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- 摘要：Accurate evaluation of geological reserves is a core prerequisite for understanding the development potential of shale oil reservoirs and formulating scientific development plans. Aiming at the problems of strong heterogeneity of shale oil reservoirs, prominent non-uniqueness of parameter prediction, conventional volumetric method masking reservoir heterogeneity, traditional probabilistic method underestimating the inherent correlation of parameters, and difficulty in accurately quantifying reserve scale and uncertainty, this study takes the QY1 shale oil well group in the Second Member of Funing Formation, Qintong Sag, Subei Basin as the research object, adopts a stochastic modeling approach to conduct a systematic analysis of the entire reserve evaluation process, and focuses on completing the identification of sensitive factors, formulation of desensitization countermeasures, and application of reserve evaluation. The results show that: depth deviation in seismic interpretation, primary and secondary range parameters of porosity and oil saturation modeling, and model grid cell step size are medium-to-high sensitive factors affecting reserve uncertainty, with their relative impact on reserves ranging from 4.1 to 12.2%; through three major desensitization countermeasures — constrained data mining in structural modeling, facies-controlled constraint in property modeling, and optimization of model grid step size — the relative impact of medium-to-high sensitive factors on reserves can be reduced to 2.4% to 3.5%; after desensitization, the value range of evaluated reserve distribution narrows by 38.5%, the slope of the cumulative probability curve increases by 114.7%, uncertainty decreases by 10.7%, and reserve prediction accuracy is significantly improved. Based on the desensitized stochastic modeling method, the quantitative evaluation of reserves by formation in the well group was further completed, confirming that the interval from Lower Member Ⅰ to Upper Member Ⅱ is the core area of reserve distribution, followed by Member Ⅲ, and Submembers Ⅳ to Ⅴ with extremely low abundance; combined with the relationship between P50 reserve abundance and single-well internal rate of return, suggestions for optimization of well spacing by formation and improvement of reservoir stimulation were proposed.关键词：stochastic modeling;shale oil;reserve evaluation;sensitive factor;uncertainty desensitization;Qintong Sag;Subei Basin7|0|0更新时间：2026-08-04
- 摘要：Continental mixed shale reservoirs commonly exhibit complex pore-fracture architectures and strong heterogeneity, which are key geological factors restricting sweet-spot prediction and efficient shale-oil development. To clarify reservoir-space types, pore-fracture system architecture, and their main controlling factors in mixed shale, this study focuses on the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, and integrates core observation, thin-section analysis, microscopic characterization, low-temperature N₂ adsorption, and high-pressure mercury intrusion to conduct a comprehensive characterization of the reservoir space system and an analysis of its controlling factors.Resultsshow that the reservoir space system is dominated by inorganic pores, organic matter pores, and microfractures. Inorganic pores include intergranular pores, intragranular dissolution pores, and intercrystalline pores, among which intergranular pores are dominant and mainly occur between felsic mineral grains. Microfractures are primarily bedding-parallel fractures and tectonic microfractures, with apertures predominantly in the 10-30μm range, and they contribute significantly to pore-microfracture connectivity and seepage capacity. Full-scale pore characterization indicates a distinct bimodal pore size distribution (<100 nm and >2 000 nm), and an average total pore volume of about 0.0085 cm³/g. Reservoir quality varies systematically among lithofacies, generally following the order: felsic shale > mixed shale > clay-rich shale. Mineral composition and lamination collectively exert strong controls on the pore-fracture system, mainly through pore enhancement by dissolution, pore reduction by cementation, and fracture promotion by brittleness: dissolution of quartz and plagioclase generates secondary pores; intercrystalline pores associated with clay minerals contribute substantially to micropore volume; whereas carbonate cementation reduces pore-throat connectivity but may facilitate fracture development under tectonic stress. Interbedded felsic-mixed laminae promote the development of bedding-parallel fractures, and organo-inorganic complexes within clay-rich laminae enhance pore-network connectivity. Overall, pore-fracture coupling is a key mechanism governing reservoir effectiveness and heterogeneity, and provides an important basis for constructing reservoir evaluation schemes and optimizing sweet-spot intervals in continental mixed shale oil systems.关键词：reservoir space;development characteristics;controlling factors;mixed shale;Fengcheng Formation;Mahu Sag4|5|0更新时间：2026-07-30
