Underground fluid injection is regarded as one of the important factors inducing seismic activity. This study therefore proposes a method to predict the maximum damage area and seismic magnitude induced by fluid injection, in order to quantify the relationship between stress disturbances in faults and induced seismic activity during fluid injection. This method involves analysing a three-dimensional geological model of fault permeability evolution in order to define the seismic rupture zone of faults during fluid injection projects. It also involves calculating the maximum damage area and seismic magnitude induced by injection and verifying the method’s effectiveness using field data. The results show that, during deep injection, continuous injection of fluid reduces the effective stress on the fault and increases the fracture area. Following the sudden cessation of injection, the rupture area and maximum seismic magnitude reach their peak values. During the initial stage of injection, seismic magnitude increases rapidly with the rupture radius of the fault, while the growth rate of seismic magnitude decreases during the stable injection stage. Once injection has ceased, the rupture range and seismic magnitude will gradually stabilise throughout the entire geological self-balancing stage. Periodic injection results in the largest fault rupture area, whereas linear growth injection induces the highest seismicity. Strike-slip faults exhibit the most significant increase in rupture area, whereas normal faults demonstrate more intense seismicity evolution. Low permeability, proximity to injection wells and direct well closure exacerbate instability, whereas linear slow closure is the safest option. These research results can inform seismic risk management in fluid injection engineering.

During oilfield injection and production operations, fluid injection and withdrawal can significantly alter the stress state around faults, potentially triggering fault reactivation and even seismic events, which has become a focal issue in both industry and academia. In this study, based on fluid–solid coupling theory and the rate-and-state friction constitutive model, a mechanical framework was developed to evaluate fault shear slip behavior induced by injection–production activities. Numerical simulations were conducted using COMSOL Multiphysics to systematically investigate the effects of injection–production rate, operational schemes, well placement, reservoir permeability, and fault dip angle on fault stability. The results indicate that higher injection–production rates, non-steady operational schemes, injection wells located closer to faults, production wells farther from faults, lower fault core permeability, and larger fault dip angles can significantly enhance fluid pressure buildup and effective stress variations within the fault core zone. These processes lead to pronounced increases in Coulomb Failure Stress (CFS) and reductions in critical stiffness, thereby elevating the risk of fault instability and slip. Overall, the findings suggest that optimizing injection–production parameters and well placement can effectively mitigate the likelihood of fault reactivation. This study provides theoretical insights into the mechanisms of injection–production-induced fault slip and offers valuable references for safe oilfield operations and seismic risk assessment.

The development of deep oil and gas reservoirs has become a key focus in the exploration and exploitation of hydrocarbon resources. To elucidate the mechanisms governing the flow evolution of reservoir sandstone under deep, high-triaxial stress conditions, this study takes the deep reservoir sandstone of a specific block as its subject. Using a true triaxial rock mechanics–seepage coupled testing system to simulate the in situ high-triaxial stress environment. Synchronous testing of the sandstone’s mechanical and seepage properties was conducted, and a staged permeability model for the elastic and damaged zones of the sandstone was developed and experimentally validated. The results indicate that, under deep, high-triaxial stress conditions, the total stress–strain behaviour of sandstone is divided into compaction, elastic deformation, yield and post-failure stages. The mechanical behaviour exhibits a ‘compression–unloading–failure’ pattern, whilst permeability follows a U-shaped evolution characterised by an ‘exponential decline–sudden increase–stabilisation’ trend; furthermore, the influence of damage on flow properties is irreversible. The intermediate principal stress exerts a significant strengthening effect on the mechanical properties of sandstone; as it increases, the peak strength and residual strength of the sandstone rise, whilst post-peak brittleness decreases and ductility increases. The intermediate principal stress is a key factor regulating the evolution of permeability. During the elastic stage, the initial permeability of the sandstone decreases as the stress increases, and the rate of exponential decay accelerates; during the damage stage, the post-peak permeability decreases as the stress increases, and the irreversible closure of pores caused by true triaxial stress makes it difficult for the post-peak permeability to recover to its initial value. The coefficient of determination for the permeability model fitted to the elastic stage is greater than 0.9, whilst that for the damage stage ranges from 0.76 to 0.85. These models effectively characterise the quantitative relationship between permeability and strain under different stress conditions, demonstrating good reliability and applicability. The research findings provide experimental evidence for elucidating the coupled relationship between mechanics and flow in sandstone under deep, high-triaxial stress conditions, as well as for predicting flow behaviour in deep reservoirs and designing development schemes.