Carbonate reservoirs, especially dolomite reservoirs, contain large reserves of oil and gas. The complex diagenesis is quite challenging to document the dolomite reservoirs formation and evolution mechanism. Porosity development and evolution in dolomite reservoirs primarily reflect the comprehensive effect of mineral dissolution/precipitation during dolomitization. In this study, multicomponent multiphase flow and solute transport simulation was employed to investigate dolomitization in the deep carbonate strata of the Tarim Basin, Northwest China, where active exploration is currently under way. One- and two-dimensional numerical models with various temperatures, fluid compositions and hydrodynamic characteristics were established to quantificationally study dolomitization and its effect on porosity. After determining the main control factors, detailed petrologic characteristics in the studied area were also analyzed to establish four corresponding diagenetic numerical models under different sedimentary environments. These models enabled a systematic analysis of mineral dissolution/precipitation and a quantitative recovery of porosity evolution during various sedimentation-diagenesis processes. The results allowed for a quantitative evaluation and prediction of reservoir porosity, which would provide a basis for further oil and gas exploration in deep carbonate reservoirs.

The interaction between CO₂ and rock during the process of CO₂ capture and storage was investigated via reactions of CO₂, formation water, and synthetic sandstone cores in a stainless-steel reactor under high pressure and temperature. Numerical modelling was also undertaken, with results consistent with experimental outcomes. Both methods indicate that carbonates such as calcite and dolomite readily dissolve, whereas silicates such as quartz, K-feldspar, and albite do not. Core porosity did not change significantly after CO₂ injection. No new minerals associated with CO₂ injection were observed experimentally, although some quartz and kaolinite precipitated in the numerical modelling. Mineral dissolution is the dominant reaction at the beginning of CO₂ injection. Results of experiments have verified the numerical outcomes, with experimentally derived kinetic parameters making the numerical modelling more reliable. The combination of experimental simulations and numerical modelling provides new insights into CO₂ dissolution mechanisms in high-pressure/temperature reservoirs and improves understanding of geochemical reactions in CO₂-brine-rock systems, with particular relevance to CO₂ entry of the reservoir.

Geochemical reactions are crucial for in situ CO₂ mineralization underground associated with CO₂‐enhanced oil recovery (CO₂‐EOR) in a hydrocarbon reservoir. However, the presence of formation water and adsorbed oil on rocks generates physical barriers to CO₂'s access to mineral surfaces, which may yield impedance to CO₂ mineral trapping that has yet to be accounted for. In this study, we mimic the dynamic oil detachment process using molecular dynamic (MD) simulation and analyze the influence of an adsorbed oil film on supercritical CO₂ (scCO₂) diffusion toward the mineral surface in the presence and absence of a water phase. Our results demonstrated a negative impact of water on oil film detachment by scCO₂, which may weaken mineral reactions and is unfavorable for mineralized CO₂ storage underground.

Shale reservoirs often undergo intense clay mineral transformation, which plays a crucial role in the formation and evolution of pores. The reservoir lithofacies types of Da’anzhai Member in the Sichuan Basin are complex, the heterogeneity is strong, and the transformation mechanism of clay minerals is unclear, limiting the understanding of reservoir diagenesis and reservoir formation mechanism. In this study, we selected the typical shale reservoir in the Da’anzhai Member of the eastern Sichuan Basin and innovatively introduced the multiphase fluid-chemical-thermal multi-field coupled numerical simulation technique to focus on the dissolution, precipitation and transformation laws of diagenetic minerals in the shale reservoir. We calculated the transformation of diagenetic minerals and their physical response under different temperatures, pressure and fluid conditions and identified the main controlling factors of mineral transformation in shale reservoirs in the study area. The results show that the transformation of smectite to illite in the Da’anzhai Member is a complex physicochemical process influenced by various factors such as temperature, pressure, fluid, and lithology. The increase in temperature can promote illitization until the critical temperature of 110°C–115°C, below which the conversion rate of smectite to illite increases as the temperature increases. However, when it is higher than the critical temperature, the degree of illitization decreases. In specific K-rich fluids, organic acids significantly affect the conversion of clay minerals in the Da’anzhai Member of the formation. The acidic fluid promotes the dissolution of minerals such as K-feldspar and releases K⁺, thus provides the material basis for illitization. The research results provide theoretical support for the diagenetic and formation mechanism of the shale reservoir in the Da’anzhai Member of the Sichuan Basin and even for the efficient exploration and development of shale gas.