- 摘要：Fractal theory is an important method for quantitatively characterizing the heterogeneity of shale reservoir pore structures. Taking the Longmaxi Formation shale reservoir as an example, this study systematically compares the monofractal and multifractal characteristics of seven shale samples from this formation in the Sichuan Basin, based on N2 adsorption experiments, with particular emphasis on the advantages of multifractals in representing complex pore structures. The results indicate that: ① The pore structure of Longmaxi Formation shale is complex, dominated by slit-like pores, and also includes composite features such as conical pores, conical parallel-plate pores, and ink-bottle pores. The pore volume is mainly contributed by pores with diameters around 35 nm, whereas the specific surface area is predominantly provided by pores with diameters of approximately 3 nm; ② Using three monofractal models, namely the Frenkel-Halsey-Hill (FHH), Neimark, and Wang-Li models, different fractal dimensions are obtained (DFHH: 2.610 0~2.814 9, DNeimark: 2.875 1~2.984 6, DWang-Li: 2.606 1~2.778 7). Among them, the Wang-Li model exhibits the highest goodness of fit (R2>0.999). However, all models are limited by their theoretical assumptions and applicable scale ranges, making it difficult to fully capture the complexity of shale pores across different scales; ③ All samples exhibit pronounced multifractal behavior, with stronger heterogeneity in low-probability regions (moment order q ≤ -1) and relatively uniform structure in high-probability regions (q ≥ 1). Multifractal parameters (D-q/Dq, D-q-Dq, αmin-αmax, and αmin/αmax) are negatively correlated with specific surface area and positively correlated with mean pore diameter, indicating that this approach effectively characterizes pore heterogeneity across scales. By systematically comparing monofractal and multifractal methods for Longmaxi Formation shale, this study highlights the advantages of multifractals in quantifying complex shale pore networks and provides new analytical perspectives and theoretical references for N2 adsorption-based fractal characterization.关键词：fractal;N2 adsorption;pore structure;Longmaxi Formation;shale24|19|0更新时间：2026-07-30
- 摘要：The deep tight sandstone gas reservoirs (3 680~4 250 m) in the Shaximiao Formation of the Zitong Block, Sichuan Basin, exhibit distinctive geological features: nanopore-throat dominance, strong compaction and cementation, and coupled wettability hysteresis and clay swelling. These features cause severe fracturing fluid invasion, low flowback efficiency (typically<20%), and compounded damage from water blocking and clay swelling, significantly hindering efficient reservoir development. To address these challenges, this study conducted full-cycle core-flooding experiments on natural samples from the first member of the Shaximiao Formation. Using a high-temperature high-pressure dynamic capillary pressure testing system under simulated reservoir conditions (82 °C, 40 MPa confining pressure), we simulated water-flooding-gas (fracturing fluid injection) and gas-flooding-water (flowback). Fifteen core samples with gas permeability ranging from 0.071×10-3 μm2 to 1.158×10-3 μm2 were divided into three groups: ultra-low permeability (K≤0.1×10-3 μm2), low permeability (0.1×10-3 μm2<K≤1.0×10-3 μm2), and relatively high permeability (K>1.0×10-3 μm2 ). The results reveal three key findings. First, during water flooding, dynamic capillary pressure transitions from a driving force to flow resistance as water saturation increases, with a critical transition at approximately 37% saturation. This resistance growth is more pronounced in lower-permeability cores (K≤0.1×10-3 μm2). Second, during gas flooding, capillary pressure consistently acts as a resistance that intensifies with decreasing water saturation; ultra-low permeability cores exhibit resistance 1.5 to 4.0 times greater than high-permeability cores. Third, a quantitative relationship was established, revealing the synergistic amplification mechanism of high nanopore-throat proportion (>70%) and illite-dominated wettability hysteresis (dynamic contact angle deviation of 30°~45°). Based on these findings, we propose an optimized flowback strategy comprising “rate-controlled injection, staged gentle flowback, clay stabilization, and real-time adjustment,” with differentiated engineering measures integrating permeability zonation and geological characteristics. This research provides experimental and theoretical support for refining fracturing design and optimizing flowback regimes in the Zitong Block, and offers valuable guidance for developing analogous deep tight sandstone gas reservoirs in the Sichuan Basin and beyond.关键词：deep tight sandstone gas reservoirs;dynamic capillary pressure;wettability hysteresis;fracturing fluid flowback;permeability zoning26|19|0更新时间：2026-07-30
