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- 摘要：Ultra-low permeability high-pour-point reservoirs are characterized by high pour points, high viscosity, and high wax content. These "three-high" properties severely hinder fluid flow, result in low oil recovery efficiency, and lead to complex and heterogeneous residual oil distributions, posing significant challenges to enhancing recovery. To investigate the microscopic flow behavior of different displacement agents and their influence on residual oil distribution and occurrence patterns, this study employs a self-developed high-resolution microfluidic visualization system to conduct comparative experiments using three typical injectants: water, oxygen-reduced air, and CO2. By combining high-magnification metallographic microscopy with depth-of-field reconstruction techniques, multi-scale quasi-3D residual oil distribution images were obtained under various displacement conditions, enabling direct characterization of oil phase migration pathways, interfacial evolution processes, and residual oil occurrence states. Experimental results show that CO2 injection demonstrates the most favorable microscopic displacement performance. Its strong dissolution and swelling capacity, effective viscosity reduction, and ability to improve rock wettability significantly enhance oil desorption and mobilization. Oxygen-reduced air ranks second in effectiveness; its displacement efficiency is improved through a combined mechanism of gas expansion and low-temperature oxidation, which activates oil–rock interfaces and promotes oil phase movement. In contrast, waterflooding shows the lowest efficiency, with the displacement front constrained and residual oil primarily trapped in micropores and non-dominant flow channels, where it is discretely distributed and difficult to mobilize. Subsequent core-scale displacement experiments were conducted to verify the macroscopic cumulative effect of the observed microscopic mechanisms, confirming the intrinsic correlation between micro-scale displacement behavior and field-scale recovery performance. The study reveals the distinct displacement mechanisms of different injectants, clarifies the occurrence patterns of residual oil, and identifies key factors that control its distribution and mobilization. These findings provide experimental support and theoretical guidance for the selection of optimal displacement strategies and the design of injection parameters for the efficient development of high-pour-point reservoirs.关键词：high-pour point reservoir;microscopic visualization experiment;oil displacement mechanism of microscopic;residual oil distribution;superposition characteristics3|0|0更新时间：2026-05-15
- 摘要：To address the technical challenges encountered in drilling operations at the QY1 shale oil demonstration platform in the Qintong Sag of the Subei Basin, including complex reservoir lithology, prone borehole instability, narrow safe drilling density window, and low rate of penetration (ROP), this study developed a set of key supporting drilling technologies adapted to horizontal shale oil wells in the Qintong Sag through research on wellbore structure optimization, high-performance water-based drilling fluid development, precision managed pressure drilling (MPD), optimization of drilling speed-up tools, and drilling parameter optimization. Wellbore structure optimization was conducted. (1) A drilling mode of “three-spud system with technical casing set to the V sub-member of the second member of Funing Formation" was established to effectively seal the unstable formations. (2) Based on the principle of "internal swelling control and external water invasion prevention”, a high-performance water-based drilling fluid system SM-ShaleMud-II was developed, which significantly enhanced the inhibition, anti-collapse and plugging capabilities. (3) The second-generation modular precision managed pressure drilling technology was introduced, and a dual early-warning mechanism of “micro-flow monitoring + pressure derivative analysis” was constructed to achieve precise closed-loop control of wellbore pressure. (4) By optimizing the selection of drill bits and downhole tools, matching with drilling speed-up tools such as hydraulic oscillators and eccentric reamers for drilling, and combining the “four-high and one-low” design concept with the Real-Time Operation Center (RTOC) decision support system for petroleum engineering, the drilling parameters were further optimized. Field application results indicated that this supporting technology achieved remarkable outcomes in four wells of the QY1 platform. No borehole instability incidents occurred during the drilling process, and downhole complex faults were significantly reduced. The average horizontal section length reached 1 716.5 m, representing an increase of 233.55 m compared with the previous period. The average rate of penetration (ROP) increased to 15.83 m/h, an increase of 22.7% compared with the prior level. The average drilling cycle was shortened to 48.6 days, a substantial reduction from the approximately 120 days recorded previously. Specifically, for well QY1-1S03HF, the drilling cycle was only 40.25 days, and the ROP reached 18.44 m/h. This technology system has successfully realized the safe and efficient drilling of continental shale oil in the Qintong Sag, providing crucial technical support and practical reference for the large-scale and economical development of similar continental shale oil reservoirs in China.关键词：Qintong Sag;shale oil horizontal wells;wellbore stability;water-based drilling fluid;precision managed pressure0|0|0更新时间：2026-05-15
