最新刊期
卷 16 ， 期 4 ， 2026
- 摘要：Metamorphic buried hill reservoirs are highly heterogeneous and difficult to characterize quantitatively. This study investigated metamorphic buried hill reservoirs in the Bozhong 19-6 and Bozhong 13-2 tectonic areas of the Bohai Bay Basin and established a targeted reservoir classification and evaluation scheme that effectively guided production practice. Five rock types were identified in the study area, namely migmatitic granite, migmatitic gneiss, gneiss, leptynite, and cataclasite. The reservoirs were overall characterized by medium-to-low porosity and low permeability. Reservoir space was dominated by secondary pores (intergranular dissolution pores and intragranular dissolution pores) and fractures (structural fractures, dissolution fractures, intergranular microfractures, and intragranular microfractures). The pore structure was complex and highly heterogeneous. Based on Gaussian curve fitting and multi-parameter integrated analysis, a new classification system with porosity, permeability, and fracture density as the core indicators was proposed. The reservoirs were divided into three major classes, namely Class I (high productivity), Class Ⅱ (relatively high productivity), and Class Ⅲ (low productivity). Each class was further subdivided into fracture-pore and fracture types, and the physical property boundaries were clarified. Class I reservoirs were mainly developed in the weathered conglomerate zone, the inner fractured section of the weathering leaching zone in the superimposed fractured section, and the thick (>40 m) fracture-dense zone of the weathering disintegration zone in the superimposed fractured section. Reservoir space was mainly composed of intergranular dissolution pores, intragranular dissolution pores, large-scale structural fractures, and enlarged dissolution fractures, with deep lateral resistivity generally >500 Ω·m and <700 Ω·m and interval transit time generally >53 μs/m and ≤65 μs/m. Class Ⅱ reservoirs were mainly developed in the inner fractured section of the weathering leaching zone and the medium-thick fracture-dense zone (20~40 m) of the weathering disintegration zone. Reservoir space was mainly composed of intragranular dissolution pores, small-scale structural fractures, and dissolution fractures, with deep lateral resistivity generally <1 000 Ω·m and locally reaching 2 500 Ω·m, and interval transit time generally <60 μs/m. Class Ⅲ reservoirs were mainly developed in the inner fractured section with very weak dissolution and the fracture-dense zone with a thickness of less than 20 m. Reservoir space was mainly composed of dissolution micropores, intragranular microfractures, and intergranular microfractures, with deep lateral resistivity ranging from 1 500 to 15 000 Ω·m and interval transit time generally <57 μs/m.关键词：Bozhong Sag;Archean metamorphic buried hill;Gaussian curve fitting;reservoir characteristics;reservoir classification and evaluation110|67|0更新时间：2026-06-12
Specialist Forum
- 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 caused by 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 in the G 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 energy storage parameters in the G oilfield. First, a geological model of a representative well group was established using 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 that significantly affected the 1 000-day cumulative oil production, including fracture-length ratio, fracture conductivity, injection intensity, daily water injection volume, and well shut-in time. Then, response surface methodology (RSM) 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. Finally, the comprehensive learning particle swarm optimization algorithm was introduced to iteratively optimize the identified key parameters with the objective of maximizing cumulative oil production. The application of this integrated optimization strategy significantly improved the development performance. The optimized scheme increased the 1 000-day cumulative oil production by 5.98% compared with the simulation results obtained using parameters optimized solely by RSM. The results successfully determined the optimal parameter combination suitable for fracturing energy storage in the G oilfield, and demonstrated that the integrated optimization method, combining single-factor analysis, RSM, and the intelligent optimization algorithm, effectively resolved the inefficient production problem caused by parameter mismatch in fracturing energy storage, thereby 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 improving development performance, and holds significant application value for the Ordos Basin and similar reservoirs.关键词：comprehensive learning particle swarm algorithm;energy storage;fracturing;Process Parameter Optimization;response surface methodology115|142|0更新时间：2026-06-12
- 摘要：Against the background of an accelerating global energy transition, the development of unconventional oil and gas resources has become an important strategic direction for ensuring energy security. To address the challenges caused by the increasing development intensity of unconventional oil and gas fields in China, such as deteriorating geological conditions, high development difficulty, low exploration rate, fast production decline, limited reduction in single well investment, and decreasing ultimate recovery and internal rate of return, promoting the geology-engineering integrated management in unconventional oil and gas exploration and development is crucial for achieving cost reduction, efficiency improvement, and overall coordination, and holds significant strategic importance. Using theoretical research achievement, the study proposed the concept, connotation, and characteristics of the geology-engineering integrated management for exploration