- 摘要：As an important type of continental shale oil and gas resources, shale oil in saline lacustrine basins is subject to multiple controls such as sedimentation and diagenesis during its hydrocarbon generation process, showing remarkable complexity and heterogeneity. Based on data investigation of the geological characteristics of shales in typical saline lacustrine basins in China, combined with research results from experimental techniques including closed-system and semi-open-system hydrocarbon generation simulations and organic sulfur analysis, this study systematically discusses the genetic mechanism of differential hydrocarbon generation of shales in saline lacustrine basins in China. The results show that shales in saline lacustrine basins are rich in lithofacies and organic facies types with strong heterogeneity, and the major source rock intervals generally have moderate to high organic matter abundance, kerogen types dominated by Type Ⅰ-Ⅱ2, and thermal maturity ranging from 0.7% to 1.3% vitrinite reflectance (Ro). Some typical shales exhibit a bimodal oil generation characteristic during hydrocarbon generation: bimodal distribution of low-mature oil and mature oil for shales in sulfate-type lacustrine basins, and bimodal distribution of mature oil and high-mature oil for shales in alkaline carbonate-type lacustrine basins. The types of hydrocarbon-generating organisms controlled by sedimentary environments dominate the material basis and hydrocarbon generation process of source rocks. Organic sulfur reduces the hydrocarbon generation activation energy of kerogen through low-bond-energy C-S bonds, leading to an earlier hydrocarbon generation threshold of shales. Salt minerals, clay minerals, volcanic minerals and alkaline minerals regulate hydrocarbon generation pathways and product compositions through organo-mineral interactions such as catalytic reactions, hydrogen supply and saponification. Through innovative experimental techniques and in-depth mechanism analysis, dynamic simulation of hydrocarbon generation from microscopic compounds to macroscopic geological processes has been realized, providing key technical support for kinetic modeling of hydrocarbon generation, resource potential evaluation and “sweet spot” interval prediction of shales in saline lacustrine basins. 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：saline lacustrine basin;shale oil;hydrocarbon generation mechanism;organic sulfur;organic-inorganic interactions112|480|0更新时间：2026-07-30
- 摘要：Conducting CCUS parameter optimization research targeting high-temperature oil reservoirs, it is possible to both product oil and gas resources from the reservoirs and develop unused geothermal resources, while achieving CO2 geological storage, enhancing the utilization value of the reservoirs, and prolonging their economic lifespan. In the current CCUS injection production parameter optimization project for high-temperature oil reservoirs, the use of reservoir numerical simulators to manually set parameter value limits is time-consuming, labor-intensive, and low calculation accuracy. The paper takes high-temperature oil reservoirs as the research target and establishes the comprehensive numerical model for CCUS that simultaneously considers three mechanisms: CO2 geological storage, oil displacement, and heat production. In order to maximize the economic benefits of CO2 oil displacement, heat production, and storage, constructing a high-temperature reservoir CCUS injection production optimization model with CO2 injection rate and liquid production rate as optimization variables and economic net present value as the objective function, and using the improved ant colony algorithm to solve. To address the issues of low computational efficiency and susceptibility to local optima in standard ant colony algorithms, an improved ant colony optimization algorithm is proposed. The improved ant colony optimization algorithm introduces ant direct communication learning mechanism and global optimal solution optimization method, improves path selection probability, ensures population diversity to escape local optima, and enhances algorithm accuracy and robustness. The results show that for the CCUS injection production optimization model of high-temperature oil reservoirs, the improved ant colony algorithm can obtain the optimal solution after 435 iterations, with an optimal economic net present value of 369 million yuan, which is 7 million yuan higher than the standard ant colony algorithm. Corresponding to the optimal gas injection rate of 40879 m ³/day and liquid production rate of 3370 m ³/day; Compared with the standard ant colony algorithm, the improved ant colony optimization algorithm has higher efficiency and better results. It can quickly and accurately optimize and adjust the CO2 oil recovery and storage plan, which is of great significance for improving the economic benefits of reservoir development.关键词：High-temperature oil reservoir;CCUS;Improved ant colony algorithm;Direct communication learning mechanism;Optimization of injection and procurement parameters;Net present value of economy10|7|0更新时间：2026-07-27
