Numerical simulation of hydraulic fracture propagation in heterogeneous reservoirs based on the finite-discrete element method

The efficient development of unconventional oil and gas resources relies on hydraulic fracturing technology; however, the evolution mechanism of hydraulic fracture networks within strongly heterogeneous reservoirs remains unclear. Therefore, this study constructs a 2D fluid–solid coupling model based on the finite-discrete element method. The model employs the Weibull distribution and a fixed random seed approach to assign rock parameters at random, and couples pipe-flow elements to systematically simulate the dynamic propagation of hydraulic fractures in heterogeneous reservoirs. The results indicate that strong heterogeneity drives the transition of the failure mode from tension to shear and mixed failure, which complicates the fracture network. Furthermore, the local shear deflection induced by strong heterogeneity disperses fluid pressure and weakens the energy accumulation effect of a high in-situ stress difference. This phenomenon also diminishes the fluid-accumulation advantage of specific natural fracture angles, such as 30° and 90°, causing the maximum fracture-aperture evolution to converge across different orientations. Although the wellbore azimuth determines the macroscopic fracture strike, conditions with a large deflection angle increase friction along the propagation path and restrict the main fracture aperture. Medium to strongly heterogeneous reservoirs can balance the development of secondary fracture networks and the conductivity of the main fracture, representing favorable sweet spots for executing volume fracturing. The findings provide a theoretical basis for fracturing design and for optimizing conductivity in fan-shaped well networks.