Search Results (57)

CCUS-EOR combines emission reduction with economic benefits, making it one of the key technologies for addressing global climate change. Addressing the lack of systematic comparative studies on the differences in geological endowments and engineering conditions between China and North America in existing literature, this paper systematically reviews the progress of North American CO₂-EOR in areas such as gas source structure transformation, capture technologies, and pipeline network construction, based on a self-constructed database of typical projects. It then conducts a quantitative comparative analysis of typical projects in China and the United States from three dimensions: reservoir geological endowment, gas source composition, and infrastructure. The study reveals that the advancement of U.S. CO₂-EOR projects benefits from increasing industrial CO₂ supply and the construction of cross-regional pipeline networks. Comparative analysis indicates that North American projects primarily feature miscible displacement in medium-to-low temperature and light oil reservoirs. This contrasts fundamentally with the characteristics of China’s continental reservoirs, which exhibit “strong heterogeneity, high viscosity, and high minimum miscibility pressure (MMP)”. Currently, China’s CCUS-EOR is transitioning from engineering demonstration to commercial application. However, gaps persist compared to more mature international systems in areas such as low-concentration CO₂ capture, pipeline network construction for source-sink matching, and suitability for continental reservoir EOR. Moving forward, China can draw on U.S. CCUS-EOR development experience, accelerate research on relevant technologies tailored to its continental reservoir characteristics, and establish a differentiated whole-industry-chain CCUS-EOR technology system. Full article

China possesses abundant tight conglomerate oil resources. However, these reservoirs are typically characterized by low porosity and permeability, high clay mineral content, and complex pore structures, resulting in poor performance of conventional waterflooding development. Challenges including insufficient energy replenishment and high flow resistance ultimately lead to low oil recovery factors. This study systematically investigates surfactant-assisted CO₂ huff-n-puff (SA-CO₂-HnP) for enhanced oil recovery in tight conglomerate reservoirs. For a tight conglomerate reservoir in a Xinjiang block, a fully implicit, multiphase, multicomponent dual-porosity numerical model was established. By integrating pore–throat distributions acquired through high-pressure mercury intrusion with a self-developed MATLAB PVT package, nanoconfinement-induced shifts in the phase envelope were rigorously embedded into the simulation framework. The calibrated model was subsequently employed to conduct a comprehensive sensitivity analysis, quantitatively delineating the influence of petrophysical, completion, and operational variables on production performance. Simulation results demonstrate that compared to conventional CO₂ huff-n-puff, the addition of surfactants increases the cumulative recovery factor by 3.5 percentage points over a 20-year production period. The enhancement mechanisms primarily include reducing CO₂–oil interfacial tension (IFT) and minimum miscibility pressure (MMP), improving reservoir wettability, and promoting CO₂ dissolution and diffusion in crude oil. Sensitivity analysis reveals that injection duration, injection pressure, and injection rate significantly influence recovery efficiency, while soaking time exhibits relatively limited impact. Moreover, an optimal surfactant concentration (0.0003 mole fraction) exists; excessive concentrations lead to diminished enhancement effects due to competitive adsorption and pore blockage. This study demonstrates that SA-CO₂-HnP technology offers favorable economic viability and operational feasibility, providing theoretical foundation and parameter optimization guidance for efficient tight conglomerate oil reservoir development. Full article

The integrated injection of low-salinity water (LSW) and carbon dioxide (CO₂) into the water-alternating-gas (WAG) process offers advantages, primarily increasing oil recovery and reducing operating costs. However, CO₂ has challenges in sweep efficiency due to significant differences in density and viscosity compared with oil. While LSW and dimethyl ether (DME) have shown promise in improving recovery through wettability alteration and reducing minimum miscible pressure, interfacial tension (IFT), and CO₂ mobility, their synergistic integration with CO₂-WAG remains poorly understood. Existing DME-based enhanced oil recovery (EOR) studies have not explored low-salinity water injection as a cost-effective alternative to mitigate high DME operating costs. This study introduces the CO₂/DME-LSWAG method, systematically evaluating the effect of DME concentrations (0%, 10%, 25%) and LSWs (seawater, twice-diluted seawater, ten-times-diluted seawater) on sweep and displacement efficiencies, oil recovery, and CO₂ storage in a 2D cross-sectional carbonate reservoir model. Results showed that DME dramatically reduces IFT (67% and 95% at 10% and 25% DME solvent, respectively) while salinity effects are relatively small. Compared with CO₂-LSWAG, the oil recovery factor improved by 5.2–13.1% depending on DME concentration and water salinity, with DME performance maximized at higher salinity water. CO₂ storage efficiency showed opposing trends. Structural trapping decreased, while solubility trapping increased with lower salinity. The sensitivity analysis identified DME concentration as the dominant factor for CO₂ storage. The composition modeling and simulation of the CO₂/DME-LSWAG process provide critical engineering guidance for the design of future EOR and CO₂ storage projects that utilize DME in carbonate reservoirs. Full article

