The impact of different injection strategies on fluid migration and formation safety in CO2 saline aquifer sequestration

CO2 geological sequestration serves as a foundational technology for low-carbon fossil energy utilization and a critical pathway for achieving carbon neutrality objectives globally. This study pioneers a thermo-hydro-mechanical-chemical (THMC) numerical model incorporating heterogeneous permeability distributions and time-dependent rock mechanical properties, specifically tailored for deep saline aquifers in the Xinjiang Tarim Basin. A decade-long simulation was conducted to evaluate the impacts of injection strategies on reservoir storage capacity and geomechanical stability. Key findings include: (1) High CO2 injection rates can induce transient pressure peaks, leading to compression of the rock skeleton and localized Mises stress concentration, with the maximum stress increase reaching approximately 30 %. CO2 preferentially migrates to the upper reservoir strata and attains saturation peaks ranging from 0.43 to 0.59, while thermal perturbations remain confined to near-well regions with a lateral spread of less than 100 m; (2) Gradient-accelerated injection protocols mitigate abrupt pressure fluctuations, maintaining stable porosity-permeability characteristics and homogeneous CO2 distribution. This approach reduces leakage risks by 8.2–9.7 % while maintaining CO2 storage density at approximately 17.0 Mt/km3 throughout the injection period; (3) Prolonged injection drives irreversible reservoir deformation, with cumulative vertical displacements reaching 0.25 m in subsidence and 0.05 m in uplift, thereby escalating the risks of caprock fatigue and fault reactivation. These findings establish a theoretical framework for optimizing deep saline aquifer storage systems, while highlighting that long-term chemo-mechanical coupling may exacerbate reservoir heterogeneity.