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.

Carbon capture, utilization and storage (CCUS) is a key technology for achieving carbon neutrality, providing the dual benefits of enhanced energy production and reduced CO₂ emissions through CO₂-enhanced oil and gas recovery (EOR/EGR) and geological storage. However, the large-scale application of CCUS technology faces technical challenges such as engineering design and risk assessment. Traditional approaches, which rely on empirical formulas, experimental verification, and physical models, suffer from low computational efficiency, limited model accuracy, and difficulties in handling multi-dimensional coupling when addressing complex systems. Machine learning (ML), with its powerful data-driven analytical capabilities and adaptive optimization features, can establish high-precision prediction models, optimize operating parameters, predict reservoir fluid behavior, and assess leakage risks. This enables real-time monitoring and intelligent decision-making for complex systems, enhancing the safety and economic efficiency of CCUS technology. This study systematically reviews the applications of ML in CO₂-enhanced oil and gas recovery and geological storage. In terms of CO₂-enhanced oil and gas recovery, the applications cover percolation mechanism modeling, well pattern design optimization, production prediction and evaluation, multi-objective optimization, minimum miscibility pressure prediction, gas adsorption curve prediction, and CO₂-CH₄ diffusion assessment. For CO₂ geological storage, the applications include reservoir selection, research on CO₂ dissolution and diffusion mechanisms, geological storage performance prediction, and risk assessment. ML demonstrates significant advantages in improving prediction accuracy, optimizing operating parameters, and enhancing computational efficiency. It has made important progress in key fields such as reservoir selection, gas adsorption prediction, and storage performance prediction. However, challenges remain in terms of adaptability to complex geological scenarios, model universality, dynamic data processing capabilities, and physical interpretability.

The shallow CO₂ geological storage in block A of the East China Sea faces challenges such as large difference in horizontal in-situ stress and significant influence of cyclic stress. However, existing cement sheath integrity models have not effectively established the coupling mechanism between non-uniform in-situ stress field and residual strain, making it difficult to effectively evaluate the sealing failure behavior of cement sheath in shallow low-pressure reservoirs of block A of the East China Sea. Therefore, aiming at the performance design and integrity evaluation of cement sheath under intermittent cyclic loading-unloading conditions of CCS pilot test well in block A of East China Sea with high in-situ stress difference, and considering the influence of non-uniform in-situ stress and residual strain of cement sheath, a casing-cement sheath-formation stress calculation model was established based on the evaluation criteria of shear failure and tensile failure safety factors of the cement sheath. Using the geological engineering parameters of CCS pilot test well in block A of East China Sea, mechanical stress analysis and integrity evaluation of cement sheath were conducted, and influencing factors such as in-situ stress difference, residual strain, and elastic modulus of cement sheath were analyzed. The results showed that the casing-cement bonding interface along the direction of minimum horizontal in-situ stress was the weak point for tensile failure and shear failure of cement sheath. When the wellhead injection pressure increased, the shear failure safety factor of cement sheath increased exponentially while the tensile failure safety factor increased linearly, and the cement sheath tended to undergo plastic shear failure first. In addition, the in-situ stress difference helped increase the margin of cement sheath failure safety factor, while the increase of cement sheath residual strain caused the increase of cement sheath failure safety factor. The shear failure safety factor of cement sheath first increased and then decreased with the increase of elastic modulus. Therefore, it is necessary to establish a dynamic control mechanism of injection pressure and optimize the cyclic loading path to suppress the cumulative effects of residual strain. To reduce the high cumulative risk of residual strain under conditions of high elastic modulus of cement, and to avoid the problem of low shear failure safety factor margin under relatively low elastic modulus conditions, it is necessary to determine the threshold of elastic modulus according to the injection pressure conditions in engineering practice, ensuring that the stress concentration effects are reduced while avoiding the local extreme value region of the shear failure safety factor.

