As the world seeks scalable solutions to reduce greenhouse gas emissions, Carbon Capture and Storage has become one of the key technologies for mitigating industrial CO₂ emissions. Deep saline aquifers are considered among the most promising geological formations for long-term CO₂ storage because of their large capacity and wide distribution.

However, predicting how injected CO₂ behaves underground remains a complex scientific challenge. Once CO₂ enters a saline aquifer, it can migrate, become trapped in pore spaces, dissolve into brine, or accumulate beneath sealing rock layers. The efficiency and safety of these mechanisms depend on several interacting factors, including rock wettability, injection rate, capillary forces, gravitational effects, and subsurface heterogeneity.

A new study led by researchers from the School of Mining and Geosciences at Nazarbayev University provides important insight into this challenge. Using field-scale simulations, the team investigated how CO₂ trapping changes under different wettability conditions, injection flow regimes, and geological structures, including heterogeneous formations and faulted aquifers.

The study found that CO₂ trapping is not controlled by wettability alone. Instead, the interaction between capillary, viscous, and gravitational forces plays a decisive role. At low gravity-number regimes, dissolution trapping remained effective in both water-wet and weakly water-wet systems. At higher gravity-number regimes, however, water-wet systems performed better because stronger capillary retention prolonged contact between CO₂ and brine.

Key Findings

• CO₂ storage efficiency in saline aquifers is controlled by the combined effects of wettability, flow regime, injection rate, and geological structure.
• Low gravity-number regimes support effective dissolution trapping in both water-wet and weakly water-wet systems.
• At higher gravity-number regimes, water-wet formations can improve storage security by increasing capillary retention and prolonging CO₂–brine contact.
• Geological heterogeneity can enhance residual and dissolution trapping.
• Tight low-conductivity faults can shift CO₂ flow from viscous-dominated to capillary-controlled behavior, improving local immobilization.
• Safe CO₂ injection requires pressure management, especially under high-rate injection scenarios.

This research supports the development of safer and more efficient Carbon Capture and Storage strategies. By showing how geological heterogeneity, wettability, and injection regime interact, the study provides a practical framework for reducing leakage risk, improving long-term CO₂ immobilization, and supporting cleaner production goals.

For Kazakhstan and other countries with significant subsurface geological resources, such studies are important for evaluating the potential of geological CO₂ storage as part of future decarbonization strategies.