and development. It systematically reviewed the challenges and current situation faced by unconventional oil and gas development, and revealed the drawbacks of isolated operation among the three major fields of exploration, development and engineering. A conceptual model of geology-engineering integrated management for unconventional oil and gas exploration and development was established, identifying and explaining seven elements, including storage-production conversion, program design, engineering support, platform construction, theoretical support, validation and correction, and geological iteration. Its specific implementation pathways were explored from multiple dimensions. Research results showed that the integrated management of unconventional oil and gas exploitation could be promoted alongside the implementation of full lifecycle management, top-level design of an integrated organizational structure, optimization and reengineering of operational processes, and development and construction of a data platform. This approach can achieve large-scale production, accelerate the conversion of unconventional oil and gas reserves into production. It not only provides a new management methodology for efficient unconventional oil and gas development but also offers insights for improving the quality and efficiency of traditional oil and gas field development management, and contribute to the high-quality development of modern oil and gas fields.关键词：unconventional oil and gas;integrated management;exploration and development;conceptual model;implementation pathway254|668|0更新时间：2026-06-12
- 摘要：Deep coal-rock gas has become an important target for increasing natural gas reserves and production in China. Field practice has demonstrated that there is a correlation between the production rate of deep coal-rock gas in the Daning-Jixian area and the economically recoverable reserves controlled by gas wells. However, existing stress-sensitivity response relationships for coal rock fail to effectively reflect this phenomenon, particularly the differentiated response of permeability to stress paths, i.e., different pressure decline rates. This study investigated the influence of stress paths on the stress sensitivity of permeability, especially the relationship between pore pressure decline rate and permeability during pressure decline process. By simulating the pore pressure variation process, 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 standard chambers, different pore pressure decline rates (stress paths) were simulated. Four core samples from the No. 8 coal seam of the Baode Mine on the eastern margin of the Ordos Basin were tested to investigate permeability variation trends of coal rock and its irreversibility under different pressure decline paths. The results showed that, with pore pressure decreasing, the matrix permeability of coal rock generally exhibited an exponential decline, characterized by a rapid decrease in the early stage followed by a slower decline in the later stages. Normalization analysis indicated that permeability recovery during unloading was relatively slow and failed to return to the initial value. Moreover, the decline amplitude of the unloading curve was smaller than that of the loading curve, demonstrating a pronounced hysteresis effect. Regression analysis of pressure decline rate and permeability change rate for different core samples revealed that, indicating differentiated responses of the stress sensitivity of coal-rock permeability under different loading rates, within a certain range, the speed of pressure drop directly affects the stress-sensitive response of coal and rock permeability. Field statistical observations further confirmed the sensitivity of coal-rock permeability to the pore pressure decline rate.关键词：deep coal-rock gas;matrix permeability;stress sensitivity;pressure decline rate;plastic deformation93|54|0更新时间：2026-06-12
Young Scientists Forum
- 摘要：By systematically reviewing the progress in Lower Cambrian shale gas exploration and development in the Sichuan Basin and its periphery, the exploration history of Lower Cambrian shale gas in China is divided into three stages: preliminary investigation and site selection evaluation, technological research and exploration breakthroughs, and benefit improvement and deep expansion. At present, the exploration and commercial breakthroughs of Lower Cambrian shale gas in China mainly rely on three innovative understandings and three iterations of engineering technology. The three innovative understandings mainly include: (1) Tensional troughs control the development of organic-rich shale and high-quality reservoirs in the Qiongzhusi Formation; (2) breaking away from the traditional concept of exploring shale gas only in organic-rich shale, two models of shale gas development in the Qiongzhusi Formation are proposed, namely, “in-place enrichment” and “in-place + carrier-bed enrichment”; and (3) the thermal evolution degree of ancient uplifts is relatively low, and trough-uplift coupling jointly controls shale gas enrichment. The three technology iterations include: (1) horizontal well drilling and staged fracturing technologies; (2) three-dimensional horizontal wells and closely spaced fracturing technology; and (3) intelligent drilling and extreme fracturing technology. Additionally, four key challenges facing Lower Cambrian shale gas exploration and development are identified: (1) The hydrocarbon generation, accumulation, and main controlling factors for high-yield enrichment of different types of shale gas remain unclear; (2) geophysical characteristics differ from those of the Silurian system, and methods for predicting geological-engineering “sweet spots” face bottlenecks; (3) reservoirs are deeply buried and subject to high in-situ stress, and efficient drilling and completion technologies urgently require breakthroughs; and (4) cost-effectiveness and environmental protection face dual challenges. In response to these challenges, related development suggestions are proposed, including strengthening research on hydrocarbon generation mechanisms and the main controlling factors of enrichment, establishing a multi-genetic pore evolution model, developing multi-attribute fusion prediction technology, developing high-temperature and high-pressure-resistant equipment, and promoting integrated technologies for intelligent cost reduction and green development.关键词：Sichuan Basin;Lower Cambrian;shale gas;tensional trough;paleo-uplift;development model;engineering technology72|34|0更新时间：2026-06-12