The poor physical properties and low pressure coefficient of tight oil reservoirs make it difficult to directly apply the advanced water injection development technology, which has been successfully used in low-permeability oil reservoirs, to tight oil reservoirs. The advanced CO₂ injection technology, as an emerging method for enhancing oil recovery, has received increasing attention. However, its microscopic oil displacement characteristics and enhanced oil recovery effectiveness require further investigation. Therefore, core samples from the Chang 8 member reservoir of the west 331 block in the Ordos Basin were selected. Experiments including water flooding, CO₂ flooding at different pressures, and advanced CO₂ injection flooding at different pressures were conducted using nuclear magnetic resonance (NMR) technology. The oil recovery characteristics and microscopic mobilization characteristics under different development methods were clarified. Meanwhile, a calculation model for the mobilization lower limit was established based on the capillary model, and the pore mobilization lower limits under different development methods were obtained. The experimental results showed that the oil recovery of water flooding was about 40%, with the oil primarily produced from macropores, while meso- and micropores exhibited poor mobilization. Compared with water flooding, the oil recovery of supercritical CO₂ flooding was higher and increased with the injection pressure, reaching 76% under miscible conditions. The advanced CO₂ injection flooding further enhanced the recovery rate, achieving 87% when the pressure reached 1.2 times the miscible pressure, with meso- and micropores contributing 14.1% of the recovery—approximately 1.5 times that of miscible flooding. After water flooding and non-miscible CO₂ flooding, the remaining oil was mainly in the form of continuous remaining oil, with a considerable amount still present at the core outlet end. As the CO₂ flooding pressure increased, the crude oil saturation decreased significantly, and the continuous remaining oil diminished, resulting in more isolated oil droplets. After advanced CO₂ injection flooding, the crude oil saturation further declined, and the large area of continuous remaining oil significantly reduced, primarily manifesting as isolated oil droplets and small clusters of continuous remaining oil. The mobilization lower limit of water flooding was 200 nm, and the pore mobilization lower limits of CO₂ flooding and advanced CO₂ injection flooding decreased with increasing injection pressure. Advanced CO₂ injection flooding can mobilize crude oil in 20 nm pores.

The carbon capture, utilization and storage (CCUS) technology can achieve the strategic goals of enhanced oil recovery for economic benefits and carbon reduction and storage for green development. However, while the technology has developed rapidly, certain problems and technical challenges have emerged, limiting its widespread application. Based on the first million-ton CCUS demonstration project in China, this study addressed reservoir development conflicts and technical challenges by integrating theoretical research, laboratory experiments, and field practices. Guided by miscible flooding theory, reservoir development and field issues were analyzed to further refine the development theories and technical approaches. Additionally, this study summarized and extracted the key technologies and their theoretical connotations of high-pressure miscible flooding in medium-deep low-permeability reservoirs. The demonstration project implemented the concept of “full-process high-pressure miscible CO₂ flooding”, and adopted strategies of “continuous injection to maintain miscibility, integrated oil-water synergy to establish displacement, and injection-production synergy to expand sweep efficiency” to boost reservoir energy and expand sweep volume. These approaches developed key technologies, including differential energy supplementation for high-pressure miscible flooding, balanced displacement, three-phase front control, gas flooding monitoring, high-efficiency storage. The understanding of reservoir development and key technologies of CO₂ flooding were gradually improved, supporting the demonstration project in achieving favorable outcomes of reservoir development. Focusing on exploring new technologies, solving technical challenges, and improving the theoretical understanding of CO₂ flooding, million-ton CCUS field experiments were conducted in the demonstration zone. Among the 13 units, 10 development units achieved miscibility, with a CO₂ gas flooding sweep efficiency of 79.3%. The inter-well group gas channeling rate was controlled at 7.1%, and single-well oil production increased from 1.8 t/d to 3.2 t/d. The gas-oil ratio was controlled within 300 m³/d, and the gas flooding efficiency gradually increased to 0.21 t/tCO₂ (the amount of crude oil obtained per ton of CO₂ injected into the reservoir), showing a continuous upward trend. During the gas reinjection phase, the storage rate reached 97.1%. The theoretical understanding and technical practice of efficient CO₂ flooding in the demonstration zone provide significant guidance and reference for the miscible flooding of similar low-permeability reservoirs, effectively exploring advancement and broader application of CCUS technology.

