CO₂ flooding is currently one of the most important enhanced oil recovery technologies. In North America, it has entered a stage of stable industrial deployment, while in China, it has entered a stage of rapid development in industrial application. A comprehensive comparison reveals that CO₂ flooding is mainly applied to medium-to-shallow, low-temperature, low-permeability light oil reservoirs, predominantly using miscible flooding in the United States. In contrast, CO₂ flooding reservoirs in China are characterized by deeper burial, higher temperatures, lower permeability, and higher crude oil viscosity, resulting in poor injectivity and significant challenges in implementing miscible flooding, thereby limiting the effectiveness of CO₂ flooding. Focusing on CO₂ flooding in deep, low-permeability reservoirs in East China, this study systematically analyzed the displacement characteristics of CO₂ in such reservoirs. The main challenges included high miscibility pressure, low permeability, relatively poor injectivity, difficulty in effectively replenishing energy through water or gas injection, and significant challenges in implementing miscible flooding. However, miscible flooding can still be achieved through early high-pressure injection to supplement reservoir energy. Additionally, large-slug CO₂ injection requires over-pressured gas injection to maintain the miscible process. Gas-alternating-water injection could effectively achieve gas channeling control, expand sweep efficiency, and improve development performance of gas injection. A field pilot test of CO₂ flooding in the deep, low-permeability reservoir of Caoshe oilfield was conducted. The results showed that the primary gas injection employed an “early-stage injection, large slug, and full-process tracking” approach to conduct high-pressure miscible flooding tests, achieving a 12.4% increase in oil recovery and a CO₂ storage rate of over 85%. Currently, secondary gas injection is being implemented using a strategy of “layered development, low-speed high-interval injection, and variable-frequency alternating injection”. Based on the principles of "controlling override, preventing channeling, and curbing water flooding", a secondary gas injection adjustment plan is formulated. Field tests continue to show promising results, with an additional 5.1% increase in oil recovery and a storage rate maintained at 75%, demonstrating strong application potential.

Geological CO₂ storage is a critical part in carbon capture, utilization, and storage technology for achieving emission reduction goals. As the scale of CO₂ injection expands and its duration prolongs, the risks of leakage from wellbores and caprocks gradually increase due to wellbore integrity failures, fault reactivation, and fracture propagation or fissure development in caprocks. Post-leakage CO₂ will rise vertically and diffuse horizontally into subsurface including groundwater systems and soil environment, where it spreads extensively and undergoes multiple types of transformation, thereby affecting regional ecological and environmental safety. Under the coupled thermo-hydro-mechanical-chemical field within geological formation, such multi-pathway, cross-spatial, large-scale, and long-term migration, diffusion, and transformation processes are extremely complex. Accurate identification and quantitative assessment of leakage safety and environmental risk rely on various migration-transformation simulation methods. This study systematically summarizes the main leakage pathways of geological CO₂ storage (wellbores, caprocks, and faults), explains the leakage mechanisms, and discusses key influencing factors such as temperature, pressure, and geochemical reactions. The migration and transformation mechanisms of CO₂ after leakage in underground environments such as faults, caprocks, groundwater, and soil are analyzed, and the dominant controlling factors and environmental effects of migration and transformation are identified. This study reviews the simulation methods for CO₂ migration and coupled migration and transformation in caprocks, faults, groundwater, and soil, as well as their application in validating leakage mechanisms, identifying migration-transformation patterns, and predicting environmental risks. This study highlights that the current model still faces challenges in accurately simulating the dynamic distribution of gas phase exsolution in faults, cross-formation multi-environment coupling, and microbial transformation process. Future research should focus on coupled modeling of cross-formation multi-environment migration and transformation, achieve full-space and full-process simulations of migration and leakage, and establish an integrated simulation framework of injection-migration-leakage-diffusion systems, thereby enabling the application of optimized leakage monitoring and precise environmental risk prediction.

In the context of the “dual carbon” goals, offshore CO₂ geological storage offers significant advantages over onshore storage and represents a key development direction for future carbon capture, utilization and storage (CCUS) technologies. However, deep subsurface industrial activities such as CO₂ geological storage carry the risk of inducing earthquakes. Although the East China Sea Shelf Basin is a suitable area for offshore CO₂ storage in China, there is currently a lack of studies on the risk of induced earthquakes. An induced earthquake risk assessment method based on the Dieterich’s rate-and-state friction law was employed. Starting from fault stability analysis, the relative seismic activity rate on fault planes was correlated with Coulomb failure stress change. Both deterministic and probabilistic assessment approaches were used to investigate the induced earthquake risk associated with CO₂ injection in X block of the Xihu Sag, East China Sea. The results showed that: (1) The target reservoir in the middle Yuquan Formation within X block exhibited an anticline structure. The twelve faults divided the storage trap into northern and southern sections. The in-situ stress regime was potential normal faulting, and all faults were initially stable. (2) When CO₂ storage was conducted at a rate of 60×10⁴ t/a over 10 years into the southern trap, the diffusion of pore fluid pressure had a minor impact on surrounding faults, with a relatively low risk of inducing high-magnitude earthquakes. The estimated maximum magnitude of induced earthquakes within the block was 1.8. (3) Increasing the CO₂ injection rate would elevate the risk of induced earthquakes. While zonal injection could mitigate this risk, it may not be economically viable due to increased costs. The evaluation methods and findings presented in this study can serve as an assessment approach for induced earthquake risk in CO₂ geological storage, providing theoretical support for the safety of CCUS projects.

