Shale Oil Transport in Kerogen Nanopores by Molecular Dynamics Simulation: Coupled Effects of Nanoconfinement and Thermodynamics

Understanding the transport mechanisms of shale oil within kerogen nanopores is important for unconventional reservoirs evaluation and simulation. However, fluid transport in kerogen nanopores significantly deviates from the classical continuum hydrodynamics due to nanoconfinement effects. In this study, nonequilibrium molecular dynamics (NEMD) simulations were employed to investigate the microscopic transport mechanisms of n -octane through the slit pores of realistic Type II-C kerogen. The coupled evolution of fluid density distributions, velocity profiles, interfacial slip, and apparent viscosity under varying pore apertures (3–11 nm), temperatures (313–393 K), pressures (10–30 MPa), and external driving forces (0.0001–0.0005 kcal/(mol Å)) were quantitatively analyzed. Results reveal that the confined fluid exhibits parabolic flow with distinct high-density adsorption layer at the boundary, which is related to the interfacial slip length and the confinement-induced apparent viscosity. Specifically, reducing the slit aperture significantly intensifies fluid-wall interactions, leading to the elevated apparent viscosity and effective viscosity, while simultaneously suppressing the slip behavior at the boundary. Temperature and pressure are found to exert opposing effects on fluid transport: elevated temperatures facilitate flow by attenuating the fluid-pore wall interactions, while higher pressures hinder fluid transport by enhancing the interactions between fluid molecules and the rough pore surfaces. Within the investigated driving-force ranges, increasing the external driving force enhances the flow velocity and volumetric flow rate, but does not notably alter the fluid density distribution or apparent viscosity, indicating an approximately linear flow response under the simulated conditions. Within the investigated range, the increase in external driving force enhances flow velocity and volumetric flow rate, but does not notably alter the fluid’s density distribution and viscosity, which indicates following the Newtonian fluid behavior. Based on these findings, two semiempirical models are developed to quantitatively decouple the synergistic effects of thermal activation, pressure densification, and geometric confinement on apparent viscosity of fluid transport in kerogen nanopores. These models serve as a theoretical tool for correcting Darcy’s law in reservoir-scale numerical simulations, facilitating more accurate predictions of shale oil mobility under complex subsurface conditions. These models provide semiquantitative parametrizations of confinement-dependent apparent viscosity and can serve as useful inputs for future continuum-scale or reservoir-scale descriptions of shale oil mobility under nanoconfined conditions.