Search Results (32)

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

The existence of propane (C₃H₈) in a CO₂-oil mixture has great potential for increasing CO₂ solubility and decreasing minimum miscibility pressure (MMP). In this study, the enhanced solubility, reduced viscosity, and lowered MMP of CO₂-saturated crude oil in the presence of various amounts of C₃H₈ have been systematically examined at the reservoir conditions. Experimentally, a piston-equipped pressure/volume/temperature (PVT) cell is first validated by accurately reproducing the bubble-point pressures of the pure component of C₃H₈ at temperatures of 30, 40, and 50 °C with both continuous and stepwise depressurization methods. The validated cell is well utilized to measure the saturation pressures of the CO₂-C₃H₈-oil systems by identifying the turning point on a P-V diagram at a given temperature. Accordingly, the gas solubilities of a CO₂, C₃H₈, and CO₂-C₃H₈ mixture in crude oil at pressures up to 1600 psi and a temperature range of 25–50 °C are measured. In addition, the viscosity of gas-saturated crude oil in a single liquid phase is measured using an in-line viscometer, where the pressure is maintained to be higher than its saturation pressure. Theoretically, a modified Peng–Robinson equation of state (PR EOS) is utilized as the primary thermodynamic model in this work. The crude oil is characterized as both a single and multiple pseudo-component(s). An exponential distribution function, together with a logarithm-type lumping method, is applied to characterize the crude oil. Two linear binary interaction parameters (BIP) correlations have been developed for CO₂-oil binaries and C₃H₈-oil binaries to accurately reproduce the measured saturation pressures. Moreover, the MMPs of the CO₂-oil mixture in the presence and absence of C₃H₈ have been determined with the assistance of the tie-line method. It has been found that the developed mathematical model can accurately calculate the saturation pressures of C₃H₈ and/or CO₂-oil systems with an absolute average relative deviation (AARD) of 2.39% for 12 feed experiments. Compared to CO₂, it is demonstrated that C₃H₈ is more soluble in the crude oil at the given pressure and temperature. The viscosity of gas-saturated crude oil can decrease from 9.50 cP to 1.89 cP and the averaged MMP from 1490 psi to 1160 psi at 50 °C with the addition of an average 16.02 mol% C₃H₈ in the CO₂-oil mixture. Full article

The reservoir type of the MH oil field in the Junggar Basin is a typical low-permeability conglomerate reservoir. The MH oilfield was developed by water injection in the early stage. Nowadays, the reservoir damage is serious, and water injection is difficult. There is an urgent need to carry out conversion injection flooding research to improve oil recovery. The use of CO₂ oil-flooding technology can effectively supplement formation energy, reduce greenhouse gas emissions, and improve economic benefits. In order to clarify the feasibility of CO₂ flooding to improve oil recovery in conglomerate reservoirs with low permeability, strong water sensitivity, and severe heterogeneity, this paper researched the impact of CO₂ miscibility on production characteristics and mechanisms through multi-scale experiments. The aim was to determine the feasibility of using CO₂ flooding to enhance oil recovery. This study initially elucidated the oil displacement characteristics of varying degrees of miscibility in different dimensions using slim tube experiments and long core experiments. Subsequently, mechanistic research was conducted, focusing on the produced oil components, changes in interfacial tension, and conditions for pore mobilization. The results indicate that the minimum miscibility pressure (MMP) of the block is 24 MPa. Under the slim tube scale, the increase in the degree of miscibility can effectively delay the gas breakthrough time; under the core scale, once the pressure reaches the near mixing phase, the drive state can transition from a non-mixed “closed-seal” to a “mixed-phase” state. Compared to the immiscible phase, the near-miscible and completely miscible phase can improve the final recovery efficiency by 9.27% and 18.72%. The component differences in the displacement products are mainly concentrated in the high-yield stage and gas breakthrough stage. During the high-yield stage, an increase in miscibility leads to a higher proportion of heavy components in the produced material. Conversely, in the gas breakthrough stage, extraction increases as the level of mixing increases, demonstrating the distinct extracting characteristics of different degrees of mixed phases. The core experiences significant variations in oil saturation mostly during the pre-gas stage. CO₂ miscible flooding can effectively utilize crude oil in tiny and medium-sized pores during the middle stage of flooding, hence reducing the minimum threshold for pore utilization to 0.3 μm. Full article

