最新刊期
卷 16 ， 期 2 ， 2026
- 摘要：To address the core challenges such as rapid decline and low recovery factor during depletion development after volume fracturing, this study investigated the feasibility and optimization strategies of integrated CO2 huff and puff and displacement for enhancing shale oil recovery in the Subei Basin, following a research approach of mechanism experiments-model construction-field verification. First, multi-mechanism seepage experiments, including shale core imbibition, dissolution, and CO2 huff and puff and displacement, were conducted to reveal pore structure evolution and differences in imbibition and displacement efficiency under the influence of different fluids. The characteristics of hydrocarbon mobilization, pressure propagation, and sweep efficiency in the integrated CO2 huff and puff and displacement mode were quantitatively characterized. Finally, based on the experimental mechanisms and numerical simulation, key technical policies for CO2 injection development (e.g., huff and puff cycles and water-alternating-gas (WAG) timing) were optimized. The experimental results showed that: (1) Under carbonated water conditions, shale pore structures were significantly improved, and the imbibition-displacement equilibrium time was shortened to 15% of that under formation water. (2) CO2 huff and puff preferentially mobilized light hydrocarbon components, and the oil increment increased rapidly at first and then slowed as the huff and puff cycles increased, with the first three cycles accounting for over 90% of the total oil increment. (3) After huff and puff, imbibition pretreatment of the shale cores resulted in a higher CO2 displacement pressure gradient, enabling CO2 to enter smaller pore spaces, strengthening gas channeling suppression and expanding the sweep range, and increasing displacement efficiency by 4.24%. Based on these results, a shale oil development mode of “three-cycle huff and puff + WAG drive” was proposed and optimized using a compositional numerical model, and the end of natural-flow production was selected as the timing for huff and puff and displacement gas injection. This mode fully leveraged miscibility, WAG-driven sweep expansion, and gas channeling suppression, thereby further expanding the extent and degree of CO2 mobilization and increasing recovery by 12.1% compared with depletion development. Pilot injection tests in two wells confirmed that Subei shale oil had favorable gas injection capability. For well LY1-1, the peak daily oil production in the first huff and puff cycle reached 27.9 t, the cumulative oil increment was estimated to be 2 500 t, and the oil exchange ratio was 0.25 t/t (oil produced per 1 t of CO₂ injected), meeting the phased expected targets and confirming the promising development prospects of CO2 injection in Subei shale oil.关键词：shale oil;CO2;integrated huff and puff and displacement;numerical simulation;enhanced oil recovery59|17|0更新时间：2026-03-10
- 摘要：Continental fine-grained muddy-laminated shale oil is widely developed in eastern China’s faulted lacustrine basins such as the Bohai Bay Basin and Subei Basin. It is characterized by “fine grain size and numerous laminae”, representing a significant new frontier in shale oil exploration and development. However, the complex formation conditions and enrichment patterns of laminated shale oil constrain its effective exploration and development. This study aims to systematically reveal the main controlling factors of the enrichment of this shale oil type, establish corresponding geological theories and reservoir formation models, and develop a supporting key technology system to guide exploration practices and evaluate its resource potential. By comprehensively utilizing core data, well logs, 3D seismic data, geochemical experiments, and production performance data, the geological characteristics, formation conditions, enrichment patterns, and key exploration and development technologies for laminated shale oil were systematically analyzed. The study clarified the advantageous composition of “high brittleness minerals + high-frequency laminae”, the optimal thermal evolution window (maturity between 0.7% and 1.2%), and the enrichment patterns of “medium-to-high matching” (source-to-reservoir lamina thickness ratio of 1∶1.5) that yielded the highest oil content in muddy-laminated shale oil. Two types of micro-migration reservoir formation models were established: felsic + organic matter and calcareous-dolomitic + organic matter. A quantitative standard for identifying Class I enrichment layers was developed, focusing on free hydrocarbon (S1), volume fraction of brittle minerals, resistivity ratio, and natural gamma. A key technology system was developed, centering on geology-logging-seismic integrated “sweet spot” characterization, optimization of horizontal well group parameters, efficient volume fracturing, and controlled pressure production techniques. After the application of this technology system, breakthroughs in high-yield shale oil were achieved in depressions such as Huanghua, Jiyang, Liaohe, Jizhong, and Dongtai. The geological resources of shale oil in eastern faulted basins were estimated to exceed 100×108 t, demonstrating promising development prospects. Additionally, the study identified challenges of shale oil from faulted lacustrine basins, including small “sweet spot” scale, great burial depth, inter-well interference, and rapid decline. It proposed research directions such as cost reduction and efficiency improvement, digitalization, and in-situ conversion. By 2030, continental shale oil production in China would account for about 8% of China’s total production.关键词：faulted basin;continental shale oil;medium-to-high matching;micro-migration reservoir formation model;development practices56|75|0更新时间：2026-03-10
