Shale reservoirs, characterized by abundant reserves and predominantly nano-scale pores and fractures, represent critical sources of unconventional oil and gas production. However, accurately capturing deformation behaviors of nano-to-micro-scale pore–fracture systems and describing microscale fluid–solid coupling phenomena under in situ stress remains challenging. In this study, we propose a homogenization-based approach to upscale micro-scale mechanical deformation and fluid flow results to the mesoscopic (core) scale, establishing effective fluid–solid coupling equations consistent with Biot's framework. Equivalent parameters are explicitly derived through three analytical expressions. Integrating centrifugal-nuclear magnetic resonance) and microfluidic experiments to characterize nano-confinement effects, simulation results indicate that, within the elastic deformation stage, the lower bound of producible oil in shale decreases from 20 to 16.19 nm. For organic pores, the minimum apparent permeability increases from 1.29×10−5 to 1.86×10−5 mD and the maximum from 2.97×10−3 to 4.34×10−3 mD, with the nonlinear flow regime boundary shifting from 90 to 73 nm. Inorganic pores exhibit negligible stress-induced deformation. Moreover, storage and Biot coefficients (αeff, γeff) increase with pore–fracture porosity. The effective elastic modulus (aeff) varies significantly across reservoir types, with felsic shale exhibiting higher stiffness than clay-rich shale. Accordingly, the degree of fluid–solid coupling follows the order: quartz feldspar clay minerals organic matter. For apparent permeability, small pores influence under a serial configuration, while large pores govern under parallel. Crude oil flow in complex nanopore networks depends on organic matter distribution, whereas multi-mineral interactions are dictated by bulk elastic modulus and Poisson's ratio.
Huo et al. (Mon,) studied this question.