Coupled effects of heterogeneity and propagation regime on hydraulic fracture morphology

Fluid-driven fracturing is fundamental to geophysical processes (e.g. fluid-induced seismicity) and engineered applications such as geothermal energy extraction. This study investigates the coupled influence of rock heterogeneity and fracture propagation regime on hydraulic fracture growth. Using a fully coupled discrete element-pore network model, we simulate fracture propagation driven by both Newtonian and shear-thinning power-law fluids. Rock heterogeneity is explicitly represented by a Weibull distribution of mechanical properties, allowing fractures to initiate and propagate without predefined paths. Model validation shows excellent agreement with classical Khristianovic–Geertsma–de Klerk (KGD) solutions across viscosity- and toughness-dominated regimes. Our results demonstrate that heterogeneity strongly influences fracture morphology. In highly heterogeneous rocks, viscosity-dominated propagation creates broad process zones with distributed microcracking and high orthogonal roughness. In contrast, toughness-dominated propagation leads to localized stress perturbations, forming tortuous and asymmetric fractures. Shear-thinning fluids reduce the morphological contrast between regimes by decreasing the effective near-tip viscosity, while time-evolving propagation behavior further moderates regime-dependent differences. Ultimately, fracture complexity is governed by the interplay between fluid rheology and material heterogeneity. These findings provide critical insights for optimizing fluid selection and injection parameters to achieve desired fracture complexity and containment in heterogeneous reservoirs.