- 摘要：Continental shale oil resources in China are abundant and serve as a critical strategic alternative for ensuring national energy security. Shale oil reservoirs are characterized by well-developed nanopores and ultra-low porosity and permeability, where clarifying the imbibition mechanisms is of great significance for improving shale oil recovery efficiency. Taking laminated argillaceous calcareous shale from the Jiyang Depression as the research object, the pore structure characteristics were quantitatively evaluated using Focused Ion Beam-Scanning Electron Microscopy (FIB-SEM) three-dimensional imaging and digital core reconstruction methods. On this basis, high-temperature and high-pressure Nuclear Magnetic Resonance (NMR) dynamic imbibition experiments were conducted to simulate co-current imbibition during high-pressure injection of fracturing fluid. By acquiring transverse relaxation time (T2) spectra at different imbibition times, the mobilization characteristics of crude oil in pores of different scales were quantitatively analyzed. The T2 cutoff method was employed to distinguish the contributions of displacement and imbibition to oil recovery. Meanwhile, the effects of displacement pressure difference and bedding fractures on dynamic imbibition performance were analyzed. Based on similarity criteria, the relationship between laboratory scale and reservoir scale was established to calculate and determine the soaking time after hydraulic fracturing. The results show that: (1) The dynamic imbibition process can be divided into three stages—rapid imbibition, slow imbibition, and imbibition equilibrium, exhibiting a pattern of elastic oil displacement in large pores and imbibition-driven oil replacement in small pores. (2) An optimal displacement pressure difference range exists for dynamic imbibition (2.67–4.16 MPa). Compared with a low-pressure condition (1.05 MPa), the total recovery factor increases by 9.02%–10.26%. (3) Bedding fractures improve pore connectivity and increase imbibition efficiency, serving as favorable petrophysical conditions for enhancing shale oil mobilization. (4) Based on similarity criteria and dynamic imbibition experimental results, the optimal soaking time for shale oil reservoirs after hydraulic fracturing is determined to be 15 days.关键词：shale oil;NMR;dynamic imbibition;recovery degree;soaking time0|0|0更新时间：2026-05-15
- 摘要：The eastern China Cenozoic rifted lacustrine basins are important hydrocarbon-rich regions, with the Eocene shale (ca. 54-32 Ma) serving as a major reservoir. Although the depositional ages of these basins are similar, significant differences exist in lithofacies characteristics, lake water salinity, and organic matter abundance, and their formation mechanisms remain unclear. This study focuses on organic-rich shales from the Jiyang and Liaohe sags in the Bohai Bay Basin, the Jianghan Basin, and the Nanxiang Basin. Through integrated lithofacies classification, mineralogical, elemental, and isotopic analyses, the depositional environments and enrichment mechanisms of organic-rich shales were investigated. Results show that the intensified East Asian summer monsoon during the early Paleogene caused pronounced climatic fluctuations, with all basins reaching their maximum lake depth around 40 Ma. Cyclic changes in salinity under extreme heat led to the development of multiple mixed lithofacies, including laminated limestone/dolostone, calcareous–dolomitic mudstone, felsic shale, and calcareous/dolomitic mixed fine-grained rocks. The Liaohe Sag is characterized by muddy analcime microcrystalline dolostone, whereas the Jianghan Basin is dominated by dolostone–marly glauberite rocks. Overall, mineral compositions show a north-to-south increase in siliceous and calcareous contents. Paleoclimatic transitions controlled lake salinity and redox conditions: warm–humid climates enhanced bioproductivity, while high-salinity stratified waters strengthened reducing conditions and promoted organic matter preservation. The Jiyang Sag exhibits relatively high TOC contents (1.5–4.5%), while the Qianjiang and Liaohe sags show lower values (0–3%), indicating that saline–alkaline conditions were the dominant factor controlling organic matter enrichment.关键词：Salted lake basin;Mixed shale;Shale lithology;Organic matter enrichment;Eocene epoch0|0|0更新时间：2026-05-15
- 摘要：The estimated ultimate recovery (EUR) of shale gas wells is low because of rapid decline of rate, and it is necessary to study the influencing factors of production for shale gas wells. Therefore, the creep process of shale under viscoelastic characteristics is described firstly by Burgers model based on the rheological properties of shale rocks, and a method to modify shale matrix pore parameters including pore size, porosity and permeability is proposed by considering the definition of strain. Then, according to the gas flow characteristics in the shale reservoir fractured by horizontal well, a production prediction model of shale gas fractured horizontal well is further established by considering complex mechanisms such as rock creep based on the five-linear flow theory, and its production calculation process is proposed by comprehensively utilizing the production trial method and the Newton iteration method. Finally, the reliability of the model calculation results is verified by using the actual production data of shale gas wells, and the influence laws of various mechanisms on the production of gas wells are analyzed. The results indicate that viscoelastic characteristics should be considered for shale matrix because shale is a kind of soft rock, and it mainly undergoes steady creep during production, while linear elastic characteristics need to be mainly considered for fractures due to high-strength proppants maintained in these fractures. During production, the effects of adsorption, rock creep, micro-nano scale and stress sensitivity should be fully considered. Ignoring the adsorption effect and micro-nano scale effect will underestimate the production capacity of gas wells, while ignoring the rock creep effect and stress sensitivity effect will overestimate the production capacity of gas wells. Although the controlled pressure-drop production is lower than the aggressive production in the initial stage, it is gradually higher in the middle and later stages because controlled pressure-drop production reduces the adverse impact of reservoir stress sensitivity. Therefore, controlled pressure-drop production is superior to the aggressive pressure for shale gas wells. The research results can provide theoretical guidance for the effective development of shale gas.关键词：shale gas;production prediction;Creep;adsorption;stress sensitivity0|0|0更新时间：2026-05-15
