Modeling of natural gas self-diffusion in the micro-pores of organic-rich shales coupling sorption and geomechanical effects

A significant amount of the natural gas in shale formations is contained in the micro- and mesopores as dissolved (absorbed) phase and on the surfaces of associated microcracks as (adsorbed) phase. The transport of natural gas in such confined spaces is primarily governed by self-diffusion as could be deduced from Knudsen number. Self-diffusion is governed by the pressure and the space confinement. In this study, realistic kerogen structures possessing both tortuous micropores and larger microcracks were formed and used to assess self-diffusion behavior during the depletion of shale reservoirs through some comprehensive molecular simulation workflow. Analysis of the transport modes revealed transition self-diffusion as the primary transport mechanism in these micropores. The sorption behavior and the mechanical properties were analyzed and incorporated to derive a transition diffusion model that is sensitive to changes in the pore pressure and the stress field. The proposed model was compared and validated against similar work in the literature. The results showed that during a typical production span, a pressure drop influences the sorption profile, the net overburden stress on the pores, and the mean free path, altering the magnitude of self-diffusivity. The calibrated pore scale model produced decent predictive ability with a relative error of 2.5–16%. The implications of structure tortuosity, sorption profile, and pore pressure on the effective diffusion coefficient and gas desorption are discussed in depth. This work provides a novel methodology for studying the effect of coupled multiphysics processes on methane transport in a realistic kerogen geometry, which could be used to calibrate a suitable pore scale model for upscaled reservoir simulation applications and accurate assessment of reservoir dynamics and ultimate recovery.