- 摘要：Shale oil reservoirs are characterized by tight rocks, nanoscale pore and microfractures, and extremely low permeability. According to fluid mobility, pore fluids can be classified into three types: movable fluids, capillary-bound fluids, and clay-bound fluids. Accurate identification of fluid occurrence types and quantitative characterization of their spatial distribution form the basis for establishing calculation models for key parameters such as effective porosity and movable fluid saturation, and provide important guidance for reservoir development design and productivity prediction. This study was based on a nuclear magnetic resonance (NMR) measurement system and took the shale oil reservoir in the second member of the Funing Formation in Qintong Sag, Subei Basin, as the research object. On the basis of systematically reviewing relevant domestic and international studies, one-dimensional/two-dimensional NMR experiments were conducted on rock samples under multiple states, including water saturation, centrifugation, oven drying, and oil saturation (dodecane). This enabled quantitative determination of the boundary values of the three fluid types in shale oil reservoirs and the establishment of a two-dimensional identification chart of fluid occurrence states based on the NMR T1-T2 spectrum. The results showed that a centrifugation speed of 16 000 r/min could distinguish movable water from bound water in pores, whereas an oven-drying temperature of 70 °C could distinguish capillary-bound water from clay-bound water. The T2 relaxation of indigenous organic matter exhibited a high-amplitude feature, with the main peak located at T2 = 0.15 ms, and the distribution center of the two-dimensional T1-T2 spectrum was located at T2 = 0.03 ms and T1/T2 = 300. The NMR identification chart of fluid occurrence states effectively distinguished the distribution regions of clay-bound water, capillary-bound water, movable water, bound oil, movable oil, and organic matter, and could be used to obtain the saturation values of various fluids. These results provide a scientific basis for mobility evaluation, reserve parameter calculation, and development plan optimization of shale oil reservoirs, and offer important technical references for exploration and development practice in complex shale oil reservoirs.关键词：Subei Basin;second member of Funing Formation;shale oil;2D NMR;pore fluid type52|40|0更新时间：2026-06-12
- 摘要：The thick shale layers of the second member of the Funing Formation (hereafter referred to as E1 f 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 E1 f 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 E1 f 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 prediction58|37|0更新时间：2026-06-12
- 摘要：The Nadu Formation in the Baise Basin is widely developed with matrix-type massive shale, which is a critical layer for shale oil exploration in Guangxi Province. The lithology of shale oil enrichment layers in other basins in China is dominated by laminated shales, which differs significantly from the matrix-type shale of the Nadu Formation. Recent exploration findings indicate that the shale of the Nadu Formation in the Baise Basin has favorable conditions for oil and gas generation and considerable potential for shale oil resources. However, quantitative characterization and evaluation of shale oil resources in the Baise Basin remain insufficient, and the characteristics of oil content, mobility, and their controlling factors remain unclear. To address this, taking the shale of the Nadu Formation as an example, this study conducted multi-scale characterization of the occurrence characteristics and storage space of shale oil in the Nadu Formation using conventional methods such as core observation, thin-section observation, and porosity and permeability measurement under overburden pressure, combined with advanced techniques including low-pressure nitrogen adsorption experiment, high-pressure mercury intrusion, nano-CT, two-dimensional nuclear magnetic resonance, and multi-temperature-step pyrolysis. Additionally, the oil-bearing properties and mobility of the matrix-type shale were analyzed. The results showed that the matrix-type shale of the Nadu Formation had a tight structure, with micropores and mesopores as the dominant pore types, and pore morphologies were mostly spherical and tubular, distributed in an isolated spatial pattern. Comparison before and after oil washing revealed that shale oil primarily occurred in layered fractures with widths of less than 10 nm, with small pore-throat radii and poor connectivity. The first member of the Nadu Formation had high organic matter content and relatively high oil content, but due to its low maturity, shale oil predominantly existed in an adsorbed state, with mobility of only about 20%. The second and third members of the Nadu Formation displayed lower total organic carbon content and lower oil content than the first member, but due to their slightly higher maturity, the mobile oil content in the sandstone interbeds could reach over 60%. Comprehensive analysis suggested that the oil-bearing properties and mobile oil content of the matrix-type shale in the Baise Basin were relatively low, and sandstone interbeds were relatively reliable exploration target intervals. This study not only provides a scientific basis for the evaluation of shale oil resources in this region, but also offers a reference for the exploration of this type of tight matrix-type shale oil in China.关键词：Baise Basin;Nadu Formation;shale oil;mobility;matrix-type shale142|83|0更新时间：2026-06-12
