Background Saline aquifers are characterized by extensive distribution, abundant reserves, and substantial potential for CO₂ storage, establishing them as the most promising geological media for carbon capture, utilization, and storage (CCUS). CO₂ storage in saline aquifers plays a crucial role in mitigating the greenhouse effect and achieving the goals of peak carbon dioxide emissions and carbon neutrality. Thoroughly investigating CO₂ storage in deep saline aquifers within the Huainan mining area helps alleviate the regional pressure of carbon emission reduction while also providing important support for expanding the technical pathways of CCUS and promoting its engineering applications.

Methods Based on the geological characteristics and multi-field coupling-based mathematical models of saline aquifers in the Dingji Coal Mine in the Huainan mining area, this study developed a 3D multi-field numerical model. Using this model, this study simulated the CO₂ injection, migration, and storage processes. Furthermore, it systematically explored the impacts of key geological and engineering parameters, including initial permeability, porosity, modulus of elasticity, injection pressure, and injection mode, on CO₂ injectivity, as well as the sensitivity of these parameters.

Results The initial permeability and porosity of reservoirs represent the core geological parameters affecting CO₂ injectivity and storage efficiency in the saline aquifers. As the initial permeability increased from 0.3×10⁻¹² m² to 0.5×10⁻¹² m² (67%), the cumulative CO₂ storage capacity rose by approximately 70%. When the initial porosity increased from 0.20 to 0.30 (50%), the cumulative storage capacity increased by about 20%. In contrast, variations in the modulus of elasticity exerted a limited effect on the storage capacity. Injection pressure and mode are identified as critical engineering parameters for regulating CO₂ storage efficiency. In detail, increasing the injection pressure to 5%‒10% of the initial reservoir pressure enhanced the CO₂ storage efficiency by approximately 15%‒20% while maintaining system stability. Compared to stepwise pressurization, the constant-pressure injection mode achieved an increase in CO₂ storage capacity of about 25% in spite of an increase in pressure averaging approximately 6%‒7%. This result indicates that constant-pressure injection can form a stable pressure gradient more rapidly and promote CO₂ plume expansion, representing a more effective injection strategy.

Conclusions It can be concluded that CO₂ storage in saline aquifers should comprehensively consider four aspects: reservoir physical properties, process control, safety constraints, and efficiency enhancement. The ideal reservoirs should have a porosity range of 0.22‒0.28 and a permeability range of (0.30‒0.45) ×10⁻¹² m². Regarding engineering parameters, the injection pressure should be maintained at 80%‒90% of the fracture pressure of caprocks, and a constant-pressure injection mode should be employed to balance the storage efficiency and operational safety. Furthermore, a monitoring system that integrates pressure, seepage, and saturation shall be established to enable dynamic monitoring and control of data feedback. In the future, techniques including water-alternating-gas (WAG) injection and multi-well synergistic injection can be introduced to further enhance CO₂ storage efficiency and distribution uniformity. This will help ensure the long-term safety and stability of CO₂ geological storage. The results of this study can provide critical theoretical support for CO₂ storage in saline aquifers within the Huainan mining area and similar resource-based areas. These results also offer technical guidance for identifying dominant geological parameters and optimizing engineering siting for CO₂ storage in saline aquifers.