Natural fractures affect hydraulic fracture propagation, pressure diffusion, casing integrity and stimulation efficiency in deep unconventional reservoirs. Conventional Mohr-Coulomb stability analysis usually assumes a fixed or weakly updated stress field, limiting its ability to capture evolving geomechanical perturbations during hydraulic fracturing. This study proposes a dynamic Mohr-Coulomb stability evaluation framework based on stress superposition induced by hydraulic fractures. Laboratory-constrained mechanical parameters, three-dimensional geomechanical modeling, induced stress redistribution and dynamic Mohr circle updating are integrated and tested using continental and marine shale cases. The results show that hydraulic fracturing increases all three principal stresses, with the minimum horizontal principal stress showing the strongest response. The effective stress superposition range is mainly limited to adjacent fracturing stages, indicating a localized but mechanically significant interaction zone. Static analysis reveals a nonlinear relationship between critical pore pressure increment and fracture approach angle, defining a friction-controlled stability window. Dynamic analysis further incorporates variations in principal stress, pore pressure, maximum horizontal stress orientation and fracture cohesion. The predicted activation risk zones agree with field observations from treatment pressure responses and microseismic data. Pumping rate optimization reduces activation risk by weakening stress and pore pressure perturbations near critically oriented natural fractures. The proposed framework provides a quantitative basis for diagnosing natural fracture activation, mitigating casing deformation and optimizing fracturing parameters in deep fractured shale reservoirs.

Following the maturation of shallow and medium-depth exploration, the petroleum industry is transitioning its focus to deep and ultra-deep formations. Field evidence shows that, even under extreme conditions of high temperature, high pore pressure, and high stress, some reservoirs retain anomalously high porosity and permeability, contradicting traditional compaction models. This paradox can be better explained through multi-field coupling, where temperature, pore pressure, and stress interact competitively and cooperatively to reshape compaction, fracture behavior, and fluid-rock interactions. Such interactions may induce brittle–ductile transitions that form semi-ductile permeability corridors, or cause localized enrichment when stress contrasts restrict fracture propagation and fluid accumulation promotes episodic reactivation. These insights shift the interpretation of deep reservoirs from single-factor models to a coupling-based framework, offering new directions for evaluation and exploration.