- 摘要：The southern section of the Pinghu tectonic belt in the Xihu Sag of the East China Sea Shelf Basin has favorable conditions for oil and gas accumulation. Under the combined influence of multiphase tectonic movements and lithologic sand bodies, it is characterized by complex oil and gas enrichment patterns and diverse reservoir types. After more than ten years of development, abundant oil and gas discoveries have been made in the southern section of the Pinghu tectonic belt. However, with the increasing pressure to increase reserves in the middle and late stages of gasfield development, a new round of comprehensive geological research is needed to further identify the rolling exploration potential around development platforms and to determine the accumulation characteristics and main controlling factors of differential enrichment in the southern section of the Pinghu tectonic belt in the Xihu Sag. Guided by the new whole petroleum system theory and based on well and seismic data and laboratory analysis data, this study systematically analyzed the distribution characteristics and main controlling factors of Paleogene conventional and tight oil and gas reservoirs in the southern section of the Pinghu tectonic belt by using oil-gas-source correlation and basin simulation methods. The results showed that the Paleogene in the southern section of the Pinghu tectonic belt constitutes a whole petroleum system. The carbonaceous mudstones and coals of the third to fifth members of the Pinghu Formation had strong hydrocarbon-generation capacity and great hydrocarbon-generation potential and were effective source rock intervals in this area. Comprehensive analysis of experiments and simulations indicated that about 40% of the hydrocarbons generated from the current effective source rocks had been expelled, providing the material basis for the present reservoirs. After two phases of oil and gas charging and reworking, an orderly accumulation model of medium-shallow conventional oil and gas reservoirs and medium-deep tight oil and gas reservoirs was formed. At the current stage, development mainly targeted conventional reservoirs, whereas tight reservoirs were less developed. The study concludes that tight oil and gas formed within the source rocks of the third to fifth members of the Pinghu Formation have great potential, and the main controlling factor for enrichment is the reservoir physical-property “sweet spot”. Such reservoirs are favorable targets for the next stage of exploration and development. This study provides a solid theoretical basis for increasing oil and gas reserves and production in the southern section of the Pinghu tectonic belt in the Xihu Sag and also offers guidance for rolling exploration strategies in the Xihu Sag.关键词：Xihu Sag;whole petroleum system;geochemical evaluation;oil and gas resources;oil and gas accumulation33|21|0更新时间：2026-06-12
Oil and Gas Exploration
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Production capacity prediction model of shale gas fractured horizontal wells considering rock creep AI导读
摘要：Shale gas wells usually decline rapidly in production, resulting in low estimated ultimate recovery (EUR). Therefore, it is urgent to study the influencing factors of shale gas production capacity. First, according to the rheological characteristics of shale rocks, the creep process under the viscoelastic characteristics of shale was described by the Burgers model, and a characterization method for shale matrix pore size, porosity, and permeability considering the creep effects was further proposed based on the strain definition. Then, according to the gas flow characteristics in reservoirs of shale gas fractured horizontal wells, a production capacity prediction model for shale gas fractured horizontal wells considering complex mechanisms such as rock creep was established based on the five-linear flow theory, and a production capacity calculation flowchart was proposed by comprehensively using the production capacity trial method and Newton iteration method. Finally, the reliability of the model calculation results was verified using actual production data from shale gas wells, and the influence patterns of various mechanisms on the production capacity of gas wells were analyzed. The results showed that (1) shale, as a type of soft rock, mainly underwent steady-state creep in the matrix during gas-well production, and its viscoelastic characteristics should be considered. Hydraulic fractures contained high-strength proppants, so linear elastic characteristics should mainly be considered. (2) The impact of adsorption, rock creep, micro-nanoscale effects, and stress sensitivity should be fully considered in shale gas production capacity prediction. Ignoring adsorption effects and micro-nanoscale effects will underestimate the production capacity of gas wells, while ignoring rock creep effects and stress sensitivity effects will overestimate the production capacity of gas wells. (3) Although controlled-pressure production of shale gas wells resulted in lower production capacity in the early stage, it yielded higher production capacity in the middle and later stages because it reduced the adverse impact of reservoir stress sensitivity. Therefore, controlled-pressure production was superior to depressurization production for shale gas wells. The research findings can provide theoretical guidance for the effective development of shale gas.