Shale oil reservoirs are characterized by ultra-low matrix permeability. After large-scale hydraulic fracturing is applied to horizontal wells, fluid transport becomes highly complex, posing major challenges for accurately predicting production performance. In this study, a coupled multi-mechanism numerical model is developed for shale oil reservoirs with complex fracture networks. Using the Embedded Discrete Fracture Model (EDFM), the mass transport between the fracture and matrix and within the hydraulic fracture network can be accurately quantified. Based on core analysis and fluid experimental data, the dynamic evolution of rock and fluid properties is characterized by incorporating nanopore confinement effects, stress sensitivity, and threshold pressure gradient behavior. Numerical simulations are then conducted to investigate the impacts of multiple mechanisms, including nanopore confinement effects, stress sensitivity, and threshold pressure gradient, as well as their coupling effects on shale oil production. A field application is carried out using Well H1 in the Qingcheng shale oil reservoir. Simulation results indicate that nanopore confinement reduces bubble-point pressure, leading to a 3.60% increase in cumulative oil production and a noticeable reduction in the producing gas–oil ratio. Stress sensitivity causes a 2.68% decrease in cumulative oil production and suppresses gas production. The threshold pressure gradient exerts the strongest negative impact, resulting in an 8.01% reduction in cumulative oil production and a slight decrease in gas–oil ratio. When all mechanisms are simultaneously considered, strong nonlinear interactions emerge, yielding a 7.09% reduction in cumulative oil production—significantly different from the linear superposition of individual effects. These results demonstrate the necessity of accounting for multi-mechanism coupling to achieve reliable production forecasting in fractured shale oil reservoirs.
Ren et al. (Mon,) studied this question.