The migration and interaction of water and gas in coal plays an important role in achieving high-performance recovery of coalbed methane (CBM). While a significant amount of fracturing fluid is injected into the reservoir to enhance the production of CBM, the effect of the imbibed liquid on the gas transport process remains poorly understood. To better understand the impact on well productivity after fracturing fluid invasion, we carried out experimental investigations on dynamic imbibition of water, and resulting matrix permeability changes, using core plug samples of coal from the Qinshui, Ordos and Junggar basins in China. The imbibition process is divided into a quick stage followed by a slow stage: the former occurs in seepage pores with a higher imbibition rate and larger imbibition time-exponent than the latter, which occurs in adsorption pores. Capillary and frictional resistance forces control the spontaneous imbibition of coals. Water movement during gas flooding has a similar imbibition rate and imbibition resistance to the slow stage of spontaneous imbibition, suggesting that the water migration process moves from larger seepage pores to smaller adsorption pores, and this is the main reason for a change in gas permeability. Gas permeability can seemingly be reduced because of two combined mechanisms: 1) occupation of the gas flow path by water in seepage pores; and 2) matrix swelling induced by water adsorption in adsorption pores. In contrast, the changing gas slippage factor can lead to an improvement in gas permeability. Coupling these three factors, we propose a modified permeability model that can be used to evaluate the influence of water on gas permeability and then to estimate the change in gas permeability during hydro-fracturing of a CBM reservoir.