关键词：shale gas;production prediction;Creep;adsorption;stress sensitivity48|20|0更新时间：2026-06-12 - 摘要：Shale reservoirs are widely developed with nanoscale pores, in which strong confinement effects cause fluid phase behavior to deviate significantly from bulk conditions, making conventional phase behavior 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 liquid distribution characteristics within confined pores were systematically observed. The dew-point experimental results indicated that the condensation mechanisms in both pore sizes were generally consistent, and both involved the formation and growth of liquid films or liquid bridges, which eventually evolved into liquid columns. However, differences in pore size exerted a pronounced influence on fluid condensation dynamics and liquid distribution. In 10 μm pores, condensation preferentially initiated at the corners, but the final liquid fraction in the pores remained relatively low. In contrast, in 100 nm pores, condensation was no longer restricted to the corners and tended to occur near the inlet, with a significant increase in liquid accumulation and a more uniform liquid distribution. A comparison between the measured dew-point pressures and the predictions of the Peng-Robinson equation-of-state model revealed the limitations of conventional models in describing confined phase behavior at the nanoscale. To accurately predict the phase behavior of confined fluids, a phase equilibrium prediction model applicable to confined spaces was established on the basis of the conventional model by incorporating capillary pressure, surface selective adsorption effects, and critical property shifts. The validation results showed that the modified model could accurately characterize confined fluid phase behavior, with a maximum relative error of 5.30%. Further analysis revealed that confinement effects were most pronounced under low-temperature and low-pressure conditions and gradually weakened with increasing temperature. This study combines theoretical modeling with experimental validation, providing experimental evidence and theoretical reference for describing fluid phase equilibrium in nanopores and offering new insights into the modification and application of phase behavior prediction models for shale reservoirs.关键词：shale reservoirs;confinement effects;fluid phase behavior;Peng-Robinson equation of state;micro-nanofluidic experiments50|33|0更新时间：2026-06-12
- 摘要：Ultra-low-permeability high-pour-point oil reservoirs are characterized by the “three highs” of high pour point, high viscosity at low temperature, and high wax content, which hinder fluid seepage, result in low oil recovery efficiency, and lead to complex residual-oil occurrence patterns, thereby severely restricting the further improvement of recovery in high-pour-point oil reservoirs. To investigate the microscopic seepage behavior of different displacement media in high-pour-point oil reservoirs and the mechanisms by which they influence residual-oil distribution and occurrence patterns, a self-developed high-resolution microscopic visualization displacement experimental system was used to carry out comparative high-resolution microscopic displacement experiments with three typical displacement media: water, oxygen-reduced air, and CO2. By combining high-magnification metallographic microscopy with depth-of-field reconstruction technology, multi-magnification quasi-3D images of residual-oil distribution under different displacement conditions were obtained, which enabled direct characterization of oil-phase migration pathways, interfacial evolution processes, and residual-oil occurrence states. The experimental results showed that CO2 flooding exhibited the best microscopic oil-displacement performance. Its dissolution-swelling effect, remarkable capability to reduce crude-oil viscosity, and wettability-improvement effect significantly enhanced crude-oil desorption and migration. Oxygen-reduced air flooding ranked second, and its expansion-disturbance effect activated the oil-phase interface and significantly improved displacement efficiency. In contrast, water flooding showed the poorest performance, with limited advance of the displacement front, while residual oil was mainly retained in fine pore-throat structures and non-dominant seepage channels, where it was discretely distributed and difficult to mobilize. Further long-core macroscopic displacement experiments verified the positive cumulative effect of the above microscopic mechanisms on recovery at the macroscopic scale, revealed the intrinsic correlation between microscopic oil-displacement behavior and macroscopic oil-displacement performance, clarified the differences among different displacement agents in terms of action mechanisms, residual-oil occurrence characteristics, and oil-displacement efficiency, and identified the key factors controlling residual-oil distribution and mobilization. This study provides experimental evidence and theoretical support for optimizing displacement methods and injection process parameters during the later stage of high-pour-point oil reservoir development.关键词：high-pour-point oil reservoir;microscopic visualization experiment;microscopic oil-displacement mechanism;residual oil distribution;cumulative effect43|22|0更新时间：2026-06-12