- 摘要：Accelerating digital and intelligent transformation is a crucial measure for oil and gas enterprises to advance industrial transformation and upgrading and foster new productive forces. Sinopec’s upstream sector in China has thoroughly implemented the “Digital and Intelligent Sinopec” initiative, focusing on supporting corporate reform and management. By closely aligning with the development trends of digital and intelligent technologies and the demands of exploration and production operations, the digital and intelligent transformation has been steadily advanced. A group-level Exploration and Development Data Center (EPDC) has been established, aggregating 17.2 PB of various types of exploration and development data, which has enabled centralized data management and shared applications. An Internet of Things network covering oil and gas production sites has been nearly completed, with digital coverage rates for oil, gas, and water wells, and station facilities reaching 94.90% and 92.30%, respectively. This has fundamentally transformed the traditional manual management model of stationing personnel at wells and stations, effectively supporting the reform of production operation modes and labor organization under digital and intelligent conditions. The construction and deepened application of unified systems have been advanced coordinately, continuously improving the digital coverage across all exploration and development business operations. Sinopec has also actively promoted the construction of artificial intelligence (AI) scenarios and their pilot applications, achieving notable results in scenarios such as intelligent seismic processing and interpretation, intelligent rock thin-section identification and analysis, intelligent reservoir numerical simulation, intelligent drilling, intelligent fracturing, and intelligent well condition diagnosis. Looking ahead to the “15th Five-Year Plan”, Sinopec’s upstream sector in China aims to build intelligent oil and gas fields, accelerate the integration of data flow, business flow, value flow, and supervision flow (“four flows in one”), and promote the construction and application of high-value AI scenarios across the entire business chain. These efforts will support the deeper and more substantive integration of digitalization and intellectualization, enhancing the operational efficiency, economic benefits, and management capability of oil and gas exploration, development, and production.关键词：Internet of Things;data governance;digital and intelligent transformation;architecture of intelligent oil and gas fields;“four flows in one”67|190|0更新时间：2026-03-10
Specialist Forum
- 摘要：Given the difficulty in accurately determining the total amount of retained hydrocarbons in shale with current experimental techniques, this study aims to achieve a precise evaluation of shale oil content. Using sealed core samples from well H in the Subei Basin as the subjects, this study employed multiple experimental methods, including freeze pyrolysis, multi-temperature step pyrolysis, sealed thermal release, and two-dimensional nuclear magnetic resonance (2D-NMR) to systematically evaluate the oil content and mobility. Through comparative pyrolysis experiments at different storage times and sealed thermal release experiments, the light hydrocarbon recovery coefficient for shale oil in the second member of the Funing Formation was determined to be 1.99. Combined with the difference in pyrolysis S2 peak areas before and after extraction, a heavy hydrocarbon correction formula was established (0.452 6×S2-0.307 9), enabling accurate calculation of the total retained hydrocarbons. Furthermore, 2D-NMR technology was used to calibrate crude oil of different qualities, and a standard curve between hydrogen nucleus signal intensity and oil mass was established, enabling non-destructive and rapid determination of oil content. By comparing NMR spectra before and after oil washing, the T₂ cutoff values for movable and adsorbed oil were identified, facilitating the calculation of free oil content and its proportion. The experimental results showed that the oil content measured by the 2D-NMR method was highly consistent with the recovered oil content, and the proportion of free oil showed a good correlation with results from multi-temperature step pyrolysis. The technical framework of “light hydrocarbon recovery-heavy hydrocarbon correction-NMR calibration-movable oil identification” established in this study offers advantages such as relative operational simplicity, a broad detection range, and non-destructiveness to samples. Overall, it significantly improves the accuracy and efficiency of shale oil content and mobility evaluation, providing crucial experimental support for shale oil sweet spot identification, reserve calculation, and development potential assessment.关键词：shale oil;light hydrocarbon recovery;heavy hydrocarbon correction;oil content;two-dimensional nuclear magnetic resonance (2D-NMR)42|41|0更新时间：2026-03-10
