Shale oil is primarily hosted within nanopores, where its flow behavior exhibits significant deviations from classical Darcy flow. The combined influences of nanoscale confinement and interfacial interactions represent key scientific challenges that hinder efficient shale oil recovery. The results show that under 25 °C and 1 MPa, the displacement distances of shale oil within 12 s in 100, 200, and 300 nm channels were 2.88, 5.67, and 11.01 mm, respectively. As pore size decreases, flow capacity drops sharply, and the displacement–time relationship evolves from quasi-linear to strongly nonlinear, indicating pronounced nanoscale non-Darcy behavior. By incorporating an equivalent resistance coefficient into the plate-channel flow model, the experimental data were accurately fitted, enabling quantitative evaluation of the additional flow resistance induced by nanoconfinement and interfacial adsorption. The equivalent resistance coefficient increases markedly with decreasing pore size but decreases progressively with increasing temperature and driving pressure. Increasing temperature and pressure partially mitigates nanoconfinement effects. In 200 nm channels, the equivalent resistance coefficient decreases from 1.87 to 1.20 as temperature rises from 25 to 80 °C, while in 100 nm channels it decreases from 2.43 to 1.65 as driving pressure increases from 1 to 6 MPa. Nevertheless, even under high-temperature and high-pressure conditions, shale-oil flow does not fully recover to ideal Darcy behavior. This work establishes a nanofluidic-based prediction and evaluation framework for shale oil flow, offering theoretical guidance and experimental reference for unconventional reservoir development and the optimization of enhanced oil recovery strategies.
Dong et al. (Wed,) studied this question.