- 摘要：The thick shale layers of the second member of the Funing Formation (hereafter referred to as Ef 2) in the Huazhuang area of the Gaoyou Sag, Subei Basin, are dissected by faults into multiple narrow fault blocks, forming a complex fault-block shale oil reservoir characterized by intensive fault development and narrow fault blocks. The shale of Ef 2 in the favorable Huazhuang area has an average burial depth of 3 800 m, where conventional seismic techniques fail to identify micro-faults with throws less than 30 m or quantitatively characterize fracture-developed zones. To address these challenges, this study innovatively integrated ant tracking, maximum likelihood attribute analysis, dispersion-based fracture prediction, and discrete fracture network (DFN) modeling to establish a multi-scale fault classification and quantitative fracture prediction method. Faults were classified based on fault throw and lateral extent. For micro-faults (throw ≤30 m), forward modeling combined with multi-attribute joint analysis (coherence, curvature, maximum likelihood, and ant tracking) identified key seismic indicators for micro-fault recognition in Ef 2. Ant tracking was found to provide the best performance for micro-fault detection, but it required constraints from regional fault characteristics to reduce uncertainties caused by steep formation dips and low signal-to-noise ratios. For natural fracture prediction, fracture-enhancing filtering and anisotropic diffusion filtering were applied to preprocess seismic data and improve data quality. DFN modeling was then used to characterize fracture occurrence and spatial distribution, providing a three-dimensional geological model for fracturing design and microseismic anomaly analysis. The results showed that the integrated fault classification and quantitative fracture prediction method effectively supported differentiated well-type deployment. Dynamic micro-fault identification and trajectory optimization were critical to ensuring a high “sweet spot” drilling encounter rate, exceeding 95%. Natural fracture models provided a scientific basis for the dynamic adjustment of fracturing parameters. Guided by these findings, multi-well-type shale oil well deployment in the Huazhuang area is optimized through geology-engineering integration of well trajectories and fracturing schemes, achieving a “sweet spot” drilling encounter rate greater than 95% in complex fault blocks, with single-well estimated ultimate recovery (EUR) exceeding 3 × 104 t, and significantly improving the exploration performance of fault-block shale oil wells.关键词：Gaoyou Sag;second member of Funing Formation;complex fault-block type;shale oil;micro-faults;fracture prediction0|0|0更新时间：2026-05-15
- 摘要：CO2 immiscible flooding technology in low-permeability reservoirs plays an important role in enhancing oil recovery and achieving carbon neutrality. This process involves solving strongly nonlinear equations, where traditional numerical simulation methods face challenges related to numerical stability and convergence, requiring fine tuning of temporal and spatial discretization steps. To address these issues, this study proposed a novel numerical simulation method based on physics-informed neural networks (PINNs) for CO2 immiscible flooding in low-permeability reservoirs. The proposed method was based on the classical Buckley-Leverett (BL) fractional flow equation, explicitly incorporating the coupled effects of threshold pressure gradient and CO2 solubility on displacement front propagation and saturation evolution. By embedding the BL equation and its initial and boundary conditions into the loss function of the PINNs, the neural network inherently satisfied the governing physical constraints during training. Meanwhile, it enabled the approximation modeling of complex nonlinear seepage processes in a mesh-free continuous space, thereby enhancing both numerical stability and predictive capability. To verify the accuracy of the proposed model, the numerical solutions obtained by PINNs were compared with analytical solutions. The results demonstrated that the constructed PINNs model exhibited high accuracy in capturing the position of the displacement front and the distribution of fluid saturation, with small differences from the analytical solutions, a coefficient of determination (R2) exceeding 93%, and a mean absolute error of 0.19×10-2. Compared with conventional explicit finite difference methods, the PINNs-based numerical simulation method exhibited stronger numerical stability and scalability. This study provides a new deep learning-based pathway for numerical simulation of CO2 immiscible flooding in low-permeability reservoirs. It contributes to a deeper understanding of seepage behavior mechanisms under multiphysics coupling, and provides theoretical support and methodological reference for the synergistic advancement of CO2 geological sequestration and enhanced oil recovery.关键词：physics-informed neural networks;low-permeability reservoirs;CO2 immiscible flooding;threshold pressure gradient;CO2 dissolution;Buckley-Leverett equation6|1|0更新时间：2026-05-12
- 摘要：In this study, the metamorphic buried hill reservoirs in the Bozhong 19-6 and Bozhong 13-2 tectonic areas of the Bohai Bay Basin were taken as the research object, and a targeted reservoir classification evaluation scheme was established, and the reservoir classification evaluation was carried out to guide the production practice. A total of five rock types were developed in the study area, including mixed granite, mixed gneiss, gneiss, metagranulite and fractured rocks, and the overall characteristics were medium and low porosity-low permeability. The reservoir space is dominated by secondary pores (intergranular/intragranular dissolution pores) and fractures (structural fractures, dissolution fractures, intergranular/intragranular microfractures), and the pore structure is complex and heterogeneous. Based on Gaussian curve fitting and multi-parameter collaborative analysis, a new classification system with porosity, permeability and crack density as the core indexes was proposed. The reservoirs are divided into three categories: I (high yield), II (relatively high yield) and III (low yield), and each type is further subdivided into fracture-pore type and fracture