CO₂ flooding is an economically feasible and preferred carbon capture, storage, and utilization technology. Asphaltene deposition is a common problem in the process of CO₂ injection because it may cause reservoir damage. The mechanism of asphaltene precipitation damage to the formation remains elusive. Experiments were conducted to reveal the pore-scale formation damage mechanism in ultra-low permeability reservoirs caused by asphaltene precipitation during CO₂ flooding. Initially, the precipitation onset point for asphaltene within the crude oil-CO₂ system was determined using a high-pressure tank equipped with visual capabilities. Subsequently, CO₂ flooding experiments were conducted on ultra-low permeability cores under miscible and immiscible conditions, with the support of nuclear magnetic resonance (NMR) to quantitatively evaluate the impact of asphaltene precipitation on ultra-low permeability reservoirs. The results indicate that within the pressure range from the asphaltene precipitation onset point to the minimum miscibility pressure (MMP). The level of asphaltene precipitation rises as CO₂ injection pressure increases. In the miscible flooding stage, asphaltene precipitation can still occur, but to a lesser extent. Notably, asphaltene deposition predominantly occurs in larger pores; above the MMP, the permeability decreases significantly as asphalt particles agglomerate, resulting in notable pore-throat blockages. While asphaltene deposition has a minimal impact on porosity, the bridging effect of asphaltene particles reduces permeability. Full article

This paper focuses on the current application of machine learning (ML) in enhanced oil recovery (EOR) through CO₂ injection, which exhibits promising economic and environmental benefits for climate-change mitigation strategies. Our comprehensive review explores the diverse use cases of ML techniques in CO₂-EOR, including aspects such as minimum miscible pressure (MMP) prediction, well location optimization, oil production and recovery factor prediction, multi-objective optimization, Pressure–Volume–Temperature (PVT) property estimation, Water Alternating Gas (WAG) analysis, and CO₂-foam EOR, from 101 reviewed papers. We catalog relative information, including the input parameters, objectives, data sources, train/test/validate information, results, evaluation, and rating score for each area based on criteria such as data quality, ML-building process, and the analysis of results. We also briefly summarized the benefits and limitations of ML methods in petroleum industry applications. Our detailed and extensive study could serve as an invaluable reference for employing ML techniques in the petroleum industry. Based on the review, we found that ML techniques offer great potential in solving problems in the majority of CO₂-EOR areas involving prediction and regression. With the generation of massive amounts of data in the everyday oil and gas industry, machine learning techniques can provide efficient and reliable preliminary results for the industry. Full article

This study focuses on the Bozhong 25-1 oilfield formation oil as the experimental subject, systematically investigating the influence of different slim tube lengths (1 m, 12.5 m, 20 m, and 25 m) on the minimum miscibility pressure (MMP) of the CO₂ and formation oil mixture system. Through slim tube experiments, the interaction process of CO₂ with formation oil in slim tubes of different lengths was simulated, with a particular focus on analyzing how changes in slim tube length affect the MMP. The experiments revealed an important phenomenon: as the slim tube length gradually increased from shorter dimensions, the MMP showed a decreasing trend; when the slim tube length reached 12.5 m, this trend stabilized, meaning that further increasing the slim tube length no longer led to significant changes in the MMP, with its stable value determined to be 27.86 MPa. This phenomenon can be explained within the theoretical framework of fluid dynamics and interfacial science, where several key factors play a significant role. Firstly, the flow characteristics of the fluid inside the slim tube significantly influence it; secondly, the interfacial tension between phases is also a decisive factor; lastly, the impact of the internal microstructure of the slim tube cannot be overlooked. These aspects together form the basis for understanding the impact of slim tube length on MMP and reveal the underlying mechanisms. This research is significant for deeply understanding and quantifying this effect, providing a solid theoretical basis for optimizing CO₂ flooding technology and guiding more precise operational strategies in oilfield development practices to enhance oil displacement efficiency and economic benefits. Full article

Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO₂ injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO₂ storage. Currently, limited research exists on advanced CO₂ injection and well pattern adjustment aimed at improving the oil recovery and CO₂ storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO₂ sequestration via advanced CO₂ injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO₂ storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO₂ injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO₂–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO₂ injection, advanced CO₂ injection can more effectively facilitate EOR and achieve CO₂ sequestration, with the recovery and CO₂ sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO₂ injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO₂ storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO₂ injection development in tight-oil reservoirs. Full article