Quantitative calculation of CO₂ geological storage potential is a crucial component of preliminary storage site suitability assessment and subsequent quantitative verification. Oil and gas reservoirs are preferred geological formations for CO₂ storage, as they combine the economic benefits of enhanced recovery and the environmental benefits of carbon storage. Among them, conventional (depleted) oil and gas reservoirs with well-developed trap structures form the foundation for the development and application of classical carbon storage potential assessment models. However, models that account for different reservoir conditions, different project stages, and fully consider the contributions of various storage mechanisms still require further advancement. This paper systematically reviews the CO₂ storage mechanisms and storage potential assessment methods for oil and gas reservoirs, and analyzes and summarizes the development history and application practices of these models. In terms of storage mechanisms, oil reservoirs mainly involve structural, residual, solubility, and mineral trapping, whereas gas reservoirs rely on the synergistic effects of pressure replenishment, competitive adsorption, and gravitational segregation. Twenty mainstream potential assessment models are categorized into four stages based on their fundamental principles: models considering geological reserves and recovery factors, models considering available reservoir pore space for storage, improved and extended models derived from the original models, and models focusing on new perspectives and localized approaches. Current models still primarily emphasize structural and residual trapping, with only a few quantifying solubility and mineralization contributions. Refinement of input parameters and uncertainty quantification have become development trends. Further research is needed on miscibility pressure prediction, solubility calculation, mineralization reaction kinetics, and the spatiotemporal evolution mechanisms of competitive gas adsorption. In the future, integrating geological monitoring data and artificial intelligence technologies and developing lightweight assessment tools will be essential to support site-level engineering decisions and advance the transition of storage potential assessment from theoretical feasibility to engineering implementation.

Shale in continental lacustrine basins has the characteristics of diverse lithofacies types and complex vertical superposition. On the basis of lithofacies type classification, the classification of lithofacies combination types and the selection of favorable combination are of great significance for identifying the “sweet spot” layers and areas of shale oil. The second member of the Funing Formation in Gaoyou Sag is a key area and stratigraphic unit for shale oil exploration in Subei Basin. Its lithofacies types have thin single layers and frequent vertical variations. Therefore, the research on the classification and evaluation of lithofacies combination types is still in the preliminary stage. Taking the well HY7 in the deep second member of the Funing Formation in Gaoyou Sag as the research object, methods including core observation, thin section identification, whole-rock X-ray diffraction analysis, and major and trace element analysis were employed. Based on lithofacies type identification and vertical sedimentary environment evolution analysis, the lithofacies combination type classification and development patterns were investigated. By comparing the evaluation parameters of different lithofacies combination types, the favorable combination types were optimized and selected. The results showed that the well HY7 in the second member of Funing Formation was mainly composed of mixed rock facies and felsic rock facies, with layered or laminated felsic-calcareous/dolomitic mixed rocks being the most developed. The sedimentary environment of the second member of the Funing Formation vertically showed early dry-late wet climate, early shallow-late deep water depth, early high-late low salinity, early high-late low provenance supply, and early low-late high productivity, which could be divided into six evolution stages. Considering sedimentary cycle changes in each evolution stage, the vertical superposition relationships of different lithofacies types, and their thickness proportions, seven main lithofacies combination types were identified. Among them, the interbedded combination of layered or laminated felsic-argillaceous mixed rocks and felsic-calcareous/dolomitic mixed rocks had the highest thickness proportion and was the most favorable combination type. The lithofacies assemblages dominated by layered/laminated carbonate rocks and felsic-calcareous/dolomitic mixed rocks could serve as good reservoir layers.