- 摘要：Continental mixed shale reservoirs commonly exhibit complex pore–fracture architectures and strong heterogeneity, which are key geological factors restricting sweet-spot prediction and efficient shale-oil development. To clarify reservoir-space types, pore–fracture system architecture, and their main controlling factors in mixed shale, this study focuses on the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin, and integrates core observation, thin-section analysis, microscopic characterization, low-temperature N₂ adsorption, and high-pressure mercury intrusion to conduct a comprehensive characterization of the reservoir space system and an analysis of its controlling factors. Results show that the reservoir space system is dominated by inorganic pores, organic matter pores, and microfractures. Inorganic pores include intergranular pores, intragranular dissolution pores, and intercrystalline pores, among which intergranular pores are dominant and mainly occur between felsic mineral grains. Microfractures are primarily bedding-parallel fractures and tectonic microfractures, with apertures predominantly in the 10–30μm range, and they contribute significantly to pore–microfracture connectivity and seepage capacity. Full-scale pore characterization indicates a distinct bimodal pore size distribution (<100 nm and >2000 nm), and an average total pore volume of about 0.0085 cm³/g. Reservoir quality varies systematically among lithofacies, generally following the order: felsic shale > mixed shale > clay-rich shale. Mineral composition and lamination collectively exert strong controls on the pore–fracture system, mainly through pore enhancement by dissolution, pore reduction by cementation, and fracture promotion by brittleness: dissolution of quartz and plagioclase generates secondary pores; intercrystalline pores associated with clay minerals contribute substantially to micropore volume; whereas carbonate cementation reduces pore-throat connectivity but may facilitate fracture development under tectonic stress. Interbedded felsic–mixed laminae promote the development of bedding-parallel fractures, and organo–inorganic complexes within clay-rich laminae enhance pore-network connectivity. Overall, pore–fracture coupling is a key mechanism governing reservoir effectiveness and heterogeneity, and provides an important basis for constructing reservoir evaluation schemes and optimizing sweet-spot intervals in continental mixed shale oil systems.关键词：reservoir space;development characteristics;controlling factors;mixed shale;Fengcheng Formation;Mahu Sag10|6|0更新时间：2026-07-23
- 摘要：To address the difficulties in identifying gas channeling during CO2 flooding in low-permeability oil reservoirs and the high global warming potential and environmental burden of conventional gas tracers, this study evaluates the performance and applicability of gas-phase tracers. The objective is to provide low-carbon and environmentally friendly alternative tracer media for dynamic field monitoring of gas channeling and to meet the field requirements of coordinated monitoring across large reservoir blocks and multiple well groups. Four gas-phase tracers, namely SF6, C2F6, C4F8 and C2HF5, were selected for static retention experiments and dynamic displacement experiments. The results show that: ①All four gas-phase tracers exhibit good stability within the experimental temperature and pressure ranges. The retention rates of the non-polar tracers C2F6 and C4F8 remain above 90% throughout the tested range, while the retention rate of the polar tracer C2HF5 remains above 87%. ②The dynamic production characteristics of the four tracers exhibit clear transport equivalence and functional differentiation in different types of cores. In high-permeability cores, the tracer response curves are highly consistent, with relative differences in breakthrough time of less than 5%. All tracers respond sensitively to preferential flow channels and exhibit broad, flat-topped slug characteristics. In contrast, in low-permeability and fractured cores, the tracers show differentiated transport behaviors due to differences in molecular polarity. The non-polar tracers C2F6 and C4F8 migrate more rapidly with the gas phase and break through earlier, whereas the polar tracer C2HF5 shows a significantly delayed production front in the low-permeability matrix because of interphase partitioning and adsorption, and exhibits a lower secondary-peak mole fraction in fractured cores. All four tracers demonstrate good feasibility for field monitoring and can provide a wider range of options for field tracer selection. Among them, C2F6 and C4F8 can serve as environmentally friendly alternatives to conventional SF6 and are suitable for reliable characterization of preferential flow channels, whereas the polar tracer C2HF5, which exhibits a sensitive transport-retardation response to the fluid environment, is more suitable for differential evaluation of matrix sweep characteristics.关键词：CO2 flooding;low-permeability reservoir;gas-phase tracers;preferential flow channel;displacement experiment10|12|0更新时间：2026-07-23
