Ye Wan

An Experimental Study of the Formation of Talc through CaMg(CO3)2–SiO2–H2O Interaction at 100–200°C and Vapor-Saturation Pressures

The metamorphic interaction between carbonate and silica-rich fluid is common in geological environments. The formation of talc from dolomite and silica-rich fluid occurs at low temperatures in the metamorphism of the CaO–MgO–SiO2–CO2–H2O system and plays important roles in the formation of economically viable talc deposits, the modification of dolomite reservoirs, and other geological processes. However, disagreement remains over the conditions of talc formation at low temperatures. In this study, in situ Raman spectroscopy, quenched scanning electron microscopy, micro-X-ray diffraction, and thermodynamic calculations were used to explore the interplay between dolomite and silica-rich fluids at relatively low temperatures in fused silica tubes. Results showed that talc formed at ≤200°C and low CO2 partial pressures (PCO2). The reaction rate increased with increasing temperature and decreased with increasing PCO2. The major contributions of this study are as follows: we confirmed the formation mechanism of Mg-carbonate-hosted talc deposits and proved that talc can form at ≤200°C; the presence of talc in carbonate reservoirs can indicate the activity of silica-rich hydrothermal fluids; and (3) the reactivity and solubility of silica require further consideration, when a fused silica tube is used as the reactor in high P–T experiments.

Supercritical CO2-involved water–rock interactions at 85℃ and partial pressures of 10–20 MPa: Sequestration and enhanced oil recovery

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.