The first member of the Paleogene Funing Formation (hereinafter referred to as E₁f₁) is one of the oil-rich and gas-rich strata in Gaoyou Sag, Subei Basin. It has considerable exploration potential in deep reservoirs, but the overall poor reservoir physical properties have constrained the exploration expansion in this area. To determine the distribution patterns and favorable zones of local "sweet spot" reservoirs with well-developed abnormally high porosity and favorable reservoir conditions, it is necessary to systematically study the genetic types and reservoir evolution models of abnormally high porosity in deep E₁f₁ of Gaoyou Sag. Using reservoir physical property analysis, thin section observation, scanning electron microscopy, and cathodoluminescence, along with stripping the thickness of the Yancheng Formation and dividing tectonic units, this study conducted the physical property analysis of deep reservoirs in E₁f₁. Significant differences were observed in the distribution characteristics of abnormally high porosity among different zones. Specifically, the slope zone developed two abnormally high-porosity intervals, while the fault-step zone developed only one abnormally high-porosity interval. Additionally, the abnormally high-porosity development zones were identified. By analyzing differential genetic controlling factors of abnormally high porosity in different zones, it was determined that oil and gas charging and abnormally high pressure were the two key factors controlling the development zones and genetic types of abnormally high porosity. Oil and gas charging contributed to promoting dissolution and inhibiting cementation, serving as a key controlling factor for the development of abnormally high porosity in the middle slope and fault-step zones. In contrast, abnormally high formation pressure facilitated oil and gas charging, and contributed to diagenetic processes such as promoting dissolution, inhibiting cementation, and slowing compaction, functioning as a key controlling factor for the development of abnormally high porosity in the inner slope zone. Based on differences in key factors and the distribution of formation pressure zones, abnormally high porosity in E₁f₁ was classified into two genetic types: oil and gas charging type and abnormally high pressure type. The oil and gas charging type was mainly distributed in the middle slope and fault-step zones, characterized by relatively shallow burial depths and local occurrence in deep field. The abnormally high-pressure type was mainly located in the inner slope zone, representing the main type in deep field. Two evolution models for abnormally high porosity in deep E₁f₁ were established. Specifically, the middle slope and fault-step zones were mainly characterized by oil and gas charging and pore-preserving dissolution model, while the inner slope zone was characterized by oil and gas charging and abnormally high pressure for pore-preserving superposition dissolution model. On this basis, it is indicated that effective traps in structural high zones overlapping with abnormally high pressure areas of formations in the inner slope and other deep field are favorable locations for the development of “sweet spot” reservoirs, providing a basis for expanding exploration in deep field.

To address the challenge of rapid bottom water breakthrough along fractures during water injection in fracture-cavity reservoirs, which makes “attic oil” difficult to recover effectively, a strategy of “gel-inorganic particle synergy damming for water control and oil enhancement” was proposed. The method constructed a stable dam with specific height and slope in near-wellbore cavities through the synergistic effects of gel plugging of channeling paths and vertical stacking of inorganic particles, raising the overflow point to divert bottom water, thereby expanding the water flooding sweep volume and mobilizing the remaining oil at the top. Based on field well cases and actual geological models, a large-scale visual physical model of fracture-cavity reservoir was established. Equivalent plugging agents and injection-production parameters were designed using similarity principles to simulate the in-reservoir damming process. The migration and distribution patterns of plugging agents under different injection modes were investigated, and the effects of plugging agent combination, slug number, total agent volume, agent ratio, injection rate, and cavity filling degree on dam morphology and performance of water control and oil enhancement were analyzed. Finally, based on back propagation (BP) neural network, a model was established to predict damming height and performance of enhanced oil recovery (EOR). The experimental results demonstrated that: (1) the gel-inorganic particle synergistic damming could effectively mobilize the top remaining oil in cavities, increasing recovery by 14.4% with significant water control and oil enhancement performance. (2) Plugging agent combinations directly determined dam morphology and height, while injection parameters significantly influenced the migration patterns of plugging agents, thereby affecting the performance of water control and oil enhancement. (3) After sufficient training, the BP neural network-based model successfully predicted dam height and EOR under different injection modes, with root mean square errors of 22.24 and 2.92, respectively. The study reveals the mechanisms of synergistic damming, clarifies directions for process parameter optimization, and provides new insights and effective methods for enhancing oil recovery in the later stages of water injection in fracture-cavity reservoirs.