In response to the development challenges caused by the high initial water saturation, low porosity, low permeability, and strong heterogeneity in C tight sandstone reservoirs, a comprehensive study was conducted on the optimization of development methods using a fuzzy model, core flooding experiments, and reservoir numerical simulations. The initial evaluation indicates the good adaptability of CO₂ flooding for improving oil recovery in a C reservoir; the experimental result of the CO₂ displacement method also performs the best, with a recovery rate of 68.38% at a connate water saturation of about 30%, compared with surfactant flooding and water flooding. However, higher water saturation inhibits the CO₂ development effect. The oil recovery factor of pure CO₂ huff-n-puff is 32.24% lower than the CO₂ displacement method, while surfactant-assisted CO₂ huff-n-puff can increase the recovery rate by 0.85% compared to pure CO₂. Based on actual geological models, numerical simulations were conducted on Well Block A and B. The results showed that the optimized production pressure is above the Minimum Miscibility Pressure (16.44 MPa); with consideration of the fracture pressure limitation, the CO₂ injection rate in Block A should be less than 3000 m³/d, and the recovery rate after 10 years is only 0.48% (oil change ratio is 0.07 t/t), while the CO₂ displacement rate of Block B should not exceed 7500 m³/d, and the recovery rate after 10 years can reach 27.39% (oil change ratio is 0.2 t/t). CO₂ displacement is an effective development method for a C reservoir, but due to a high water content the oil change ratio is very low, indicating a low potential for further development. The research provides important references for the development of similar oil reservoirs. Full article

This study investigates gas injection gravity miscible flooding to enhance oil recovery in fractured-vuggy volatile oil reservoirs of the Fuman area, Tarim Basin. The Fuman 210 reservoir, containing light oil with high maturity, large column heights, and strong fracture control, provides favorable conditions for gravity-driven flooding. Laboratory tests show that natural gas and CO₂ achieve miscibility, while N₂ reaches near-miscibility. Mixed gas injection, especially at a natural gas to nitrogen ratio of 1:4, effectively lowers minimum miscibility pressure and enhances displacement efficiency. Full-diameter core experiments confirm that miscibility improves oil washing and expands the sweep volume. Based on these results, a stepped three-dimensional well network was designed, integrating shallow injection with deep production. Optimal parameters were determined: injection rates of 50,000–100,000 m³/day per well and stage-specific injection–production ratios (1.2–1.5 early, 1.0–1.2 middle, 0.8–1.0 late). Field pilots validated the method, maintaining stable production for seven years and achieving a recovery factor of 30.03%. By contrast, conventional development relies on depletion and limited water flooding, and dry gas injection yields only 12.6%. Thus, the proposed approach improves recovery by 17.4 percentage points. The novelty of this work lies in establishing the feasibility of mixed nitrogen–natural gas miscible flooding for ultra-deep fault-controlled carbonate reservoirs and introducing an innovative stepped well network model. These findings provide new technical guidance for large-scale application in similar reservoirs. Full article

Oil and gas reservoirs dominated by coarse clastic rocks, particularly conglomerates (including gravel sandstones), are commonly termed conglomerate reservoirs in both the domestic and international literature. Sandy conglomerate reservoirs generally have high thickness and high productivity per unit area, but because of their characteristics such as rapid lithology change, strong heterogeneity, low porosity, and low permeability, it is difficult to develop conventional waterflooding. There is an urgent need for an efficient development scheme for the giant sandy conglomerate reservoir. In this study, nuclear magnetic resonance (NMR) technology was employed to investigate the stratified injection-production strategy for large-scale sandy conglomerate reservoirs. Three representative cores from different strata were selected to perform CO₂ flooding and CO₂-water alternating gas (WAG) flooding experiments, respectively. The aim was to explore how different development methods affect the recovery efficiency of various core types and the distribution of remaining oil under miscible and immiscible pressure conditions. The results show that immiscible CO₂ flooding mainly displaces crude oil in large pores, and oil in micropores and mesopores is difficult to displace. After gas channeling, there is still a large area of residual oil “aggregate” in the core, and the recovery rate is low. Compared with medium-coarse sandstone, the strong heterogeneity of sandy conglomerates leads to early gas breakthrough and low recovery efficiency during gas flooding. Compared with CO₂ flooding, CO₂-WAG flooding can balance the micro-oil displacement effect between micropores and macropores, significantly improve the oil production in micropores and mesopores. Thus, CO₂-WAG flooding has a certain micropore “profile control” effect, which can delay the gas channeling and improve the core recovery efficiency of reservoirs, especially for the highly heterogeneous sandstone. Miscible CO₂ flooding can effectively extract the oil in the mesopores and micropores that immiscible CO₂ flooding is difficult to displace. The gas breakthrough is slower and the recovery is much higher in miscible CO₂-WAG flooding than that of immiscible one. Therefore, ensuring that the formation pressure is higher than the minimum miscible pressure to achieve miscible flooding is the key to reservoir stimulation. Full article

