Fadi Khagag

Salt precipitation during CO2 injection into saline aquifers is a critical process that controls injectivity and long-term storage security. When brine evaporates into the injected CO2 phase, halite and other salts crystallize in pore constrictions, producing severe permeability reduction that is disproportionate to the corresponding porosity loss. Pore-scale observations have revealed that corner films and thin water layers act as preferential nucleation sites, leading to localized oversaturation and the initiation of precipitation. Coreflooding experiments confirm that salt deposition is not uniform but develops as irregular fronts near the injection face, governed by injection rate, CO2, phase state, and rock heterogeneity. Numerical modeling approaches, including continuum reactive transport simulators (e.g., TOUGH2, CMG-GEM), geochemical codes (e.g., PHREEQC), and pore-network frameworks, reproduce many of these dynamics and demonstrate the self-reinforcing feedback between salt growth and injectivity decline. Nevertheless, major challenges persist: thin-film transport is often neglected, multi-ion brine chemistry is oversimplified, and upscaling from laboratory to reservoir remains uncertain. This review synthesizes experimental and modeling evidence across scales. The results show that salt precipitation is nonlinear, localized, and strongly dependent on operational parameters. Future research should focus on integrating high-resolution imaging with reactive transport models and on developing mitigation strategies to ensure reliable long-term CO2 storage.

Anthropogenic CO₂ emissions are a major driver of climate change, highlighting the urgent need for effective mitigation strategies. Carbon Capture, Utilization, and Storage (CCUS) offers a promising approach, particularly through CO₂-enhanced gas recovery (EGR) in shale reservoirs, which enables simultaneous hydrocarbon production and CO₂ sequestration. This study employs a numerical simulation model to compare two injection strategies: CO₂ flooding and huff-and-puff (H&P). The results indicate that, without accounting for key mechanisms such as adsorption and molecular diffusion, CO₂ H&P provides minimal improvement in methane recovery. When adsorption is included, methane recovery increases by 9%, with 14% of the injected CO₂ stored over 40 years. Incorporating diffusion enhances recovery by 19%, although with limited storage potential. In contrast, CO₂ flooding improves methane production by 26% and retains up to 94% of the injected CO₂. Higher storage efficiency is observed in reservoirs with high porosity and low permeability, particularly in nano-scale pore systems. Overall, CO₂ H&P may be a viable EGR option when adsorption and diffusion are considered, while CO₂ flooding demonstrates greater effectiveness for both enhanced gas recovery and long-term CO₂ storage in shale formations.