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Understanding existing fractures is critical to achieving high and stable yields in low‐permeability reservoirs, tight sandstones, and shale reservoirs. When multiple fracture sets are present in a reservoir, accurately determining the seepage direction of fluids is critical for the deployment of the well network, fracture reformation, and the design of horizontal wells. In this paper, based on conventional logging data calculations and rock triaxial mechanical experiments, a heterogeneous finite element model was established using the finite element software. The densities and the occurrence of the natural fractures were calculated by numerical simulation of the paleostress field; the fracture apertures were calculated numerically by a current in situ stress simulation. Using a combined static coordinate system and dynamic coordinate system approach, a model suitable for determining the 3D permeability tensor of multiple fractures is established, and the formula of the permeability tensor is given. In addition, by adjusting the rotation angle and flip angle in the dynamic coordinate system, the permeability of elements is predicted for different directions. The results show that fractures mainly trend in the NE (45°) and ESE (120°) directions. Additionally, the results of differential strain, microseismic monitoring, stress relief, and regional borehole collapse observations indicate that the dominant direction of the in situ stress field is ENE (70°). The principal values of maximum permeability in the reservoirs in the Chang 71 layer mainly range from 0.05 to 2 × 10−3 μm2, and in the horizontal plane, the direction of maximum principal permeability ranges from 56 to 124°. [ABSTRACT FROM AUTHOR]