The Xihu Sag is a hydrocarbon-rich sag with high oil and gas exploration value in East China Sea Shelf Basin. In recent years, continuous breakthroughs have been achieved in the exploration efforts of the Eocene Pinghu Formation of Xihu Sag, making it an important target for oil and gas exploration and development. However, previous studies were mostly carried out on a macroscopic regional scale with scattered data, resulting in many controversies in the academic community regarding the depositional system of the Pinghu Formation, which seriously affects the accuracy and efficiency of subsequent exploration and development. Focusing on the early deposition of the Pinghu Formation in the Pingbei area of Xihu Sag, this study comprehensively utilized data including core, well logging, and seismic data to conduct an in-depth investigation of the depositional system, aiming to clarify depositional characteristics and establish a depositional model. This study divided the lower Pinghu Formation into two third-order sequences: Sequence 1 (SQ1) and Sequence 2 (SQ2). Both exhibited significant tidal depositional characteristics, with diagnostic depositional structures including bidirectional cross-bedding, reactivation surfaces, double mud layers, and flaser-wavy-lenticular tidal composite bedding. During the SQ1 period, the study area exhibited a typical barrier coastal depositional environment. The NE-SW-trending barrier sand bars divided the area into two parts. A lagoon-tidal flat system was formed on the west side, where depositional microfacies such as tidal channels and delta fronts developed. On the east side, there was an open coastal system, where strip-shaped longshore sand bars developed parallel to the barrier island. During the SQ2 period, affected by regional transgression, the development of the barrier island-lagoon system was suppressed, and the depositional environment transformed to a tide-dominated open tidal flat, completely developing depositional sequence of sand flat-mixed flat-mud flat. Affected by tidal action, NW-SE trending tidal channels developed in the intertidal and subtidal zones, and tidal sand bars and sand flats also developed in the subtidal zone. Furthermore, through a detailed analysis of sand body types, shapes, and distribution patterns, combined with the depositional environment and classic depositional models, a barrier coastal-tidal flat composite depositional model was established. The establishment of this model not only provides a basis for understanding the depositional evolution process of the Xihu Sag, but also offers guidance for oil and gas exploration and development from the slope zone to the sag area in Xihu Sag.

The East China Sea experiences extreme waves and frequent typhoons. Currently, the installation design of jacket platforms in the East China Sea is mainly based on the sea state restrictions and standby coefficient obtained from installation experience in the South China Sea. Consequently, the actual installation period and investment of jacket platforms in the East China Sea deviate significantly from design expectation. Therefore, studying the operation windows of jacket platform construction in the East China Sea plays an important guiding role in ensuring their safe and economical installation. At present, a large number of studies have focused on the operation windows for offshore wind turbines in shallow waters, and some studies have analyzed the operation windows for offshore operation in the deep waters of the South China Sea. However, research on offshore operation in the East China Sea remains limited. The area of the East China Sea investigated in this study is classified as mid- to deep-water, with depth ranging from 80 to 110 m, and its waves are larger than those of the South China Sea. The jacket platforms operating in this area have significantly greater sizes and weights than offshore wind turbines, making the installation of offshore oil and gas platforms much more difficult than offshore wind turbines in this area. The stability of the floating crane vessels and the property of the cranes are very important for the offshore installation. Generally, both daily reports during the operation period of the installation and the simulation analyses according to the design parameters of floating crane vessels such as Huatianlong, Blue Whale, are essential. Code checking based on Noble Denton and API standards was performed on the operation performance of floating crane vessels and cranes. By comprehensively analyzing the actual installation conditions of the platforms, the stability of floating crane vessels, the capability of cranes, and the environmental conditions were identified to meet the requirements for jacket platform installation by the crane vessels. The results showed that when the jacket was installed, the wind speed was required to be no more than 10 m/s, and the significant wave height must not exceed 2.0 meters. Otherwise, when the stability of the floating crane vessels deteriorated, the installation conditions could not be satisfied. When the topsides were required to nest