- 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 and offering broad application prospects. The adsorption characteristics of CH4 and CO2 in shale directly affect gas displacement efficiency and CO2 sequestration performance and are one of the key factors influencing the performance 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, BET specific surface area, temperature, pressure, and CO2 content 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 properties and to investigate competitive adsorption in CH4-CO2 systems. Model performance was evaluated by comparison with published data, experimental measurements, and Langmuir model predictions. The results indicated that the random forest regression model achieved the highest prediction accuracy and strong generalization ability. Within the pressure range of 0-15 MPa, the model yielded 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;Langmuir model;machine learning87|26|0更新时间：2026-06-12
Oil and Gas Development
- 摘要：Shale oil reservoirs exhibit strong heterogeneity, and in-situ stress field, rock mechanical properties, and lithological non-uniformity around the target zone are significant, leading to large differences in initiation pressure among different perforation clusters in horizontal wells. Consequently, unbalanced fracture initiation and propagation among clusters within a fracturing stage occur, severely affecting the stimulated reservoir volume and stimulation efficiency. To address these issues, this study first optimized the perforation cluster positions within each fractured well stage by minimizing the differences in initiation pressure among perforation clusters. Subsequently, considering the stress interference effect between multi-cluster fractures, the non-uniform stress field during reservoir fracturing was calculated. A multi-cluster hydraulic fracture propagation model for shale oil was then established, and finally a method for regulating uniform propagation of multi-cluster fractures was developed. Taking the horizontal shale oil well NC1 as an example, this study performed the non-uniform perforation cluster layout optimization with the objective of minimizing the differences in initiation pressure among perforation clusters. The fracture propagation before and after perforation cluster optimization was simulated and comparatively analyzed, and the effectiveness of fracture control after optimization was evaluated. The results indicated that after perforation cluster optimization, the average initiation pressure difference across all stages decreased from 7.04 MPa to 1.03 MPa. The average fracture length coefficient of variation across all stages decreased from 0.22 to 0.09, with the coefficient of variation decreasing in each stage, and all cluster fractures in each stage successfully initiated. The standard deviation of the inflow rates per cluster in well NC1, derived from high-frequency pressure wave cepstrum inversion, was less than 10, indicating a relatively uniform distribution of inflow rate among clusters. The regulation of hydraulic fracture initiation and propagation was significantly effective. This study provides a theoretical framework for enhancing the effectiveness of perforation cluster fracturing in shale oil horizontal wells and regulating the uniform propagation of fractures among clusters, offering valuable guidance for the design of multi-cluster perforation in field shale oil horizontal wells.关键词：shale oil;Initiation pressure;non-uniform perforation cluster layout;fracture length coefficient of variation;Uniform fracture propagation182|325|0更新时间：2026-06-12
- 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 pressure75|28|0更新时间：2026-06-12
- 摘要：During multistage volume fracturing of shale gas horizontal wells, casing deformation severely restricts the efficient development of shale gas. Specifically, the casing deformation rate in major blocks of the Sichuan Basin in China exceeds 20%. Among 43 drilled wells in the Baima block of the Fuling shale gasfield, 11 have suffered casing damage (with a casing deformation rate of 26%), and the casing deformation rate in the Duvernay shale gasfield in North America reaches 47%. This issue often leads to the failure of bridge plug setting, affecting fracturing operations. To effectively prevent and control fracturing-induced casing deformation, this study proposes a cementing technology based on nitrogen-injected foam cement slurry, which mitigates the influence of formation shear slip on the casing by enhancing the deformation capacity of the cement sheath. A three-dimensional mechanical model of sliding fracture-cement sheath-casing was established using FLAC3D to analyze the influence of the elastic modulus of the cement sheath on casing deformation. Mechanical property tests of foam cement stone were conducted, and the results showed that its maximum compressive deformation capacity reached 54%, far exceeding the 3%-5% of conventional cement stone, and that its elastic modulus could be flexibly regulated by the nitrogen injection volume. Combined with downhole conditions (such as casing deformation risk locations and lost circulation risk), four casing deformation prevention and control cementing processes were designed, namely the full-horizontal-section integrated type, interval type, targeted type, and whole-well variable-density type. Field tests were subsequently carried out in the Baima block of the Fuling shale gasfield. The research results indicated that when the elastic modulus of the cement sheath decreased from 10 GPa to 0.5 GPa, the casing shear deformation was reduced by 80%. When it decreased to 0.01 GPa, the influence of 35 mm formation slip on the casing could be neglected. The maximum compressive deformation capacity of foamed cement stone was 54%, much higher than the 3%-5% of conventional cement stone, and its elastic modulus could be regulated by the nitrogen injection amount. For all six test wells, the excellent rate of cementing quality exceeded 90%, and that of the horizontal section exceeded 96% in some wells. No casing deformation occurred after fracturing, forming a