subclass, and its physical property boundaries are clarified. The lithology of Class I reservoirs is mainly developed in the weathered conglomerate zone, the inner fracture section of the weathering leaching zone with superimposed fragmentation sections, and the dense fracture zone with thick layers (greater than 40 m) of the weathering disintegration zone with superimposed fragmentation sections, and the reservoir space is dominated by intergranular dissolution, intragranular dissolution holes, large-scale structural fractures, and dissolution expansion fractures, with deep lateral resistivity generally lower than 700 Ω·m, and acoustic time difference generally greater than 53 μs/m. Class II reservoirs are mainly developed in the inner fragmentation section of the weathering and leaching zone and the medium-thick (20~40 m) fracture dense zone of the weathering disintegration zone, and the reservoir space is dominated by intragranular dissolution holes, small-scale structural fractures and dissolution fractures, and the deep lateral resistivity is generally lower than 1 000 Ω·m and the highest can be 2 500 Ω·m, and the acoustic time difference is generally less than 60 μs/m. Type III. reservoirs are mainly developed in the inner fragmentation section with very weak dissolution and the fracture dense zone with a thickness of less than 20 m, and the reservoir space is dominated by dissolved micropores, intragranular microfractures and intergranular microfractures, and the deep lateral resistivity is distributed at 1 500~15 000 Ω·m, and the acoustic time difference is generally less than 57 μs/m.关键词：Bozhong Sag;Archean metamorphic buried hill;Gaussian curve fitting;reservoir characteristics;reservoir classification evaluation7|2|0更新时间：2026-05-11
- 摘要：Shale oil reservoirs are widely developed with nanoscale pores, in which strong confinement effects cause the fluid phase behavior to deviate significantly from bulk conditions, making conventional theories difficult to apply to shale oil reservoirs. To investigate the phase behavior of confined fluids, dew point experiments were conducted using micro–nanofluidic techniques in 10 μm and 100 nm pores, and the condensation process and the liquid distribution within confined pores were systematically observed. Experimental results indicate that the condensation mechanisms in both pore sizes involve the formation and growth of liquid films or bridges, which eventually evolve into liquid columns. However, pore size exerts a pronounced influence on condensation dynamics and liquid distribution. In 10 μm pores, condensation preferentially initiates at pore corners, but the final liquid fraction remains relatively low. In contrast, in 100 nm pores, condensation is no longer restricted to the corners and tends to occur near the inlet, with a significant increase in liquid accumulation and a more uniform distribution. A comparison between the measured dew point pressures and the predictions from the Peng-Robinson equation of state reveals the limitations of conventional models in describing confined phase behavior at the nanoscale. To accurately predict the phase behavior of confined fluids, a modified prediction model was developed based on the Peng–Robinson equation of state by incorporating capillary pressure, adsorption effect, and critical point shift. The modified model achieves accurate characterization of confined fluid phase behavior, with a maximum relative error of 5.30%. Further analysis reveals that confinement effects are most pronounced under low-temperature and low-pressure conditions, but tend to weaken as the temperature increases. This study integrates theoretical modeling and experimental validation, providing experimental evidence and theoretical references for describing phase equilibrium in nanopores and offering new insights for phase behavior prediction in shale oil reservoirs.关键词：Shale oil reservoirs;confinement effects;fluid phase behavior;Peng-Robinson equation of state;micro-nanofluidic experiments4|0|0更新时间：2026-05-11
- 摘要：Deep coal-rock gas has become an important target for increasing natural gas reserves and production in China. Field practice indicates that there is a clear relationship between the production rate of deep coal-rock gas in the Daning–Jixian area and the economically recoverable reserves (EUR) controlled by gas wells. However, existing stress-sensitivity relationships for coal rock fail to effectively capture this phenomenon, particularly the differentiated response of permeability to stress paths, i.e., different pressure-decline rates. In this study, the pore pressure variation process was simulated to investigate the influence of stress paths on permeability stress sensitivity, with a specific focus on the relationship between pore pressure decline rate and permeability during pressure depletion. The permeability evolution of coal-rock reservoirs under different stress conditions was systematically analyzed. Permeability experiments were conducted using a pulse-decay method for unconventional reservoir cores. By adjusting the average pressures of the upstream and downstream reference chambers, different pore pressure decline rates (stress paths) were simulated. Four core samples from the No. 8 coal seam of the Baode Mine were tested to examine permeability evolution and its irreversibility under different pressure-decline paths. The results show that, as pore pressure decreases, the matrix permeability of coal rock generally exhibits an exponential decline, characterized by a rapid decrease at the early stage followed by a slower decline at later stages. Normalized analysis indicates that permeability recovery during unloading is limited and fails to return to its initial value; moreover, the permeability reduction during unloading is smaller than that during loading, demonstrating a pronounced hysteresis effect. Regression analysis of pressure-decline rate versus permeability change rate reveals that, for every 1 MPa/d increase in pore pressure decline rate, the permeability stress-sensitivity degree increases by an average of 0.28%, indicating a differentiated stress-sensitive response of coal permeability under different loading rates. Field statistical observations further confirm the sensitivity of coal-rock permeability to the pore pressure decline rate.关键词：deep coal-rock gas;matrix permeability;stress sensitivity;pressure drop rate;plastic deformation38|10|0更新时间：2026-04-23