CO₂ flooding has become a strategic tool for enhanced oil recovery and reservoir management in mature fields. This technique, however, is rarely utilized in asphaltenic crude oil systems, due to the likely occurrence of high asphaltene precipitation. The effect of asphaltene concentrations and CO₂ injection pressures has mostly been the focus of studies in determining asphaltene precipitation rates. However, asphaltene precipitation is not the only direct factor to be considered in predicting the extent of damage in an asphaltenic crude oil system. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection pressure at which asphaltene-induced formation damage can be avoided during both miscible and immiscible CO₂ flooding in an asphaltenic crude system. Simulation results indicate that asphaltene-induced permeability reduction exceeded 35% in most affected zones, with a corresponding drop in injectivity of 28%. Cumulative oil recovery improved by 19% compared to base cases without CO₂ injection, achieving peak recovery after approximately 4200 days of simulation time. As CO₂ was injected below the Minimum Miscibility Pressure (MMP) of 2079.2 psi, a significantly lower asphaltene precipitation was observed near the injector. This could be attributed to the stripping of lighter hydrocarbon components (C2–C7+) occurring in the transition zone at the gas–oil interface. Injecting CO₂ at pressures above the MMP resulted in precipitation occurring throughout the entire reservoir at 3200 psia and 1000 bbl/day injection rates. An increase in the injection rate at pressures above the MMP increased the rate of precipitation. However, a further increase in the injection rate from 1000 bbl/day to 4200 bbl/day resulted in a decrease in asphaltene deposition. The pressure drop in the water phase caused by pore throat increase demonstrated that water injection was effective in removing asphaltene deposits and restoring permeability. This work provides critical insights into optimizing CO₂ injection strategies to enhance oil recovery while minimizing asphaltene-induced formation damage in heavy oil reservoirs. Full article

CO₂-enhanced oil recovery (CO₂-EOR) has gained prominence as an effective oil displacement method with low carbon emissions, yet its microscopic mechanisms remain incompletely understood. This study introduces a novel high-pressure microfluidic visualization system capable of operating at 0.1–10 MPa without confining pressure and featuring stratified porous media with a 63 μm minimum throat size to provide unprecedented insights into CO₂ and CO₂-foam EOR processes at the microscale. Through quantitative image analysis and advanced machine learning modeling, we reveal that increasing the CO₂ injection pressure nonlinearly reduces residual oil saturation, achieving near-complete miscibility at 6 MPa with only 2% residual oil—a finding that challenges conventional thresholds for miscibility in heterogeneous systems. Our work uniquely demonstrates that CO₂-foam flooding not only mobilizes capillary-trapped oil films but also dynamically alters interfacial tension and the pore-scale fluid distribution, a phenomenon previously underexplored. Support Vector Regression (R² = 0.71) further uncovers a nonlinear relationship between the surfactant concentration and residual oil saturation, offering a data-driven framework for parameter optimization. These results advance our fundamental understanding by bridging microscale dynamics with field-applicable insights, while the integration of machine learning with microfluidics represents a methodological leap for EOR research. Full article

