CO₂ sequestration in saline aquifers is one of the most potential sequestration modes, and saline aquifers are ideal sites for CO₂ geological sequestration. After CO₂ is injected into a saline aquifer, it will have a long-term complex geochemical reaction with the formation of minerals and water, and the minerals will undergo multiple reactions such as dissolution and reprecipitation. Therefore, an in-depth study of the geochemical reaction mechanisms between CO₂ and formation minerals is of great significance to the accurate calculation and prediction of CO₂ storage volume and the safety evaluation of long-term CO₂ sequestration. In China, continental saline aquifers are widely distributed, whose mineral compositions and texture maturity are markedly different from those of the marine sedimentary basins in North America, and their stratigraphic environments are more complicated. The studies on the CO₂–water–rock (mineral) still have many research gaps or insufficiencies, and there is no report on the dissolution mechanisms of individual minerals in the reaction. Taking one certain block of Daqing Oilfield, which is a typical continental deposit in China, as an example, we analyze the dissolution laws and four types of typical continental deposited minerals under the effect of CO₂ and the change features of ionic compositions and pH of the formation water in the process of geochemical reaction. The research results indicate that CO₂ has different dissolution degrees for the four types of minerals, among which, feldspar, as the main mineral in continental sedimentary formations, has the lowest dissolution rate. Furthermore, in terms of the water type (Na+-enriched NaHCO₃) of the saline aquifer in the deep part of the continental deposit, feldspar can precipitate into the secondary minerals represented by dawsonite in the later stage, which can act as the potential minerals of carbon fixation to increase the CO₂ mineralization storage volume in continental deposited saline aquifers.

This study systematically investigates the formation mechanism and development characteristics of the “foamy oil” phenomenon during pressure depletion development of high-viscosity crude oil through a combination of physical experiments and numerical simulations. Using Venezuelan foamy oil as the research subject, an innovative heterogeneous pore-etched glass model was constructed to simulate the pressure depletion process, revealing for the first time that bubble growth predominantly occurs during the migration stage. Experimental results demonstrate that heavy components significantly delay degassing by stabilizing gas–liquid interfaces, while the continuous gas–liquid diffusion effect explains the unique development characteristics of foamy oil—high oil recovery and delayed phase transition—from a microscopic perspective. A multi-scale coupling analysis method was established: molecular-scale simulations were employed to model component diffusion behavior. By improving the traditional Volume of Fluid (VOF) method and introducing diffusion coefficients, a synergistic model integrating a single momentum equation and fluid volume fraction was developed to quantitatively characterize the dynamic evolution of bubbles. Simulation results indicate significant differences in dominant controlling factors: oil phase viscosity has the greatest influence (accounting for ~50%), followed by gas component content (~35%), and interfacial tension the least (~15%). Based on multi-factor coupling analysis, an empirical formula for bubble growth incorporating diffusion coefficients was proposed, elucidating the intrinsic mechanism by which heavy components induce unique development effects through interfacial stabilization, viscous inhibition, and dynamic diffusion. This research breaks through the limitations of traditional production dynamic analysis, establishing a theoretical model for foamy oil development from the perspective of molecular-phase behavior combined with flow characteristics. It not only provides a rational explanation for the “high oil production, low gas production” phenomenon but also offers theoretical support for optimizing extraction processes (e.g., gas component regulation, viscosity control) through quantified parameter weightings. The findings hold significant scientific value for advancing heavy oil recovery theory and guiding efficient foamy oil development. Future work will extend to studying multiphase flow coupling mechanisms in porous media, laying a theoretical foundation for intelligent control technology development.

Some high-viscosity crude oils have the characteristics of high oil production, low gas production and slow pressure reduction speed during the pressure depletion production process, and the "foamy oil" phenomenon occurs. The coexistence time of the two phases of foamy oil is much longer than that of crude oil with ordinary dissolved gas. Its complex phase change process is an important reason for the high degree of primary oil recovery. In the past, most of the studies focused on the production performance of foamy oil, while there were relatively few studies on the regularity of the molecular phase behavior of microscopic foamy oil and its influencing factors. Taking the foamy oil in Venezuela as the research object, this paper uses an etched glass model with heterogeneous pore characteristics to simulate the pressure reduction process. It discovers an important phenomenon that the growth of bubbles mostly occurs during the migration process. It is speculated that the high content of heavy components in foamy oil leads to the stability of the interface between the oil phase and the gas phase, which is the main reason why foamy oil is not easy to degas and undergoes phase change slowly. And there is always a diffusion phenomenon between bubbles and the oil phase during the movement process. Combined with the experimental phenomena, molecular simulation was employed to calculate the diffusion process of components in the gas phase and oil phase. After taking the diffusion coefficient into account, the VOF (Volume of Fluid) method was adopted to simulate the growth process of bubbles in foamy oil by solving the individual momentum equations and handling the volume ratio of each fluid passing through the region. The influences of conditions such as the content of light components, oil phase viscosity and interfacial tension on the bubble growth process were analyzed. The simulation results show that the bubble growth process is affected by multiple conditions such as oil phase components, oil phase viscosity and interfacial tension. However, the degrees of influence of the above factors vary in different stages. In the initial stage of bubble formation, it is mainly influenced by the change in the content of light components. During the stage when the bubbles have relatively high stability, the oil phase viscosity is the main reason for slowing down the increase in the bubble growth rate. The slight influence of interfacial tension on the bubble growth rate is not a major influencing factor for foamy oil. Based on the above analysis, an empirical formula for bubble growth was obtained through data fitting means, and a reasonable explanation for the development characteristics of foamy oil was provided.

A single geological carbon dioxide (CO2) storage within salinity aquifer as a paramount stratagem in the context of forthcoming CO2 sequestration initiatives. Within the expansive tapestry of terrestrial salinity aquifers in China, replete with nuances in mineral composition and structural diversity, a paradigm distinct from the marine sedimentary basins of North America, a labyrinthine stratigraphic environment of elevated complexity unfolds. Consequently, conspicuous lacunae and insufficiencies manifest within the existing knowledge reservoir pertaining to CO2-water-rock (mineral) reaction mechanisms. Notably, a conspicuous dearth of insights prevails concerning the dissolution kinetics inherent to individual minerals embroiled in these reactions. The present investigation undertakes a scrupulous exploration into the dissolution and erosive processes manifest within four emblematic terrestrial minerals in conjunction with CO2. Furthermore, the study meticulously scrutinizes the evolution of ionic composition and pH within the formation water throughout the trajectory of the geochemical reactions. To accomplish this, a simulation apparatus is configured to emulate conditions germane to temperature, pressure, and mineralization characteristics characteristic of a prototypical salinity aquifer reminiscent of the Daqing oilfield in China. The findings that emerge from this scrutiny reveal that the erosive action of CO2 fluid begets varying degrees of dissolution within the four minerals under investigation. Moreover, our meticulous inquiry lays bare that, in the terminal phases of the reaction process, feldspar precipitates secondary minerals, characterized primarily by dawsonite, in response to the aquatic milieu typifying the profound salinity stratum of terrestrial sedimentation. This milieu is notably enriched with Na+ ions and NaHCO3. This phenomenon suggests that feldspar, under these specific conditions, assumes the mantle of a mineral amenable to carbon sequestration, thus enriching the reservoir for CO2 mineralization within the salinity stratum of terrestrial sedimentation.