- 摘要：CO2-enhanced shale gas recovery (CO2-ESGR) is a promising carbon capture, utilization, and storage (CCUS) technology that simultaneously improves shale gas production and enables geological CO2 sequestration, contributing to carbon neutrality. The adsorption behaviors of CH4 and CO2 in shale are critical factors controlling the efficiency of CO₂-ESGR. In this study, experimental data on CH4-CO2 adsorption in shale samples from major shale-gas-rich regions in China were compiled to establish a comprehensive database. The effects of total organic carbon (TOC), clay content, specific surface area, temperature, pressure, and CO2 fraction on adsorption behavior were systematically considered. Several machine-learning models, including back-propagation neural network, K-nearest-neighbor regression, random forest regression, and support vector machine regression, were developed to predict CH4-CO2 adsorption capacities and to investigate competitive adsorption in mixed-gas systems. Model performance was evaluated by comparison with published data, experimental measurements, and Langmuir model predictions. The results indicate that the random forest regression model achieves the highest prediction accuracy and strong generalization ability. Within the pressure range of 0-15 MPa, the model yields an average absolute relative deviation of 1.57%-1.94% and an R2 value of 0.99 for both single-component and mixed-gas systems. These results demonstrate that the proposed machine-learning model can reliably predict CH4-CO2 adsorption and competitive adsorption behaviors in shale, providing theoretical support for CO2-ESGR applications.关键词：shale;CH4-CO2;adsorption;competitive adsorption;machine learning33|2|0更新时间：2026-04-23
- 摘要：Aquifer thermal energy storage technology is an emerging and viable multi-energy complementary solution, with its core principle being the storage of highly variable renewable energy sources (such as solar and wind energy) in underground aquifers in thermal form, enabling stable extraction and utilization when needed to achieve multi-energy complementary storage based on geothermal reservoirs. The thermal equilibrium distance is a key parameter for determining the well spacing in this system, representing the minimum distance required for the temperature fluctuation amplitude of injected fluids to reduce to an acceptable range while flowing through the aquifer under specific operating conditions. To reveal the influencing mechanisms of thermal equilibrium distance, a three-dimensional aquifer model incorporating thermo-hydraulic coupling was constructed. The study focused on analyzing the impact of operational parameters (injection temperature and injection rate), formation properties (permeability and porosity), and rock thermophysical properties (volumetric heat capacity and thermal conductivity) on thermal equilibrium distance. Multivariate linear regression analysis was employed to rank the sensitivity of each parameter and identify the primary influencing factors. The results indicate that thermal equilibrium distance is positively correlated with injection temperature, injection rate, permeability, and rock thermal conductivity, while negatively correlated with porosity and volumetric heat capacity. The three dominant factors influencing thermal equilibrium distance are permeability, injection rate, and injection temperature, with their sensitivity ranking as permeability > injection rate > injection temperature. Notably, operational parameters account for a relatively high proportion among the dominant factors, suggesting that optimizing injection-production strategies and wellfield layouts can effectively enhance the thermal storage efficiency and economic viability of the system. These findings provide quantitative basis for well placement and operational strategies in "geothermal+" multi-energy complementary systems, offering technical support for renewable energy utilization.关键词：aquifer energy storage;thermal equilibrium distance;multi energy complementary system;Tthermo-hydraulic coupling;sensitivity analysis29|2|0更新时间：2026-04-21
- 摘要：The development of low-rank coalbed methane in the Fukang Block of Xinjiang has entered a bottleneck stage, necessitating an urgent enhancement and acceleration of exploration and exploitation initiatives. However, the inefficient methane desorption process within the microscopic pores of low-rank coal, combined with poorly understood adsorption and desorption mechanisms, has resulted in challenges such as low initial production rates, short durations of stable production, and suboptimal development performance in newly commissioned coalbed methane wells. To address challenges such as low recovery rates and the difficulty in mobilizing adsorbed-phase methane, low-rank coal from the Fukang block was selected as the study subject. The coal’s pore size distribution, molecular formula (C100H108O16N3) and molecular structure were characterized using elemental analysis, Low-temperature N2 adsorption, XRD, FT-IR, and 13C-NMR, enabling the construction of a slit-shaped pore model. Adsorption behavior under varying slit widths, pressures, and temperatures was simulated via the grand canonical Monte Carlo (GCMC) method, and a non-isothermal Langmuir equation was fitted to describe methane adsorption in the Fukang coal. Subsequently, isothermal depressurization desorption processes were analyzed using molecular dynamics simulations based on adsorbed methane configurations in slit pores at 10 MPa and 308 K. Key findings include: (1) The dominant molecular architecture of Fukang low-rank coal consists of aliphatic chains linking aromatic rings (benzene/naphthalene), functionalized with carboxyl, hydroxyl, and pyrrole groups; (2) At slit widths below 2 nm, strong nano-confinement deepens the adsorption potential well, leading to a “single-peak” methane density distribution, with micropore filling as the primary storage mechanism; above 2 nm, the density profile transitions to a “double-peak” pattern