The shock absorbers in the landing gear absorb and dissipate a significant amount of kinetic energy generated from impacts during the landing and taxiing phases to ensure the stability and safety of the aircraft. The nitrogen–oil binary system is a commonly used energy absorption medium in these shock absorbers. Nevertheless, the interplay of interfacial mass transfer dynamics, microscopic dissolution behavior, and pressure drop in the aviation hydraulic oil–N₂ system under landing conditions necessitates further elucidation. Thus, we investigated the interfacial mass transfer characteristics of the oil–gas mixing process using molecular dynamics (MD) for analyzing the dissolution mechanism of N₂ in the aviation hydraulic oil system. The results show that as system pressure and temperature increase, the degree of oil–gas mixing intensifies. Under conditions of 373 K, 35 MPa and 433 K, 20 MPa, the diffusion coefficient, interfacial thickness, and system energy reach their maximum values. An increase in system pressure facilitates the occurrence of oil–gas mixing until the interface disappears at the minimum miscibility pressure (MMP), with the obtained MMP value being 107 MPa. Finally, the solubility of N₂ molecules in aviation hydraulic oil under different conditions was statistically analyzed, which is identified as the root cause of the pressure drop in the shock absorber’s gas chamber. This study innovatively applies molecular dynamics simulations to unveil, for the first time, the dissolution mechanism of N₂ in aviation hydraulic oil at the molecular scale, overcoming experimental limitations in observing extreme pressure–temperature conditions. This research elucidates the behavior of aviation hydraulic oil and N₂ under different thermodynamic conditions, making it easier to capture the patterns of phenomena that are difficult to observe in extreme environments. The research findings not only enhance the microscopic understanding of oil–gas mixing within the shock absorber but also provide valuable guidance for optimizing energy dissipation efficiency, improving damping characteristics, and enhancing safety in aircraft landing gear systems. Full article

CO₂ flooding technology for tight oil reservoirs not only effectively addresses the challenge of low recovery rates, but also facilitates geological CO₂ sequestration, thereby achieving the dual objective of enhanced CO₂ utilization and secure storage. However, in the development of continental sedimentary tight oil reservoirs, the high content of heavy hydrocarbons in crude oil leads to an elevated minimum miscibility pressure (MMP) between crude oil and CO₂, thereby limiting the process to non-miscible flooding. Conventional physical and chemical methods, although effective in reducing MMP, are often associated with high costs, environmental concerns, and limited efficacy. To address these challenges, we propose a novel approach utilizing petroleum hydrocarbon-degrading bacteria (PHDB) to biodegrade heavy hydrocarbons in crude oil. This method alters the composition of crude oil, thereby lowering the MMP during CO₂ flooding, facilitating the transition from non-miscible to miscible flooding, and enhancing oil recovery. Results demonstrated that, after 7 days of cultivation, the selected PHDB achieved a degradation efficiency of 56.4% in crude oil, significantly reducing the heavy hydrocarbon content. The relative content of light-saturated hydrocarbons increased by 15.6%, and the carbon atom molar percentage in crude oil decreased from C8 to C6. Following the biodegradation process, the MMP of the lightened crude oil was reduced by 20.9%. Core flood experiments indicated that CO₂ flooding enhanced by PHDB improved oil recovery by 17.7% compared to conventional CO₂ flooding. This research provides a novel technical approach for the green and cost-effective development of tight oil reservoirs with CO₂ immiscible flooding. Full article

This study evaluates the feasibility of CO₂ Water-Alternating-Gas (WAG) injection for enhanced oil recovery (EOR) in a highly heterogeneous reservoir using cost-effective and efficient tools. The Rule of Thumb method was initially used to screen the reservoir, confirming its suitability for CO₂-WAG injection. A fluid model was constructed by comparing several component lumping methods, selecting the approach with the least deviation from experimental data to ensure accuracy. The minimum miscibility pressure (MMP), a critical parameter for CO₂-EOR, was estimated using three methodologies: 1D simulation based on the slim tube test, semi-empirical analytical correlations, and fluid modeling. These techniques provided complementary insights into the reservoir’s miscibility conditions. The CO₂ Prophet software version 1 was employed to history-match production data and evaluate different development strategies. The Kinder Morgan CO₂ Scoping Model was used to perform production forecasting and assess the economic viability of implementing CO₂-WAG. Quantitative comparisons showed that the CO₂ Prophet version 1 model revealed minimal deviations from the history match results: oil production estimates differed by only 3.5%, and water production estimates differed by −4.11%. Cumulative oil recovery was projected to reach approximately 20.26 MMSTB over a 25-year production period. The results indicate that CO₂-WAG injection could enhance oil recovery significantly compared to water flooding while maintaining economic feasibility. This study demonstrates the practical integration of analytical tools and inexpensive models to evaluate and optimize CO₂-EOR strategies in complex reservoirs. The findings provide a systematic workflow for deploying CO₂-WAG in heterogeneous reservoirs, balancing technical and economic considerations. Full article

