Shale oil reservoirs present complex pore structures and ultra-low permeability, making the evaluation of flow capacity in both the reservoir matrix and various fracture types after fracturing crucial for developing effective work systems. In this study, the Brazilian splitting method was utilized to simulate different fracture morphologies. We constructed a set of methods for evaluating matrix and fracture flow capacity based on nuclear magnetic resonance（NMR）technology. This evaluation was conducted on shale cores from the second member of Funing Formation of Gaoyou Sag in Subei Basin（referred to as the Fu-2 member）. Techniques including NMR, Brazilian fracturing, and high-pressure saturation were applied to develop these evaluation methods. The experimental results indicate that the minimum flow pore size of the shale reservoirs is 10 nm. Under stress conditions, the flow pattern exhibits a two-stage equation: nonlinear and linear. Factors affecting the fracture system’s conductivity include crack type, opening degree, stress magnitude, and driving pressure difference. Higher stress levels result in greater permeability loss, reaching up to 95%. The more complex the fracture network and the larger the opening, the greater the permeability loss. During production, it is essential to manage the pressure difference between the formation fluid and the bottomhole flow based on the crack development and effective stress characteristics of the overlying strata to ensure stable oil well production and uniform pressure propagation. For the shale oil in Fu-2 member of Gaoyou Sag, it is recommended to maintain an effective stress range of 7 MPa to 10 MPa and a flow pressure difference range of 10 MPa to 15 MPa as optimal for pumping or reservoir energy replenishment. These research findings significantly contribute to the theoretical understanding and practical application of the shale seepage mechanism.