accompanied by a non-adsorption zone, indicating a shift toward surface-dominated adsorption; (3) Under high-pressure conditions, elevated temperature reduces adsorption potential energy, thereby promoting methane desorption—this effect is more pronounced in pores >2 nm, where both micropore filling and surface adsorption co-dominate, the central region of the slit still exhibits adsorbed methane; (4) In narrow slit (1 nm), high desorption energy barriers and low diffusion coefficients (0.075 Å2/ps) lead to significant desorption hysteresis, whereas wider slit (3 nm) exhibit lower energy barriers and higher diffusivity (0.647 Å2/ps), eliminating hysteresis. In conclusion, reducing the adsorption/desorption energy barrier in low-rank coal micropores is crucial for enhancing methane desorption efficiency and diffusivity. A synergistic strategy combining depressurization, aperture expansion, and thermal stimulation—implemented through pre-injected CO₂ combined with self-heating fracturing fluids, followed by well-pattern thermal fluid displacement—represents a promising pathway for improving recovery rates in low-rank coalbed methane reservoirs in the Fukang block.关键词：Fukang block;low-rank coal;coalbed methane;adsorption and desorption;molecular simulation;micropore filling72|98|0更新时间：2026-04-10
- 摘要：CO2 foam can effectively reduce gas mobility and improve oil displacement system sweep efficiency, but the presence of oil phase will have a significant impact on the formation and stability of foam and the control of gas mobility in porous media. Therefore, it is very important to understand the interaction between foam and oil phase in porous media. This study systematically studied the effects of foam quality (fg) on its steady-state transport behavior, the effects of oil phase composition on foam strength, and the effects of foam generation mode (in-situ generated foam, pre-generated foam) on miscible flooding efficiency through supercritical CO2 foam steady-state flow experiments and core displacement experiments. The results show that the apparent viscosity of supercritical CO2 foam increases first and then decreases with the increase of foam quality. In the core with a permeability of approximately 28×10-3 μm2, the optimal foam quality is about 0.75, and the foam system shows the best mobility control ability. The oil phase composition significantly affects the foam strength. Compared with n-decane (C10), in the process of displacing hexadecane (C16), the apparent viscosity and pressure difference of foam are larger, the gas breakthrough time is lagging behind, the foam strength is larger, and the recovery rate is higher during displacement. In addition, the foam generation mode has an important influence on the efficiency of miscible flooding. Whether it is displacing C10 or C16, the recovery rate of in-situ generated foam is higher than that of pre-generated foam. The specific data show that the recovery rates of in-situ generated foam flooding C10 and C16 are 17.78% and 30.91%, respectively, while the recovery rates of pre-generated foam under the same conditions are 15.91% and 20.83%, respectively. This study clarifies the optimal foam injection quality and provides a direct basis for the optimization of field process parameters. At the same time, it clarifies the influence of oil phase composition and foam generation mode on CO2 foam performance and oil flooding efficiency, which lays a theoretical foundation for reservoir adaptability evaluation and injection process optimization.关键词：mobility control;oil phase composition;foam generation mode;supercritical CO2 foam;the steady-state transport characteristics;miscible flooding behavior94|37|0更新时间：2026-04-02
- 摘要：Saline lacustrine basin shale oil, as an important type of continental shale oil and gas resources, undergoes hydrocarbon generation processes regulated by multiple factors including sedimentation and diagenesis, exhibiting significant complexity and heterogeneity. Based on a systematic investigation of geological characteristics of shales from typical saline lacustrine basins in China, combined with the application results of experimental techniques such as closed-system MSSV (Microscale Sealed Vessel pyrolysis), semi-open-system hot-press simulation, and organic sulfur analysis, this study comprehensively explores the genetic mechanism of differential hydrocarbon generation in shales from Chinese saline lacustrine basins. The results indicate that saline lacustrine basin shales feature diverse lithofacies and organic facies with strong heterogeneity, and the main source rock sequences generally possess medium-to-high organic matter abundance, kerogen predominantly of Type Ⅰ-Ⅱ₂, and a thermal evolution degree ranging from 0.7% to 1.3% Ro. The hydrocarbon generation process of some typical shales presents distinct "double-peak oil generation" differentiation characteristics: shales in sulfate-type lacustrine basins exhibit a "low-mature oil-mature oil" double peak, while those in alkaline carbonate-type lacustrine basins are characterized by a "mature oil-high-mature oil" double peak. Organic sulfur reduces the hydrocarbon generation activation energy of kerogen through forming low-bond-energy C-S structures, thereby advancing the hydrocarbon generation threshold. Salt minerals, clay minerals, volcanic minerals, and alkaline minerals regulate the hydrocarbon generation pathways and product composition through organic-inorganic interactions such as catalytic reactions, hydrogen supply, and saponification reactions. Through the innovation of experimental techniques and the deepening of genetic mechanisms, dynamic simulation of hydrocarbon generation from microscopic compounds to macroscopic geological processes has been realized, providing key technical support for hydrocarbon generation kinetic modeling, resource potential evaluation, and "sweet spot" interval prediction of saline lacustrine basin shales. This study is of great significance for improving the theory of continental shale hydrocarbon generation and guiding the efficient exploration and development of continental shale oil and gas..关键词：shale oil;hydrocarbon generation mechanism;experimental techniques;organic sulfur;organic-inorganic interactions84|179|0更新时间：2026-03-31