sharp contrast with the 26% casing deformation rate of wells cemented with conventional cement slurry in the same block. Well Jiaoye X5HF maintained normal production for 1 year after fracturing, with a daily gas production of 4.6×104 m3 and no annular pressure. In conclusion, the nitrogen-injected foam cement slurry cementing technology significantly reduces the influence of formation shear slip on the casing through the buffering effect of the flexible cement sheath. The four proposed processes can be adapted to different downhole conditions, effectively solving the problem that conventional cementing technologies struggle to balance sealing and buffering performance and providing an innovative solution for casing deformation prevention and control in shale gas wells under complex geological conditions. However, when the formation slip exceeds 45 mm, measures such as increasing the casing wall thickness should be combined for coordinated prevention and control.关键词：shale gas;fracturing;casing deformation;foam cement slurry;casing deformation prevention and control138|426|0更新时间：2026-06-12
- 摘要：The average water depth of a certain investment block in the Qiongdongnan Basin of the South China Sea is about 200 m. Jacket platforms in deepwater environments are affected by multiple factors, and their ultimate bearing capacity analysis differs from that of conventional jacket platforms. Taking a deepwater jacket platform as the research object, an integrated model was established using the structural response analysis software USFOS. The study calculated the dynamic amplification factor, the second-order gravitational effect (P-Delta effect), and the optimized lateral load P-Y curves of the pile foundation based on correction formulas under deepwater conditions. A comparative analysis of the platform’s ultimate bearing capacity was conducted, and the sensitivity of three individual influencing factors was quantified. The results showed that in terms of the reserve strength ratio (RSR), when all three influencing factors were considered, the RSR of the deepwater jacket platform decreased by approximately 0.4 under 90° environmental loading. Additionally, the time for the platform to reach plastic strain was shortened, and its ultimate bearing capacity declined. The base shear force and overturning moment of the platform were reduced by 3% and 6%, respectively. Regarding structural failure modes, insufficient pile foundation bearing capacity was identified as the primary cause of the overall failure of the deepwater jacket platform. In addition, the connection between the launching truss and the main leg was also found to be a weak point in structural resistance. The influence of the three factors on the ultimate bearing capacity of deepwater jacket ranked as follows: The dynamic amplification factor had the greatest impact, reducing the RSR change rate by 7.2% compared to pre-optimization. The P-Delta effect ranked second. The soil degradation effect (P-Y load) had the least influence. The optimized calculation method more accurately reflects the effects of loading in deepwater environments, providing a theoretical basis for evaluating the ultimate bearing capacity of deepwater jacket platform structures.关键词：ultimate bearing capacity;dynamic amplification factor;second-order gravitational load;soil degradation effect;USFOS69|37|0更新时间：2026-06-12
Engineering Techniques
- 摘要：The characteristics of sandstone diagenetic facies are complex and diverse. Taking the Eocene sandstones in the Lufeng Sag of the Pearl River Mouth Basin as the research object, it is of great significance to establish an accurate method for the classification and identification of sandstone diagenetic facies. To accurately classify the diagenetic facies, quantitative parameters including apparent compaction ratio, apparent cementation ratio, apparent dissolution ratio, and dissolved grain area ratio were introduced. Image processing techniques such as edge detection and threshold segmentation were applied to extract the content of each component from cast thin sections, thereby systematically characterizing the intensity differences of compaction, cementation, and dissolution. Based on intensity differences of diagenesis, a total of 7 diagenetic facies types were identified and further grouped into three classes. Class I diagenetic facies (including weak compaction, weak cementation, strong dissolution; and weak compaction, weak cementation, weak dissolution) exhibited the best physical properties and pore structures, with porosity greater than 13%, mainly dominated by macropores. Class II diagenetic facies (including weak compaction, strong cementation, strong dissolution; and weak compaction, strong cementation, weak dissolution) had intermediate physical properties, with porosity ranging from 9% to 13%. Class III diagenetic facies (including strong compaction, weak cementation, weak dissolution; strong compaction, strong cementation, strong dissolution; and strong compaction, strong cementation, weak dissolution) had the poorest physical properties, with porosity lower than 10%, mainly dominated by micropores. On this basis, a multilayer perceptron (MLP) neural network model was established by combining conventional logging curves (natural gamma ray, interval transit time, compensated neutron log, compensated density log, and resistivity) along with the characteristics of the three diagenetic facies classes. The number of hidden layers and the number of neurons in each layer were optimized using the control variable method, and the optimal architecture was determined to be a single hidden layer with five neurons. The MLP model achieved a training accuracy of 82.11%, and its prediction accuracy for all 23 samples in well A reached 82.61%. The log response characteristics of each diagenetic facies were in good agreement with the actual thin section identification results. The proposed method for classifying and identifying sandstone diagenetic facies based on image processing technology and MLP effectively enhances the quantitative level and identification efficiency of diagenetic facies research, and can serve as a reference for diagenetic facies evaluation of sandstone reservoirs under similar geological settings.关键词：Pearl River Mouth Basin;Wenchang Formation;diagenetic facies;image processing;machine learning;logging81|97|0更新时间：2026-06-12
