Enhanced coalbed methane (ECBM) can be recovered by injecting a gas such as carbon dioxide into the reservoir to displace methane. The contrast between density, viscosity, and permeability of the resident and displacing fluids affects the efficiency of ECBM recovery. The prediction of earlier breakthrough becomes complex as the permeability may vary by orders of magnitude during gas injection and methane recovery. Predominantly, the reservoir permeability is modulated by the pore pressure of the sorptive gas (CH4 and CO 2) and effective stresses. Here we explore the possibility of early breakthrough and its implications for managing coalbed reservoirs during CO 2 assisted ECBM. A coupled finite element (FE) model of binary gas flow, diffusion, competitive sorption and permeability change is used to explore the effect of CO2 injection on net recovery, permeability evolution and injectivity in uniform and homogeneously permeable reservoirs. This effect is evaluated in terms of dimensionless pressure (pD), permeability (kD) and fracture spacing (xD) on the recovery of methane and permeability evolution for ECBM and non-ECBM scenarios. We have considered two scenarios (4 MPa and 8 MPa) of constant pressure injection of CO2 for ECBM. The increase in production rate of CH4 is proportional to kD but inversely proportional to xD. Further, a reservoir with initial permeability heterogeneity was considered to explore the effect of CO2 injection on the evolution of permeability heterogeneity - whether heterogeneity increases or decreases. The evolution of permeability heterogeneity is investigated for the same two CO2 injection scenarios. For the specific parameters selected, the model results demonstrate that: (1) The injection of CO2 in coalbed reservoirs increases the production nearly 10-fold. (2) At higher injection pressures the recovery is rapid and the production increases dramatically - the production increases 2-fold on increasing the CO2 injection pressure from 4 MPa to 8 MPa. (3) However, CO2 breakthrough occurs earlier at higher injection pressures. (4) The permeability heterogeneity in the reservoir is reduced after a threshold time (∼500 days) although the overall heterogeneity is increased relative to the initial condition and is overall increased for both non-CO 2 and CO2 injection scenarios. This indicates that the homogenizing influence of CO2-sorption-swelling is outpaced by CH4-desorption-shrinkage and effective stress influences. This leaves the reservoir open to short-circuiting and earlier breakthrough of CO 2 rather than having this effect damped-out by the homogenizing influence of swelling. (5) The cumulative volume of CO2 produced and stored in the reservoir is proportional to the injection pressure. © 2014 Elsevier Ltd. All rights reserved.