This study investigated the impact of formation water on the mass transfer between CO₂ and crude oil in low-permeability reservoirs through CO₂ miscible flooding. Formation water leads to water blocks, which affect the effectiveness of CO₂ miscible flooding. Therefore, we studied the impact and mechanisms of formation water on the CO₂-oil miscibility. The microscale interaction between formation water-CO₂-core samples was investigated using CT scanning technology to analyze its influence on core permeability parameters. In addition, CO₂ miscible flooding experiments were conducted using the core displacement method to determine the effects of formation water salinity and average water saturation on minimum miscibility pressure (MMP) and oil displacement efficiency. The CT scanning results indicate that high-salinity formation water leads to a decrease in the porosity and permeability of the core as well as pore and throat sizes under miscible pressure conditions. The experimental results of CO₂ miscible flooding demonstrate that CO₂-oil MMP decreases as the salinity of the formation water increases. Moreover, as the average water saturation in the core increases, the water block effect strengthens, resulting in an increase in MMP. The recovery factors of cores with average water saturations of 30%, 45%, and 60% are 89.8%, 88.6%, and 87.5%, respectively, indicating that the water block effect lowers the oil displacement efficiency and miscibility. Full article

Natural gas injection is considered for enhanced oil recovery (EOR) in a high saturation pressure reservoir in block B111 of the Dagang oilfield, China. To investigate the interaction characteristics of injected natural gas and crude oil, the ability for dissolution–diffusion and miscibility–extraction of natural gas in crude oil was tested using a piece of high-temperature and high-pressure PVT equipment. The physical properties and minimum miscible pressure (MMP) of the natural gas–crude oil system and their interaction during dynamic displacement were analyzed using the reservoir numerical simulation method. The results show the following: (1) Under static gas–oil contact conditions, natural gas has a significant dissolution–diffusion and miscibility–extraction effect on the crude oil in block B111, especially near the gas–oil interface. The content of condensate oil in gas phase is 10.14–18.53 wt%, while the content of dissolved gas in oil phase reaches 26.17–57.73 wt%; (2) Under the reservoir’s conditions, the saturated solubility of natural gas injected in crude oil is relatively small. The effect of swelling and viscosity reduction on crude oil is limited. As the pressure increases with more natural gas dissolved in crude oil, the phase state of crude oil can change from liquid to gas; accordingly, the density and viscosity of crude oil will be greatly reduced, presenting the characteristics of condensate gas; (3) The MMP of natural gas and crude oil is estimated to be larger than 40 MPa. It mainly forms a forward-contact evaporative gas drive in block B111. The miscible state depends on the maintenance level of formation pressure. The injected natural gas has a significant extraction effect on the medium and light components of crude oil. The content of C2–C15 in the gas phase at the gas drive front, as well as the content of CH₄ and C16+ in the residual oil at the gas drive trailing edge, will increase markedly. Accordingly, the residual oil density and viscosity will also increase. These results have certain guiding significance for understanding gas flooding mechanisms and designing gas injection in block B111. Full article

The accurate determination of key parameters, including the CO₂-hydrocarbon solubility ratio (Rs), interfacial tension (IFT), and minimum miscibility pressure (MMP), is vital for the success of CO₂-enhanced oil recovery (CO₂-EOR) projects. This study presents a robust machine learning framework that leverages deep neural networks (MLP-Adam), support vector regression (SVR-RBF) and extreme gradient boosting (XGBoost) algorithms to obtained accurate predictions of these critical parameters. The models are developed and validated using a comprehensive database compiled from previously published studies. Additionally, an in-depth analysis of various factors influencing the Rs, IFT, and MMP is conducted to enhance our understanding of their impacts. Compared to existing correlations and alternative machine learning models, our proposed framework not only exhibits lower calculation errors but also provides enhanced insights into the relationships among the influencing factors. The performance evaluation of the models using statistical indicators revealed impressive coefficients of determination of unseen data (0.9807 for dead oil solubility, 0.9835 for live oil solubility, 0.9931 for CO₂-n-Alkane interfacial tension, and 0.9648 for minimum miscibility pressure). One notable advantage of our models is their ability to predict values while accommodating a wide range of inputs swiftly and accurately beyond the limitations of common correlations. The dataset employed in our study encompasses diverse data, spanning from heptane (C₇) to eicosane (C₂₀) in the IFT dataset, and MMP values ranging from 870 psi to 5500 psi, covering the entire application range of CO₂-EOR. This innovative and robust approach presents a powerful tool for predicting crucial parameters in CO₂-EOR projects, delivering superior accuracy, speed, and data diversity compared to those of the existing methods. Full article