence of the moisture content on deep shales sharply decreased the methane adsorption capacities, and the reduction of the adsorption capacity decreased with the pressure. The moisture would occupy the adsorption sites in the shale pores, which could result in the methane adsorption capacity that decreased.

CO 2-enhanced coalbed methane recovery, known as CO 2-ECBM, is a potential win-win approach for enhanced methane production while simultaneously sequestering injected anthropogenic CO 2 to decrease CO 2 emissions to the atmosphere. In this paper, CO 2-ECBM is simulated using a coupled thermal-hydrological-mechanical (THM) numerical model that accounts for multiphase (gas and water) flow and solubility, multicomponent (CO 2 and CH 4) diffusion and adsorption, as well as heat transfer and coal deformation. The coupled model is based on the TOUGH-FLAC simulator, applied here for the first time for modeling CO 2-ECBM. The capacity of the simulator for modeling methane production is first verified by code-to-code comparison with the generalpurpose finite element solver COMSOL. Then the TOUGH-FLAC simulator is applied in an isothermal simulation to study the variations in permeability evolution during a CO 2-ECBM operation, considering four different stress-dependent permeability models implemented into the simulator. Finally, the TOUGH-FLAC simulator is applied in non-isothermal simulations to model THM responses during a CO 2-ECBM operation. The simulations show that permeability evolution, mechanical stress, and deformation are all affected by changes in pressure, temperature and adsorption swelling, with adsorption swelling having the biggest impact. The calculated stress changes did not induce any mechanical failure in the coal seam except near the injection well in one case of a very unfavorable stress field. Keywords: Coupled THM model; CO 2 sequestration; CBM production; TOUGH-FLAC, CO 2-ECBM Highlight: (1) Coupled thermal-hydrological-mechanical (THM) numerical modeling of CO 2-ECBM (2) Application of the TOUGH-FLAC simulator for CO 2-enhanced coalbed methane recovery (3) Code-to-code comparison between TOUGH-FLAC and the finite element solver COMSOL (4) Mechanical failure occurs near the injection well in the coal seam with an extensional in situ stress state