CO₂ geological storage is considered as an important measure to reduce anthropogenic CO₂ emissions to the atmosphere for addressing climate change. The key prerequisite for long-term CO₂ geological storage is the sealing capacity of caprock. This study investigates the evolution of sealing capacity of caprock induced by geochemical reactions among CO₂, water and caprock using TOUGHREACT code based on the Heshanggou Formation mudstone at the Shenhua Carbon Capture and Storage (CCS) demonstration site of China. The results show that the self-sealing phenomenon occurs in the lower part of the caprock dominated by the precipitation of dawsonite, magnesite, siderite, Ca-smectite and illite. While the self-dissolution occurs in the upper part of caprock mainly due to the dissolution of kaolinite, K-feldspar, chlorite and Ca-smectite. Sensitivity analyses indicate that the precipitation of dawsonite, magnesite, siderite is highly advantageous leading to self-sealing of caprock, with albite and chlorite dissolution providing Na⁺, Mg²⁺ and Fe²⁺. The dissolution of K-feldspar dominates illite precipitation by providing required K⁺, and albite affects Ca-smectite precipitation. The self-sealing and self-dissolution of caprock are enhanced significantly with increasing temperature, while the effect of salinity on caprock sealing capacity is negligible perhaps due to the low salinity level of formation water.

A 100,000 t/year demonstration project for carbon dioxide (CO₂) capture and storage in the deep saline formations of the Ordos Basin, China, has been successfully completed. Field observations suggested that the injectivity increased nearly tenfold after CO₂ injection commenced without substantial pressure build-up. In order to evaluate whether this unique phenomenon could be attributed to geochemical changes, reactive transport modeling was conducted to investigate CO₂-water-rock interactions and changes in porosity and permeability induced by CO₂ injection. The results indicated that using porosity-permeability relationships that include tortuosity, grain size, and percolation porosity, other than typical Kozeny-Carman porosity-permeability relationship, it is possible to explain the considerable injectivity increase as a consequence of mineral dissolution. These models might be justified in terms of selective dissolution along flow paths and by dissolution or migration of plugging fines. In terms of geochemical changes, dolomite dissolution is the largest source of porosity increase. Formation physical properties such as temperature, pressure, and brine salinity were found to have modest effects on mineral dissolution and precipitation. Results from this study could have practical implications for a successful CO₂ injection and enhanced oil/gas/geothermal production in low-permeability formations, potentially providing a new basis for screening of storage sites and reservoirs.