- 摘要：The second section of the Xujiahe Formation in western Sichuan has abundant natural gas resources in the deep tight sandstone, but the low exploration rate, low utilization rate, and difficulty in upgrading of reserves have always been challenges for exploration and development in the region. The unclear distribution pattern and genesis of gas and water in both horizontal and vertical directions have hindered further understanding of gas reservoirs and drilling deployment research. To solve the dilemma of gas reservoir evaluation brought about by the complex distribution of gas and water, and effectively promote exploration and development deployment, based on actual drilling, logging, testing data and natural gas and core analysis and laboratory data, this study analyzed the characteristics of natural gas enrichment and production under different combinations of geological elements from macro and micro scales, plane and vertical dimensions, and the original state of gas reservoirs and actual drilling conditions. The differences in gas and water occurrence and electrical response in different depths of fracture development were sorted out, and the principles and methods for identifying gas and water in tight fractured reservoirs under wellbore conditions were summarized. Research has shown that: ①Macroscopically, the spatiotemporal coupling of the hydrocarbon source reservoir transport system controls the vertical and horizontal distribution of gas and water, with the scale and formation period of faults being key factors affecting gas and water distribution; ②At the micro level, small-scale fractures and microcracks control the filling behavior of natural gas. High maturity gas is difficult to achieve long-distance vertical and horizontal migration in matrix reservoirs. The depth range of fracture development has significantly higher gas saturation and natural gas maturity compared to adjacent matrix segments; ③Under actual drilling conditions, the deep invasion of mud filtrate significantly reduces the identification of gas and water layer resistivity in the fracture development depth range, which is an ideal target area for gas bearing identification. The new method, which uses gas logging C1/C2 as the key means and characterizes the rhythmic changes of natural gas maturity in different fracture development stages, effectively improves the gas water identification ability of tight reservoirs; ④The results of single well gas water identification show that in early fault controlled areas, the height of gas columns is usually less than 100m and the planar distribution radius of fault transmission conductors is small, while in late fault controlled areas, the height of gas columns and the planar distribution radius of fault transmission conductors are usually larger and related to the size of the fault. Under the guidance of the fluid identification methods and gas water distribution laws mentioned above, drilling deployment was carried out, and general principles for designing drilling trajectories and selecting test layers for target layers were established. Multiple new drilling wells achieved good oil and gas results, which strongly supported the high-quality exploration and development of deep tight sandstone in the second section of the Xujiahe Formation in western Sichuan.关键词：gas water distribution;transporting gas reservoir;cracks;gas maturity level;Western Sichuan Depression;second section of Xujiahe Formation40|127|0更新时间：2026-03-31
- 摘要：The potential of deep shale gas resources in the Sichuan Basin is huge, but due to its deep burial depth, the pressure-holding coring technology is difficult and costly. Therefore, how to accurately recover and evaluate the in-situ gas content through numerical simulation or experimental methods has become a key issue in the industry. Based on Nuclear Magnetic Resonance (NMR) isothermal adsorption data, this study employs adsorption potential theory to derive adsorption curves at various temperatures and establishes a prediction model for adsorbed gas under variable temperature and pressure conditions. Additionally, a free gas prediction model is developed using NMR free gas data and the equation of state. These models enable the analysis of adsorbed and free gas, as well as the prediction of in-situ gas content in the study area. Experimental results reveal comparable in-situ gas content between siliceous shales (6.2 cm³/g) and mixed siliceous shales (5.9 cm³/g), with statistically insignificant differences. Notably distinct gas phase partitioning is observed across lithologies, with free gas consistently predominating over adsorbed gas at ratios of 3:7 in siliceous shales and 4:6 in mixed siliceous shales, which reveals the differential control of lithology on the distribution of occurrence state. This difference in phase distribution is mainly related to clay mineral content and water saturation. In the deep high-pressure environment, although free gas is dominant, clay minerals play a key ' lock gas ' role, and water saturation is the ' short board ' of free gas enrichment. By changing the temperature and pressure gradient on the basis of the model, the temperature and pressure response characteristics of shale gas occurrence are revealed: the adsorbed methane has the conversion of the main controlling factors of temperature and pressure in the deep and shallow parts, and the favorable geological conditions for its occurrence are high pressure and low temperature conditions; free methane is mainly controlled by pressure, and the high pressure environment of deep shale in the study area is conducive to the occurrence of free methane.关键词：Sichuan Basin;Longmaxi Formation shale;adsorption potential theory;adsorption gas prediction model;free gas prediction model37|64|0更新时间：2026-03-30