the Christmas tree, stringent demands were imposed on the floating crane vessels regarding sea conditions, limiting the wind speed to no more than 10 m/s and the significant wave height to no more than 1.5 meters. When the topsides were installed conventionally, wind speed for the floating crane vessels was required to be more than 14 m/s, and the significant wave height was not more than 2.0 meters. During the installation phase of the jacket platform, the feasibility of offshore installation and the period of the installation mainly depended on the stability of the floating crane vessel and the strength of the platform. The jacket platform mainly consisted of a jacket and topsides. The installation design reports of 3 jackets and 4 topsides implemented in the East China Sea were investigated. All jackets were designed according to the significant wave height not more than 1.5 meters and the wind speed less than 10 m/s. In addition, only one of the four topsides installation was designed with a significant wave height not exceeding 2.0 meters, while the other topsides were designed with a significant wave height not exceeding 1.5 meters, with the wind speed less than 10 m/s. It could be concluded that the sea conditions adopted in the installation design of a jacket and topsides were calmer than the sea conditions allowable for the stability of the floating crane in the actual installation process. Therefore, the sea conditions adopted in the installation design of a jacket and topsides should be used as the governing sea conditions during the installation process. A high-precision model was used to simulate the sea state conditions of the target sea areas in the East China Sea, and the simulation results were calibrated based on both the prediction and observation data of the nearby sea area. Consequently, the high-precision wind wave data of the East China Sea from 2015 to 2023 were obtained, enabling the establishment of an innovative sea state database with long time span and large data capacity. On this basis, research methods such as comprehensive analysis method and reverse inference method were used to analyze the wind and wave data. Wind speed and wave height were identified as two key factors to be considered in evaluating the operation windows. It should be noted that the requirements for weather conditions varied significantly at different stages of offshore installation of the jacket platform. Specifically, the launch of the jacket imposed relatively higher requirements for sea conditions, while the requirements for pile driving and grouting operation of the jacket were relatively lower. To further evaluate the duration of the window period in terms of time and safety, a comprehensive analysis method for offshore operation windows considering the effects of wind, waves, and sustainable operation time conditions was innovatively proposed. In this analysis, any period of continuous offshore installation shorter than the required duration was excluded from being counted as an operation window. According to the large amount of data involved, it was assumed that the wind speed did not exceed 12 m/s, and the significant wave height was not more than 1.5 meters to simplify and accelerate the statistical analysis. Then, the duration of installation periods meeting the wind and wave requirements were statistically analyzed for intervals of at least 24, 48, and 72 hours, respectively. A code was developed via MATLAB to read the wind and wave data day by day, and subsequently, the annual and monthly operation windows were evaluated. Finally, reverse inference analyses were performed. The results showed that the average number of operation windows exceeded 15 from March to August, and the number of operation windows in October was at least 8.44 under the conditions of 24-hour continuous operation. Under the conditions of 48-hour continuous operation, the average number of operation windows exceeded 10 from March to September, and there were at least 4.75 in December. Under the conditions of 72-hour continuous operation, the average number of operation windows was more than 10 from April to August, and at least 2.38 in December. In conclusion, the optimal window for offshore installation of the jacket platform in the East China Sea is from April to June. If the significant wave height of the installation operation considered in design is increased from 1.5 meters to 2.0 meters, the weather standby coefficient will be reduced by 20% to 40%. Therefore, to improve the offshore installation efficiency of jacket platforms and reduce the waiting probability, it is recommended to adopt the significant wave height of 2.0 meters for jacket installation design. When the topsides are required to nest the Christmas tree, the installation design should adopt the significant wave height of 1.5 meters, and the installation design of the remaining topsides should adopt significant wave height of 2.0 meters. These research findings fill the gap in the operation window data for the East China Sea and effectively ensure the safety of the offshore installation of jacket platforms.