- 摘要：The concept of "full fracture propping" aims to improve fracture placement morphology by the efficient placement of main fractures and hierarchical propping of multi-scale fractures, effectively addressing the limited effective propped volume in unconventional oil and gas reservoirs. Using proppant-fiber clusters instead of pure proppant as the basic transport unit in fractures can effectively increase the lateral migration distance and vertical placement height of proppant in main fractures, serving as a key technical approach to achieving efficient placement. This study systematically investigated the structural characteristics and sedimentation mechanisms of proppant-fiber clusters through experimental methods, establishing a physical model of the cluster unit network structure and revealing the sedimentation and placementmechanisms of clustered bodies within the main fractures. The results indicate that proppant-fiber clusters are a composite system jointly composed of a fiber framework that traps proppant particles, a filamentous network of friction reducer polymers, and a flaky structure of stabilizer. Characterization of cluster units and their size distributions revealed that increasing fiber mass fraction and length facilitates the formation of larger cluster units.Specifically, the average proppant placement height increased by 116.6% with the addition of 0.5% fibers compared to the proppant-only system. At 30 seconds of sedimentation, the average sizes of the cluster units formed by 6 mm and 12 mm fibers are 2.15 mm and 4.26 mm, respectively. However, the relationship between slickwater viscosity and cluster size is nonlinear. Transport experiments in the multi-stage fracture show that increasing fiber mass fraction and fiber length can elevate proppant placement height in the main fracture, but fiber-induced proppant blockage occurs at fracture intersections.Therefore, optimizing material intrinsic properties and injection parameters is of significant engineering importance for realizing full fracture domain propped technology centered on proppant-fiber cluster transport. The research findings also provide theoretical support for the optimal design and field application of fiber-assisted fracturing technology.关键词：unconventional oil and gas;full fracture propping;proppant;fiber;proppant-fiber cluster;transport characteristics27|9|0更新时间：2026-07-09
- 摘要：Being a geothermal field with medium-low temperature conductivity, Guanzhong Basin has become the main geothermal reservoir resource in central Shaanxi Province because of its good geothermal reservoir. Efficient and reasonable exploitation of geothermal resources can play an important role in energy transformation and the goal of “double carbon”. In this paper, Guanzhong basin is taken as the research object, and the geothermal resource potential in the research area is quantitatively analyzed by volume method and Monte Carlo. Based on the physical conditions, heat transfer characteristics and location conditions, the game combination weighting model of grey correlation, criticality, coefficient of variation and projection pursuit is constructed, and the dominant area of geothermal resources in the study area is analyzed. The target area of geothermal resources development in Guanzhong basin is determined by comprehensive evaluation grade of geothermal resources potential and dominant areas. The results show that the maximum probability resource of Neogene thermal storage in the study area is 82.5×1018 kJ, and the average geothermal resource abundance is 38.4×1014 kJ/km2 (equivalent to 13.11×107 t/km2standard coal). The average amount of geothermal resources in Pucheng uplift is the largest, and the average abundance of geothermal resources in Xi’an sag is the highest. Population density and gross domestic product are the key dominant parameters for the division of advantage areas, with the weight ratios of 31.3% and 29.9%, respectively. The area of “good” and above geothermal development dominant area in the study area is 2978.72km2 (accounting for 13.78%), and the “good” and above grade areas are mainly concentrated in Xi’an sag, Xianli uplift and Gushi sag. The overall reliability of the evaluation results of dominant areas is high, among which Gushi sag and Xianli uplift are the most stable. Based on the comprehensive evaluation results of resource potential and development advantage areas, Xi’an sag and Gushi sag have significant advantages in structural units and are the most potential targets in the study area. The research can provide a scientific basis for the large-scale development of geothermal resources and the selection of optimal targets in the Guanzhong Basin, thereby contributing to the optimization of the regional energy structure and the achievement of carbon emission reduction goals.关键词：Geothermal resource potential;uncertainty evaluation;identification of dominant areas;game combination empowerment;Guanzhong basin21|58|0更新时间：2026-06-29