- 摘要：The G Oilfield in the Ordos Basin has entered the middle to late stages of development and is confronted with the challenge of production decline due to depleted reservoir energy. Fracturing stimulation combined with water injection for energy replenishment is a commonly used production enhancement strategy. However, parameter mismatch in fracturing-induced energy storage within this oilfield often leads to water channeling and premature water breakthrough in adjacent wells, severely constraining development effectiveness. To address this issue, this study focuses on the integrated optimization of fracturing-induced energy storage parameters for the G Oilfield. Firstly, a geological model of a representative well group was established using the CMG numerical simulation software, and the mechanism of water injection for energy storage was thoroughly analyzed. Subsequently, the single-factor analysis method was employed to systematically identify key control parameters significantly impacting the 1 000-day cumulative oil production, including fracture-length ratio, fracture conductivity, injection intensity, daily injection volume, and well soaking time. Following this, the Response Surface Methodology was applied to construct a high-precision predictive model between these key parameters and the 1 000-day cumulative oil production. The reliability of the model was verified through residual analysis and numerical simulation validation. Finally, the Comprehensive Learning Particle Swarm Optimization algorithm was introduced to perform iterative optimization of the identified key parameters, with the objective of maximizing cumulative oil production. The application of this integrated optimization strategy significantly enhanced the development outcomes. The optimized scheme increased the 1000-day cumulative oil production by 5.98% compared to the simulation results under parameters optimized solely by the Response Surface Methodology. The study successfully determined the optimal parameter combination suitable for fracturing-induced energy storage in the G Oilfield. The results demonstrate that the integrated optimization method, combining single-factor analysis, Response Surface Methodology, and the intelligent optimization algorithm, effectively resolved the inefficient production problem caused by parameter mismatch in fracturing-induced energy storage, significantly improving crude oil production. The integrated optimization strategy proposed in this study provides a systematic and feasible technical solution for addressing common issues in low-pressure coefficient reservoirs, such as insufficient natural productivity and difficulties in enhancing development. It holds significant application value for the Ordos Basin and similar reservoirs.关键词：CLPSO;Energy Replenishment;fracturing;Process Parameter Optimization;RSM42|49|0更新时间：2026-03-27
- 摘要：To reveal the influence of water on the CO2-ECBM (CO2-replacement of CH4) effect in deep coal seams, using Fuchang deep coal as the research object, experiments such as 13C nuclear magnetic resonance spectroscopy (13C-NMR) and X-ray photoelectron spectroscopy (XPS) were conducted. A coal matrix model was constructed using molecular simulation software, and the microscopic mechanism of water’s effect on the CO2-ECBM process in deep coal seams was studied using molecular simulation methods. The results show that after the coal matrix adsorbs gas, it undergoes significant expansion, and the pore volume significantly decreases. When saturated with adsorbed CH4, the coal matrix porosity decreases by 72.2% compared to the initial value; when the molar fraction ratio of CO2 to CH4 (
- 摘要：Ultra-deep pore-fracture-fault complex condensate gas reservoirs exhibit highly heterogeneous fluid flow behaviors. During production, the fracture system often experiences locally reduced pressure, leading to retrograde condensation, while the matrix pressure and overall reservoir pressure remain above the dew-point pressure. This discrepancy makes it difficult for traditional gas reservoir engineering methods—typically based on average reservoir pressure—to accurately identify the onset and extent of local retrograde condensation. To address this issue, this study investigates the Bozi condensate gas reservoir located in the Kuqa Depression of the northern Tarim Basin. The flow mechanism and pressure response characteristics of the pore-fracture-fault triple-medium system are systematically analyzed. Based on the variation patterns of wellhead oil pressure, the production process is divided into three distinct stages: a steady-decline period, an unstable-fluctuation period, and an accelerated-decline period. Abnormal fluctuations in the gas-oil ratio (GOR) are interpreted as early indicators of phase change. By examining GOR variations across different pressure intervals, this work characterizes the dynamic evolution of complex medium gas reservoirs at various production stages. A hybrid predictive framework is proposed that integrates the Long Short-Term Memory (LSTM) network and the Temporal Convolutional Network (TCN), whose hyperparameters are globally optimized using the Pelican Optimization Algorithm (POA). A weighted fusion strategy is employed to construct the POA-LSTM-TCN combined model, enabling stage-wise fitting and prediction of GOR. The results demonstrate that the optimized POA-LSTM and POA-TCN models achieve mean absolute percentage errors (MAPE) of 3.71% and 7.73%, respectively, whereas the POA-LSTM-TCN hybrid model achieves a significantly lower MAPE of 2.40%, outperforming the single models by 1.31% and 5.33%. Numerical simulation further verifies that the traditional gas reservoir engineering approach based on average pressure fails to effectively capture retrograde condensation occurring within fractures. In contrast, the POA-LSTM-TCN model not only provides high-accuracy and efficient GOR prediction but also identifies retrograde condensation when deviations exceed the prdefined threshold. Therefore, this study overcomes the limitations of conventional engineering methods in detecting local retrograde condensation and establishes an early-warning approach based on anomaly recognition. The findings hold substantial theoretical and practical significance for production dynamics analysis, retrograde condensation mechanism identification, and development optimization of complex condensate gas reservoirs.关键词：Tarim Basin;Bozi Gas Reservoir;complex media;condensate gas reservoir;gas-oil ratio;anti-condensate;neural network43|172|0更新时间：2026-03-24
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