After being subjected to depletion production and water flooding, deep low-permeability oil reservoirs still retain about 60% of the original oil in place, which has become a major bottleneck restricting the efficient utilization of oil and gas resources. CO₂ miscible flooding, as an efficient enhanced oil recovery (EOR) technique, has attracted significant attention in recent years. However, during its practical application, the phenomenon of frontal breakthrough often occurs, leading to an uneven sweep efficiency and significantly reducing the overall oil displacement performance. This study employed nuclear magnetic resonance (NMR) and CT scanning techniques to systematically investigate the migration characteristics and microscopic mobilization mechanisms of CO₂ miscible fronts using deep low-permeability core samples with different permeability grades. The results indicated that core permeability significantly influenced the stability and migration behaviors of CO₂ miscible fronts. As permeability decreased, the pseudo-piston-like displacement pattern was disrupted earlier, and the degree of non-uniform frontal advancement intensified, specifically manifested as a shorter dimensionless migration distance and a notable decline in oil displacement efficiency in the middle and rear sections of the core. In terms of microscopic pore mobilization, CO₂ exhibited distinct sequential selectivity. It preferentially entered large pores, and gradually advanced into medium and small pores. With increasing core permeability, the mobilization of crude oil in medium pore throats significantly improved, reflecting more uniform displacement characteristics. Further correlation analysis showed a positive relationship between overall oil displacement efficiency and the dimensionless migration distance of the front, indicating that front stability was a key factor restricting the performance of oil displacement. This study reveals the migration patterns of CO₂ miscible fronts and pore-scale oil mobilization mechanisms in deep low-permeability reservoirs from a combined macro-micro perspective. The findings provide valuable insights for optimizing injection-production strategies and improving development performance, offering theoretical support and technical guidance for the efficient development of deep low-permeability reservoirs using CO₂ flooding.

Heavy oil accounts for about 70% of the world’s remaining proven crude oil reserves, yet its efficient development remains a significant challenge worldwide. Based on the carbon capture, utilization and storage (CCUS) framework, this study constructed silica nanochannels with fully hydroxylated surfaces to simulate real reservoir conditions. Molecular dynamics (MD) simulations were employed to explore the microscopic mechanisms of deep heavy oil emulsification under synergistic CO₂-thermal agent conditions. The study focused on three aspects. First, the influence of surfactant sodium dodecyl sulfate (SDS) on the emulsification performance of deep heavy oil in silica nanopores was studied, and emulsification behaviors and oil droplet stability with and without surfactants were compared. Second, steered molecular dynamics (SMD) simulations were used to analyze the forces and motion of oil droplets in silica channels, which revealed the key factors affecting droplet stretching and rupture. Finally, the emulsification mechanism under synergistic “thermal + chemical agent + CO₂” conditions at 150 ℃ was investigated, and the emulsification performance of the CO₂-thermal agent synergy was explored. The results showed that: (1) The addition of surfactants significantly enhanced emulsification stability, increasing the solvent accessible surface area (SASA) of oil droplets by 7.4% on average while optimizing their spatial distribution. (2) Oil droplet migration must overcome the resistance from the channel’s hydration layer, with the center-of-mass displacement exhibiting a three-stage evolution relationship with the external force. (3) The synergistic interaction between CO₂ and thermal agents could effectively accelerate the emulsification process of deep heavy oil, resulting in an oil droplet diffusion coefficient of 5.733×10^-9 m²/s, which marked a 31.0% increase compared to the condition with thermal agents alone. This study provides a new theoretical basis for understanding the microscopic mechanisms of deep heavy oil emulsification under CO₂-thermal agent synergy while offering potential technical references for efficient deep heavy oil extraction in practical oilfield operations.