The Qiongdongnan Basin is located in the northwestern part of the continental shelf in the northern part of the South China Sea, which is a Cenozoic highly-overpressured, transformed, and extended basin with abundant oil and gas resources. The Qiongdongnan Basin is also a typical offshore HTHP basin in China, and is one of the world’s top 3 offshore HTHP areas, with the highest reservoir temperature of over 240 ℃ and the highest formation pressure coefficient of 2.3, which makes it one of the most difficult areas for domestic and international drilling operations. The complex genesis mechanism of abnormal high pressure in the Qiongdongnan Basin of the South China Sea results in great difficulty and low accuracy of pre-drilling pressure prediction, which seriously compromises drilling safety. Block 64/07 of Lingshui structure in Qiongdongnan Basin was taken as the research object. Through analysis of tectonic evolution and loading/unloading mechanisms, the coupling genesis mechanisms of abnormal high pressure in this block were revealed, a multi-mechanism coupling pressure prediction method was specifically established, and formation pressure profiles of drilled wells and a 3D regional formation pressure model were constructed, systematically analyzing the vertical and horizontal pressure systems of this block. The Qiongdongnan Basin has experienced many rounds of tectonic evolution since the Paleocene, forming a huge thickness of Paleocene-Neocene and Quaternary sediments. From the perspective of the depositional history of the Qiongdongnan Basin, the sedimentation rate of the whole basin is relatively high, with two distinct peaks. The first peak occurred in the fracture to fracture-argument period, with a subsidence rate exceeding 600 m/Ma. The second appeared during the post-fracture rapid subsidence period, with the Yinggehai Formation reaching 600~1 700 m/Ma. Both rates exceeded the 150 m/Ma threshold for overpressure, and these periods were prone to the formation of anomalous high pressures with undercompaction mechanisms. These processes were the basis of the overpressure prevalent across the entire basin, and were manifested as loading-type anomalous high pressures. Meanwhile, the FS fracture zone in this region had the ability to transmit oil and gas, forming a two-way hydrocarbon supply pattern between the main depression and the secondary depression in western Lingshui. The hydrocarbons had two large-scale hydrocarbon discharge periods (15 Ma and 5 Ma), and the Meishan~Sanya Formation underwent prolonged effective charging, creating conditions for high pressure caused by fluid charging, which was the most probable auxiliary cause of anomalous high-pressure formation in this region. Using the logging data of the drilled wells, the rock density-sound wave velocity crossplot of the stratified sections was established, and the Meishan Formation showed a composite mechanism of loading and unloading. Combined with the tectonic evolution history, it could be inferred that the anomalously high pressure of Yinggehai and Huangliu Formations was attributed to the undercompaction mechanisms, and the anomalously high pressure of Meishan Formation resulted from the coupling mechanism of undercompaction and fluid filling. To address the high-pressure coupling genesis mechanism of this block, this study developed a multi-mechanism coupling pressure prediction method. The upper Yinggehai Formation and Huangliu Formation under-compacted strata were evaluated using the conventional Eaton method, and the lower Meishan Formation and Sanya Formation stratigraphic over-pressure zones were analyzed using the multi-parameter effective stress method, thereby overcoming the limitations of single-method prediction and improving prediction accuracy. Based on this method, a high-precision three-dimensional stratigraphic pressure body was constructed in Lingshui tectonic block 64/07, revealing the vertical and horizontal distribution patterns of stratigraphic pressure in this block. The results showed that the high pressure in formations above Huangliu Formation in this area was caused by undercompaction mechanism, while below Meishan Formation it was caused by the coupling mechanism of undercompaction and fluid charging. Vertically, pressure began to increase in the middle and lower part of Yinggehai Formation, Huangliu Formation served as the pressure transition zone, and Meishan and Sanya Formations entered the overpressure zone, with the highest pressure coefficient reaching 2.10. Horizontally, it generally presented the characteristics of “low in the west and high in the east, low in the north and high in the south”. These