The Impact of Different Injection Strategies on Fluid Migration and Formation Safety in CO2 Saline Aquifer Sequestration

[Geoengineering News]

https://www.sciencedirect.com/science/article/abs/pii/S0360544225039271

Authors: Yanghui Li, Qingyong Lu, Peng Wu

02 September 2025

https://doi.org/10.1016/j.energy.2025.138285

Highlights:

•CO2 injection causes a reduction in the mechanical strength of the reservoir.

•Reservoir temperature lags behind CO2 concentration changes.

•Near the injection wellbore, localized subsidence and uplift occur.

•A low, gradually increasing injection rate ensures a more uniform CO2 distribution.

Abstract

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.

Source: ScienceDirect