The deep volcanic reservoirs of the Huoshiling Formation in the Songliao Basin face severe challenges for economically efficient development due to ultra-low permeability and extreme compactness, while also presenting potential target reservoirs for CO₂ utilization and storage under CCUS scenarios. To address this challenge, this study explored and verified a water-rock interaction modification method based on supercritical carbon dioxide (SC-CO₂) synergized with formation water. Through SC-CO₂ saturation dissolution reaction experiments, combined with X-ray diffraction (XRD) mineral quantitative analysis, field emission scanning electron microscopy (FE-SEM) microstructural characterization, and rock mechanical property testing, the modification effects of SC-CO₂ synergized with formation water on the reservoir were systematically investigated. The experimental results showed that SC-CO₂ preferentially dissolved minerals such as plagioclase and calcite, leading to a significant reduction in clay mineral content and the formation of microscopic fractures and pore throats. Three-dimensional digital core models constructed from CT scans further revealed that SC-CO₂ treatment significantly improved reservoir pore structure: the proportion of dominant flow channels with coordination numbers (CN) >3 increased by approximately 11%, while pore volumes with throat radii >6 μm expanded by over 16.5%. The trends of simulated permeability were consistent with the changes in actual gas permeability measurements, both showing year-on-year increases exceeding 90%. Meanwhile, rock mechanical tests indicated that after SC-CO₂ treatment, the compressive strength of rock samples decreased by 19.6%, the elastic modulus decreased by 13.2%, and the Poisson’s ratio increased by 8.7%. Combined with scanning electron microscopy (SEM) observations, these results confirmed that mechanical weakening effectively induced a secondary fracture network. The study indicated that SC-CO₂, owing to its nanoscale molecular diffusion capability and zero interfacial tension, could effectively penetrate micro- and nano-scale pores and react with pore-bound water to form carbonates. Through water-rock interactions, it deeply dissolved the interior of the reservoir, effectively overcoming the limitation of traditional acid fluids in accessing micro- and nano-scale pores. This method provides new theoretical foundations and technical pathways for the cost-effective development of deep volcanic reservoirs and for CO₂ co-storage and enhanced recovery modification in CCUS technology.

In numerical simulations of CO₂ storage sequestration in saline aquifers, calculating the gas-water phase equilibrium is a critical step for determining the physical property parameters of the gas-water system, and their accuracy directly affects the reliability of simulation results. Current simulations of CO₂-brine phase equilibrium often inadequately account for ionic effects and fail to build upon established gas-water phase equilibrium frameworks, thereby compromising result reliability. This study aims to establish a high-precision CO₂-brine phase equilibrium model. Based on the law of molar conservation and fugacity equality principles, an innovative phase equilibrium model incorporating ionic effects was established. The model accuracy was validated through comparison with experimental data, and phase equilibrium patterns during CO₂ storage in deep saline aquifers under different formation conditions were analyzed. The results indicated that the modified physical property parameters could accurately characterize CO₂ solubility in both single-salt and mixed-salt solutions. The established model could quantitatively describe key indicators in CO₂-brine phase equilibrium calculations, including liquid-phase molar density, gas-phase molar density, component molar fractions, and saturation. The presence of ions increased the mole fraction of H₂O while decreasing that of CO₂ in the liquid phase. It simultaneously increased the liquid-phase molar density but reduced liquid-phase saturation. Gas-phase component composition and molar density remained essentially unchanged, while gas-phase saturation exhibited an upward trend. Higher ionic concentrations exerted more significant effects on phase equilibrium calculations. Notably, Ca²⁺ and Mg²⁺ ions exerted substantially stronger effects than Na⁺ and K⁺ ions. This model established in this study overcomes the limitations of traditional models by inheriting the framework of the gas-pure water system and innovatively introducing ionic correction. This study provides high-precision fundamental data for numerical simulation of CO₂ storage in deep saline aquifers, offering significant theoretical value for advancing carbon storage technology. This model is derived from the gas-pure water system model and demonstrates good extendability.

Injecting carbon dioxide (CO₂) into carbonate gas reservoirs can achieve the geological storage of CO₂ while enhancing methane (CH₄) recovery. To address the inaccurate characterization of fluid flow in fractured-vuggy carbonate gas reservoirs, the Peng-Robinson (PR) equation of state was used to calculate fluid properties, and a dual-porosity dual-permeability numerical model considering both convection and diffusion was established. This model was used to analyze the effects of factors including fracture permeability, reservoir dip angle, fracture porosity, matrix porosity, and gas injection rate on CH₄ recovery and CO₂ storage capacity. The numerical simulation results showed that higher fracture permeability led to higher CH₄ production rates in the early stage, but the CH₄ production rate declined rapidly after CO₂ breakthrough. Increasing fracture porosity and matrix porosity significantly improved CH₄ recovery and CO₂ storage capacity. An increase in reservoir dip angle resulted in higher CH₄ recovery and CO₂ storage capacity due to gravity segregation effects. Higher gas injection rates resulted in more significant pressure maintenance and energy replenishment, leading to higher production rates of both CH₄ and CO₂ but causing a decrease in both CH₄ recovery and CO₂ storage capacity. Matrix permeability, injection timing, and the presence of 5% O₂ had a relatively small impact on the enhancement of recovery and storage. Based on the numerical simulation results, the weights of the influencing factors were determined using the coefficient of variation method and expert weighting method. Then, an evaluation indicator system for CO₂-enhanced recovery and storage in carbonate gas reservoirs was constructed using the analytic hierarchy process. A comprehensive evaluation was conducted on different blocks of the WLH gas reservoir. The comprehensive evaluation results showed that significant differences in reservoir physical properties were observed among different blocks, and the weights of indicators such as fracture permeability, fracture porosity, and reservoir dip angle directly affected the evaluation results. However, the overall trend was consistent with the model analysis, confirming the effectiveness and accuracy of the evaluation indicator system. The findings provide a theoretical basis and an effective evaluation indicator system for CO₂-enhanced gas recovery and carbon storage in fractured carbonate gas reservoirs.