Studying the interactions between CO2-rich fluid and reservoir rock under reservoir temperature and pressure is important for investigating CO2 sequestration and the CO2-enhanced oil recovery processes. Using high-concentration CaCl2-type formation water as an example, this study performed a CO2-rich fluid–rock interaction experiment at 85℃ and compared the dissolution of calcite and sandstone samples, as well as sandstone powder and thin-slice samples. This study also investigated the effects of the sample surface area, the CO2 partial pressure ( PCO2 = 10 and 20 MPa), and the composition of formation water (3 mol/kg NaCl and 1 mol/kg CaCl2–2 mol/kg NaCl) on the water–rock interaction mechanism and process by weighing, ion chromatography, and scanning electron microscopy observations. The results showed that the injection of CO2 resulted in the dissolution of reservoir minerals such as carbonate cements and feldspar. The mineral dissolution increased with increasing PCO2. The dissolution of minerals such as calcite in the CaCl2-type formation water was significantly decreased because of the high concentration of Ca2+. Under the same conditions, more sandstone dissolved than calcite and more sandstone powder dissolved than sandstone thin slices. Dissolution of the potassium feldspar occurred in the sandstone, whereas the albite was nearly unaffected. No new minerals formed during the experimental process. The experimental results and a PHREEQC calculation demonstrated that the injection of CO2 causes a significant pH drop in the formation water, which improves the porosity and permeability of the reservoir, increases the capacity of the reservoir to store CO2, and facilitates the progression of the CO2-enhanced oil recovery process. However, if alkaline minerals in the caprocks of the reservoir are also dissolved by the CO2-rich fluid, the sealing capacity of the caprocks may be reduced.
The Effect of Clay Content in the Adsorption of Surfactant by Reservoir Rock in the Enhanced Oil Recovery Process