research findings were applied to well L5-1. The core of this method lay in addressing the coupling genesis of formation pressure in the Meishan Formation by establishing a multi-parameter effective stress method. Parameters such as shale content, porosity, and effective stress of the lower high-pressure layer were introduced, avoiding the difficult problem of determining original sedimentary loading and subsequent unloading, thereby achieving accurate prediction of reservoir high pressure. During the drilling process of well L5-1, a combination of pre-drilling pressure prediction, logging monitoring, logging constraints on seismic layer velocity and MDT pressure correction were used to follow up and monitor the trend of pressure change throughout the entire process in real time. The entire pressure monitoring process could be divided into four stages: (1) determining the starting pressure layer at the pre-drilling design stage as the bottom of Ledong Formation and the top area of Yinggehai Formation; (2) adjusting the starting pressure depth from 2 100 m to 1 850 m based on the three-opening single-root gas pressure and the pressure monitoring profile with drilling; (3) using the four-opening electroacoustic constraints to recalibrate the extracted layer velocity, combined with the MDT pressure measurements, to correct the parameters of the prediction model; (4) conducting five-opening monitoring and the DST test after completion of drilling to complete the real drilling pressure evaluation. Using this method, the average accuracy of pre-drilling formation pressure prediction was 87.1%. During actual drilling, based on logging and test data, prediction results were timely corrected, and the prediction accuracy of lower formation pressure was improved to 98.8%, meeting the requirements for drilling design and field construction.

Bozhong A oilfield is the first region in the Bohai Sea where deep metamorphic buried hills are covered by Mesozoic strata. Affected by multiple tectonic movements, the distribution of fractured reservoirs is complex. Accurately characterizing the fractured reservoir distribution and mitigating overall development risks are urgent issues. To address these challenges such as the complex distribution and unclear development models of fractured reservoirs, this study integrated logging and seismic data and incorporated key controlling factors such as weathering and paleogeomorphology. The buried hill reservoirs were vertically divided into three zones: a strongly weathered zone, a moderately weathered zone, and an inner zone, further revealing the distribution characteristics and development model of the buried hill reservoirs in the study area. The results showed that favorable reservoirs developed near long-active faults on the plane. Vertically, fractures exhibited zonal development. The upper strongly weathered zone developed network fractures and had relatively good lateral connectivity, forming a “quasi-layered” distribution pattern controlled by paleogeomorphology. The central moderately weathered zone, which had better lateral connectivity than the strongly weathered zone, developed both network and structural fractures. This zone was controlled by fold cores, faults, and paleogeomorphology, also showing a “quasi-layered” distribution pattern. The lower inner zone, which had poor lateral connectivity, developed structural fractures, forming a "funnel-shaped" distribution pattern controlled by fold cores and faults. To improve oil displacement efficiency and vertical sweep, this study analyzed the geological model of the buried hill and the distribution pattern of fractured reservoirs. Gas injection wells were deployed in the upper part of the hill, and oil production wells were placed in the middle and lower parts, following the principle of “prioritizing the moderately weathered zone, with supplementary development of favorable areas in the strongly weathered and inner zones”. This method provides a solid foundation for the development of the buried hill reservoirs in the region. By promoting integrated evaluation and construction, a synchronized model and workflow for deep buried hill exploration, evaluation, and pilot production were established. It facilitated the efficient development of newly discovered reserves, with three trial production wells near a high position producing an average of 300 tons of oil and gas equivalent per day. This achievement lays a foundation for mitigating regional risks and realizing rapid conversion of reserves to production. The research findings and practical experience provide valuable guidance and reference for the development of similar oilfields.