- 摘要：Nowadays, the issues of high water cut in old oilfields and the growing demand for development of unconventional resource were evident, and the traditional oil displacement technology is facing efficiency bottlenecks. The low-permeability reservoirs possessed abundant geological reserves and significant development potential. Nevertheless, their intrinsic properties, including low porosity, low permeability, strong heterogeneity, and complex pore structures, generally result in relatively low oil displacement and overall recovery efficiencies. Nanomaterials were widely applied in the petroleum industry, especially for enhanced oil recovery (EOR). However, conventional large-sized nanoparticles struggle to migrate efficiently through the micro-pore throats of low-permeability reservoirs and are prone to aggregation under harsh conditions like high temperature and high salinity, limiting their effectiveness. As the typical zero-dimensional nanomaterial, quantum dots (QDs) typically possess extremely small physical sizes, ultra-high specific surface areas, massive surface atom ratios, and abundant surface chemical functional groups. These structural characteristics endow them with an excellent size match with the pore throats of tight reservoirs, exhibiting superior monodispersity and migration ability, which provides them with greater advantages in enhancing the recovery of low-permeability reservoirs compared to traditional nanomaterials. The present review systematically summarized the types of QDs used for EOR and the current research progress in recent years, and their EOR mechanisms were revealed. Compared with conventional nanoparticles, QDs demonstrated superior capabilities in interfacial activity and wettability alteration. Finally, the future prospects of QDs in EOR applications are discussed. At present, QDs still remained at the laboratory research stage. Further advancements are required before industrial implementation, including breaking through key technical bottlenecks such as low-cost scalable green synthesis, elucidating flow mechanisms in complex environments, and achieving intelligent, stimuli-responsive functional designs, to promote their engineering applications in unconventional oilfield development.关键词：quantum dots;low-permeability reservoir;enhanced oil recovery;interfacial activity;wetting behavior26|30|0更新时间：2026-06-15
- 摘要：The shale oil reservoir in the Chang 7 Block of the Triassic Formation in the Ordos Basin has not yet achieved large-scale and effective development due to significant reservoir heterogeneity and considerable variation in crude oil physical properties. Accurately predicting single-well production and identifying its main controlling factors are crucial for optimizing field production strategies. Based on production data, engineering parameters, and fracturing parameters from 197 sample wells screened in the Chang 7 Block, this study first classified the wells using a feature-weighted FCM algorithm. Subsequently, an LSTM model incorporating an attention mechanism was constructed for intelligent production simulation and prediction. This mechanism effectively overcomes the difficulty of the standard LSTM model in screening key information under multi-parameter conditions by prioritizing the most critical factors and ignoring less influential ones. The model parameters were then optimized using a differential evolution algorithm. Finally, the production predictions were compared against those from the standard LSTM model and the traditional Arps model. The results indicate that: Across the three classified well types, the main factors influencing single-well production include oil saturation, the number of fracturing stages, sand volume, the total injected fracturing fluid volume, and reservoir length. Furthermore, the relative contribution of each factor varies among the three well types. The traditional Arps decline model showed significant errors in three evaluation metrics—coefficient of determination (R²), root mean square error (RMSE), and mean absolute percentage error (MAPE)—demonstrating that neural network models provide superior prediction performance for single-well production in this shale oil reservoir compared to the Arps model. The introduction of the attention mechanism improved the prediction accuracy of the LSTM model for the three well types by 3.34%, 3.57%, and 2.57%, respectively, demonstrating its effective optimization capability. Adjusting the input parameters and training set length of the AT-LSTM model according to the characteristics of different production stages for the three well types can further enhance prediction performance. Aiming to increase single-well production, the optimization of the main controlling factors for wells within the block confirmed the feasibility of multi-factor synergistic optimization. This simultaneously provides strong support for adjusting production strategies for single wells in the Chang 7 Block shale oil reservoir.关键词：attention mechanism;differential evolution algorithm;LSTM model;production forecasting;shale oil31|14|0更新时间：2026-06-04
- 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 time29|7|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 epoch51|10|0更新时间：2026-05-15
- 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 analysis52|45|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 filling104|290|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 behavior117|122|0更新时间：2026-04-02
- 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 Formation55|258|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 model46|130|0更新时间：2026-03-30
- 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 network58|308|0更新时间：2026-03-24
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