Gas miscible flooding, especially CO₂ miscible flooding, is a key method for enhanced oil recovery. However, the high Minimum Miscibility Pressure (MMP) often makes true-miscible flooding impractical. A number of studies confirm the existence of a near-miscible region that also ensures high recovery. However, the exact boundary for near miscibility remains unclear, with various speculative definitions based on experimental data or by experience. In this work, a molecular-level understanding of miscibility and near miscibility and the role of the MMP reducer are achieved using the molecular dynamics method. It is found that the traditional criterion of interfacial tension being zero is not valid for the molecular dynamics method, and that the interaction energy between oil molecules suggests distinct boundary between near-miscibility and miscibility regimes. MMP reducers were found to bring the two regions closer in terms of energy, rather than actually reducing the MMP. Full article

CO₂ is the main solvent used in enhanced oil recovery (EOR). However, its low density and viscosity compared to oil cause a decrease in sweep efficiency. Recently, dimethyl ether (DME), which is more efficient than CO₂, has been introduced into the process. DME improves oil recovery by reducing minimum miscible pressure (MMP), interfacial tension (IFT), and oil viscosity. Since DME is an expensive solvent, price reduction and appropriate injection scenarios are needed for economic feasibility. In this study, a compositional model was developed to inject DME with impure CO₂ streams, where the CO₂ was derived from one of these three purification methods: dehydration, double flash, and distillation. It was assumed that such a mixed solvent was injected into a heterogeneous reservoir where gravity override was maximized. As a result, lower oil recovery is achieved for the higher impurity content of the CO₂ stream, lower DME content, and more heterogeneous reservoir. When a high-purity CO₂ stream is used, the change in oil recovery according to DME content and heterogeneity of the reservoir is increased. When the lowest-purity CO₂ stream is used, the net present value (NPV) is the highest. For a homogeneous reservoir, the NPV is highest for all impure CO₂ streams. This optimization indicates a greater impact on revenue from reduced CO₂ purchase cost than on profit loss due to reduced oil recovery by impurities. Additional benefits can be expected when considering solvent reuse and carbon capture and storage (CCS) credits. Full article

This study presents a comparative analysis of CO₂-EOR and water flooding scenarios to optimize oil recovery in a geologically heterogeneous reservoir with a dome structure and partial aquifer support. Using production data from twelve production and three monitoring wells, a dynamic reservoir model was built and successfully history-matched with a 1% deviation from actual field data. Three main recovery methods were evaluated: water flooding, continuous CO₂ injection, and water-alternating-gas (WAG) injection. Water flooding resulted in a four-fold increase from primary recovery, while continuous CO₂ injection provided up to 40% additional oil recovery compared to water flooding. WAG injection further increased recovery by 20% following water flooding. The minimum miscibility pressure (MMP) was determined using a 1D slim-tube simulation to ensure effective CO₂ performance. A sensitivity analysis on CO₂/WAG ratios (1:1, 2:1, 3:1) revealed that continuous CO₂ injection, particularly in high permeability zones, offered the most efficient recovery. An economic evaluation indicated that the optimal development strategy is 15 years of water flooding followed by 15 years of continuous CO₂ injection, resulting in a net present value (NPV) of USD 1 billion. This study highlights the benefits of CO₂-EOR for maximizing oil recovery and suggests further work on hybrid EOR techniques and carbon sequestration in depleted reservoirs. Full article

Jimsar shale oil in China has undergone a rapid decline in formation energy and has a low recovery rate, with poor reservoir permeability. CO₂ injection has become the main method for improving oil recovery. Pre-fracturing with CO₂ energy storage in Jimsar shale oil has been performed, yielding a noticeable increase in oil recovery. However, the CO₂ injection mechanism still requires a deeper understanding. Focusing on Jimsar shale oil in China, this paper studies the effect of CO₂ on crude oil viscosity reduction, miscible phase testing, and the law of imbibition displacement. The results show that CO₂ has a significant viscosity reduction effect on Jimsar shale oil, with a minimum miscible pressure between CO₂ and Jimsar shale oil of 25.51 MPa, which can allow for miscibility under formation conditions. A rise in pressure increased the displacement capacity of supercritical CO₂, as well as the displacement volume of crude oil. However, the rate of increase gradually declined. This research provides a theoretical basis for CO₂ injection fracturing in Jimsar shale oil, which is helpful for improving the development effects of Jimsar shale oil. Full article