A workflow to estimate shale gas permeability variations during the production process

Gas flow behavior in the tight shale porous matrix is complex due to the involvement of multiple physical processes. Pore size reduces as the effective stress increases during the production process, which will reduce the intrinsic permeability of the porous media. Slip flow and pore diffusion enhance gas apparent permeability, especially under low reservoir pressure. Adsorption not only increases original gas in place (OGIP) but also influences gas flow behavior because of the pore size reduction when the molecule size is comparable with the pore size along with the induced surface diffusion. Surface diffusion between the free gas phase and adsorption phase enhances gas permeability. Pore size reduction and the adsorption layer both have complex impacts on gas apparent permeability, plus the non-Darcy flow component make shale gas permeability look mysterious. These physical processes are difficult to couple with fluid flow, and previous research is generally incomplete. This work proposes a methodology to take these various effects into account simultaneously. Our results show that the geomechanical effect significantly reduces the intrinsic permeability of shale gas. However, slip flow and pore diffusion begin to overwhelm the geomechanical effect at reservoir pressure of 500 psi and below. As for the adsorption layer, it changes little of shale gas permeability but its induced surface diffusion might increase gas flow capacity significantly at low pressure, and the influence depends on the value of surface diffusivity. The workflow proposed in this study is considered to be useful to describe shale gas permeability evolution considering these physics together.