Phase behavior and flow mechanisms of CO2–hydrocarbon under nanoconfinement in shale nanopores

With the large-scale deployment of carbon capture, utilization, and storage, CO2 has been widely applied for enhanced oil recovery in shale reservoirs. However, strong nanoconfinement in shale nanopores induces CO2–hydrocarbon phase behavior and transport mechanisms that cannot be adequately described by conventional theories or microscale experiments. To address this issue, an integrated framework combining theoretical development, experimental emulation, and numerical modeling is established to investigate phase behavior and transport in shale 15 nanopores. A gas–liquid–adsorbed three-phase equilibrium algorithm is developed based on thermodynamic principles and coupled with a simplified local density functional theory to characterize adsorption under confinement. Meanwhile, a customized nano-microfluidic platform is constructed, including single-scale nanopores of 150, 80, and 10 nm and dual-scale nanopores with orthogonal staggered channels of 150 and 10 nm depth, enabling direct visualization and validation of nanoconfined phase transitions and flow behavior. Results show that decreasing pore size markedly contracts the gas–liquid two-phase envelope, lowers bubble point pressure, raises dew point pressure, and suppresses critical condensation pressure and temperature. Stronger confinement also promotes preferential adsorption of heavier components on pore walls while retaining lighter components in the bulk phase. In dual-scale nanopores, gas bubbles nucleate first in larger pores, and transition pathways are strongly controlled by gas–oil ratio. Finally, a nanoconfinement-enabled multiphase multiscale flow model is implemented in MATLAB Reservoir Simulation Toolbox, incorporating phase equilibrium and interphase mass transfer to predict CO2–hydrocarbon phase behavior and transport in shale nanopores.