- 摘要：Digital core technology is capable of constructing high-precision porous-media models for reservoir characterization under complex geological conditions, providing digital carriers for multiscale seepage simulation. It is currently widely used in petroleum engineering, rock mechanics, petrophysics, and other fields. Based on existing studies, digital core construction methods can be classified into physical modeling methods, numerical modeling methods, and hybrid modeling methods. Physical modeling methods mainly rely on imaging techniques such as CT scanning or focused ion beam scanning electron microscopy (FIB-SEM) for direct three-dimensional reconstruction. Numerical modeling methods generate equivalent models based on different algorithms, thereby overcoming the limitations of imaging resolution and sample size. According to their modeling characteristics, these methods can be further divided into global optimization algorithms, sampling information statistical algorithms, spatial statistical information algorithms, diagenetic process simulation algorithms, and deep learning algorithms. Hybrid modeling methods combine the advantages of physical experiments and numerical simulations and overcome the limitations of a single method through multisource data fusion and algorithm coupling, thereby considering more reservoir information and geological constraints. This study also elaborates on the construction principles, research progress, and development directions of various modeling methods, summarizes the characteristics of each method, and proposes corresponding solutions to their limitations. In practical applications, appropriate modeling methods should be selected according to reservoir type, target scale, and research focus to construct porous-media models that match reservoir characteristics. With the development of computer technology, digital core modeling methods will tend toward multisource data fusion, multiscale model construction, and multilevel mechanistic representation.关键词：digital core;petrophysics;modeling methods;research progress;development trends203|485|0更新时间：2026-06-12
- 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 equation55|17|0更新时间：2026-06-12
Digital and Intelligent Energy
- 摘要：During the construction of salt cavern hydrogen storage, the debrining process, in which gas injection is used to displace brine and convert the solution-mined cavern into usable hydrogen storage space, is commonly required. The process parameters at this stage directly affect the effective storage capacity and operational safety of the salt cavern. To reduce the cost and safety risks of using H2 as the debrining medium and to form a stable cushion structure during cavern construction, CH4, N2, and CO2 were selected as cushion gases, and their flow behavior when introduced during the gas injection debrining stage and their effects on salt cavern hydrogen storage performance were investigated. Based on the geological parameters of the Dunham salt region in the United States, a three-dimensional salt cavern model was constructed using the CMG-GEM numerical simulation platform, and key factors such as debrining rate, injection pressure, and cushion-gas type were systematically analyzed, with gas channeling time, cumulative gas injection, effective H2 storage capacity, and cushion-gas proportion used as evaluation indicators. The simulation results indicated that the debrining rate was the main factor controlling gas channeling behavior and effective storage capacity. When the debrining rate increased from 40 m3/h to 80 m³/h, gas channeling occurred approximately 34% earlier, the effective H2 storage capacity decreased by about 9%, and the gas-water interface gradually evolved from an overall gentle downward movement into a coning pattern along the wellbore axis. Increasing the injection pressure from 22 MPa to 25 MPa increased cumulative gas injection by about 13.6%, but it had only a limited effect on the timing of gas channeling. Under different cushion-gas conditions, CO2 was more prone to gas channeling during debrining because of its higher solubility and lower interfacial tension, and its cushion-gas proportion could reach about 45%. CH4 provided a higher effective H2 storage capacity. N2 showed a lower cushion-gas proportion (about 37%) and more favorable H2 purity. In addition, different salt-cavern shapes significantly affected gas channeling behavior, cumulative gas injection, and effective storage capacity, but under the same debrining rate, the overall trends among different cavern shapes remained consistent as the debrining rate changed, whereas the change in cushion-gas proportion was small. The results show that selecting an appropriate cushion gas and controlling the debrining rate during cavern construction can help delay gas channeling, improve the effective H2 storage capacity of the salt cavern, and enhance operational safety, thus providing a basis for the process design of salt cavern hydrogen storage construction.关键词：Salt cavern hydrogen storage;gas injection debrining;Cushion gas;numerical simulation;gas channeling102|465|0更新时间：2026-06-12
Non-fossil Energy Resources
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