Аннотация
Salt precipitation and pore clogging near CO2 injection wells can reduce injectivity during geological storage in saline formations; yet, the combined effects of CO2 phase state, flow rate, and humidity remain insufficiently resolved at the core scale. This study investigated CO2-induced pore-structure alteration in brine-saturated artificial sandstone containing shale/clay interbeds and carbonate cementation. Eight CO2 core-flooding experiments were conducted under controlled phase-state, flow-rate, and humidity conditions, and each core was imaged before and after displacement using X-ray CT. Pressure response, apparent flow resistance, CT-derived porosity change, and salt-enriched phase distribution were evaluated. CO2 flooding caused substantial porosity loss in all tests. In the phase-state series, porosity reductions ranged from 40.75% to 50.21%, with the largest reduction under supercritical CO2. In the flow-rate series, the largest porosity reduction was 56.52%, whereas the highest apparent flow resistance occurred at the lowest flow rate. The humidity comparison showed the strongest contrast: dry supercritical CO2 reduced porosity by 46.45%, whereas wet supercritical CO2 reduced it by only 15.68%. These results indicate that CO2 humidity strongly controls pore-volume preservation and that humidified CO2 can mitigate evaporation-driven salt-related injectivity impairment.