The goals of carbon neutrality and peak carbon have officially been proposed; consequently, carbon dioxide utilization and sequestration technology are now in the limelight. Injecting carbon dioxide into reservoirs and solidifying and sequestering it in the form of carbonates after a series of geochemical reactions not only reduces carbon emissions but also prevents carbon dioxide from leaking out of the formation. Carbon dioxide mineralization sequestration, which has good stability, has been considered the best choice for large-scale underground CO₂ sequestration. To provide a comprehensive exploration of the research and prospective advancements in CO₂ mineralization sequestration within Chinese oil and gas reservoirs, this paper undertakes a thorough review of the mechanisms involved in CO₂ mineralization and sequestration. Special attention is given to the advancing front of carbon dioxide mineralization, which is driven by microbial metabolic activities and the presence of carbonic anhydrase within oil and gas reservoirs. The paper presents an in-depth analysis of the catalytic mechanisms, site locations, and structural attributes of carbonic anhydrase that are crucial to the mineralization processes of carbon dioxide. Particular emphasis is placed on delineating the pivotal role of this enzyme in the catalysis of carbon dioxide hydration and the promotion of carbonate mineralization and, ultimately, in the facilitation of efficient, stable sequestration.

Shut-in after fracturing is generally adopted for wells in shale oil reservoirs, and imbibition occurring in matrix nanopores has been proven as an effective way to improve recovery. In this research, a molecular dynamics (MD) simulation was used to investigate the effects of wettability and pressure on nanopore imbibition during shut-in for a typical shale reservoir, Jimsar. The results indicate that the microscopic advancement mechanism of the imbibition front is the competitive adsorption between “interfacial water molecules” at the imbibition front and “adsorbed oil molecules” on the pore wall. The essence of spontaneous imbibition involves the adsorption and aggregation of water molecules onto the hydroxyl groups on the pore wall. The flow characteristics of shale oil suggest that the overall push of the injected water to the oil phase is the main reason for the displacement of adsorbed oil molecules. Thus, shale oil, especially the heavy hydrocarbon component in the adsorbed layer, tends to slip on the walls. However, the weak slip ability of heavy components on the wall surface is an important reason that restricts the displacement efficiency of shale oil during spontaneous imbibition. The effectiveness of spontaneous imbibition is strongly dependent on the hydrophilicity of the matrix pore’s wall. The better hydrophilicity of the matrix pore wall facilitates higher levels of adsorption and accumulation of water molecules on the pore wall and requires less time for “interfacial water molecules” to compete with adsorbed oil molecules. During the forced imbibition process, the pressure difference acts on both the bulk oil and the boundary adsorption oil, but mainly on the bulk oil, which leads to the occurrence of wetting hysteresis. Meanwhile, shale oil still existing in the pore always maintains a good, stratified adsorption structure. Because of the wetting hysteresis phenomenon, as the pressure difference increases, the imbibition effect gradually increases, but the actual capillary pressure gradually decreases and there is a loss in the imbibition velocity relative to the theoretical value. Simultaneously, the decline in hydrophilicity further weakens the synergistic effect on the imbibition of the pressure difference because of the more pronounced wetting hysteresis. Thus, selecting an appropriate well pressure enables cost savings and maximizes the utilization of the formation’s natural power for enhanced oil recovery (EOR).

Crude oil gasification bacteria, including fermenting bacteria, hydrocarbon-oxidizing bacteria, reducing bacteria, and methanogenic bacteria, participate in multi-step reactions involving initial activation, intermediate metabolism, and the methanogenesis of crude oil hydrocarbons. These bacteria degrade crude oil into smaller molecules such as hydrogen, carbon dioxide, acetic acid, and formic acid. Ultimately, they convert it into methane, which can be utilized or stored as a strategic resource. However, the current challenges in crude oil gasification include long production cycles and low efficiency. This paper provides a summary of the microbial flora involved in crude oil gasification, the gasification metabolism pathways within reservoirs, and other relevant information. It specifically focuses on analyzing the factors that affect the efficiency of crude oil gasification metabolism and proposes suggestions for improving this efficiency. These studies deepen our understanding of the potential of reservoir ecosystems and provide valuable insights for future reservoir development and management.

Shut-in after fracturing is generally adopted for wells in shale oil reservoirs, and imbibition occurring in matrix nanopores has been proven as an effective way to improve recovery. In this research, the molecular dynamics (MD) simulation was used to investigate the effects of wettability and pressure on nanopores imbibition during shut-in for a typical shale reservoir Jimsar. The results indicate that the microscopic advancement mechanism of the imbibition front is the competitive adsorption between “interfacial water molecules” at the imbibition front and “adsorbed oil molecules” on the pore wall. The essence of spontaneous imbibition involves the adsorption and aggregation of water molecules onto the hydroxyl groups on the pore wall. The flow characteristics of shale oil suggest that the overall push of the injected water to the oil phase is the main reason for the displacement of adsorbed oil molecules. Thus, shale oil especially the heavy hydrocarbon component in the adsorbed layer tends to slip on the walls. However, the weak slip ability of heavy components on the wall surface is an important reason that restricts the displacement efficiency of shale oil during spontaneous imbibition. The effectiveness of spontaneous imbibition is strongly dependent on the hydrophilicity of the matrix pore's wall. The better hydrophilicity of the matrix pore's wall facilitates higher levels of adsorption and accumulation of water molecules on the pore wall and requires less time for “interfacial water molecules” to compete with adsorbed oil molecules. During the forced imbibition process, the pressure difference acts on both the bulk oil and the boundary adsorption oil, but mainly on the bulk oil, which leads to the occurrence of wetting hysteresis. Meanwhile, shale oil still existing in the pore always maintains a good stratified adsorption structure. Because of the wetting hysteresis phenomenon, as the pressure difference increases, the imbibition effect gradually increases, but the actual capillary pressure gradually decreases and there is a loss in the imbibition velocity relative to the theoretical value. Simultaneously, the decline in hydrophilicity further weakens the synergistic effect of pressure difference because of the more pronounced wetting hysteresis. Thus, selecting an appropriate well pressure enables cost savings and maximizes the utilization of the formation's natural power for EOR.

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.

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.