- 摘要：Exploration breakthroughs of shale oil have been successively achieved in the second member of the Paleogene Funing Formation in four main sags (Qintong, Gaoyou, Jinhu, and Haian) of the Subei Basin, marking an important area for future increases in reserves and production. The evolution of shale oil accumulation processes differs greatly among major sags. The unclear understanding of the differences in preservation conditions, controlling factors, and the development patterns of formation overpressure for shale oil has constrained further exploration deployment. Starting from the differential evolution processes of the major sags, and combined with a comparative analysis of the top-bottom conditions, fault development, and fault activity, the differences in shale oil preservation conditions and their influencing factors across various sags were clarified. Additionally, the preservation mechanisms of abnormal overpressure in complex fault-block areas was revealed. The results indicated that the differences in the sedimentary facies belts of the second member of the Paleogene Funing Formation’s base in the eastern and western parts of the basin formed the basis for current differences in formation overpressure. The activity and development degree of faults within each sag during the Wubao event, as well as the differential controlling effect of the Tan-Lu fault zone on the western part of the basin on each sag (manifested as a gradual weakening of late-stage fault activity in the second member of the Paleogene Funing Formation from west to east), constituted the core of current differences in formation overpressure across the sags. During the middle to late stage of sedimentation of the Yancheng Formation, the Haian and Yancheng Sags in the eastern part of the basin first entered the hydrocarbon generation threshold, while the Qintong, Gaoyou, and Jinhu Sags in the central and western part experienced local deepening, increased thermal maturity, and secondary hydrocarbon generation. This process was crucial in the current differences in formation overpressure across the sags. For medium-to-high maturity shale oil, the preferred favorable exploration areas were located in the deep and stable zones of the Jinhu, Gaoyou, and Qintong Sags. For low to medium maturity shale oil, the preferred favorable exploration areas were located in the deep zones of the Haian and Yancheng Sags. Moreover, within a sag, larger fault scales and closer proximity to faults were less favorable for shale oil preservation. The research findings provide guidance for shale oil exploration in continental fault-depression basins.关键词：Subei Basin;second member of Funing Formation;shale oil;preservation conditions;formation overpressure25|5|0更新时间：2026-03-10
- 摘要：Porosity and oil saturation are critical parameters in shale oil reservoir evaluation, but current laboratory measurements face challenges. In contrast, using wellsite mobile two-dimensional nuclear magnetic resonance (2D NMR) measurements can minimize the impact of light hydrocarbon loss, allowing for timely measurements of shale cores and the acquisition of relatively accurate parameters of porosity, oil saturation, and movable oil saturation. First, based on the geological characteristics of shale oil reservoirs in the second member of the Funing Formation (Fu-2 member) in the Subei Basin, a 2D NMR fluid type identification chart was constructed under laboratory conditions based on specialized experiments. This chart enabled the identification of fluid components including adsorbed oil, bound oil, movable oil, capillary-bound water, and clay water. Laboratory measurements were conducted under the same temperature and pressure conditions as wellsite measurements. The relaxation-time cutoff values for each fluid component, determined by high-precision laboratory 2D NMR measurements, were used to calibrate the field 2D NMR spectra. Then, a wellsite mobile 2D NMR fluid identification chart was established, leading to the development of evaluation models for porosity, oil saturation, and movable oil saturation. Both wellsite and downhole 2D NMR measurements employed the same echo spacing and resonance frequency to ensure consistent shapes of their 2D NMR spectra. Then, with the wellsite 2D NMR spectrum as a reference, a translation method was applied to correct the downhole NMR spectra for temperature and pressure effects. Consequently, a fluid identification chart and quantitative evaluation model for shale oil reservoirs based on downhole 2D NMR logging were established. This technique was applied and validated through comparison in four wells within the shale oil reservoir area of the Fu-2 member in the Subei Basin. The results demonstrated consistency between wellsite and downhole NMR measurements and showed a high agreement with laboratory results. These findings demonstrate the broad application prospects of mobile 2D NMR measurement technology for evaluating shale porosity, oil saturation, and movable oil content.关键词：second member of Funing Formation;shale oil;two-dimensional nuclear magnetic resonance (2D NMR);porosity;oil saturation55|28|0更新时间：2026-03-10
- 摘要：In the exploration and development of marine shale gas in southern China, traditional lithofacies classification does not fully account for the effect of thermal maturity on reservoir space, resulting in suboptimal development of thermally mature marine shales. Therefore, a reservoir facies classification method based on thermal maturity, organic matter content, and mineral composition was proposed to improve the accuracy of reservoir evaluation and identify optimal reservoir facies types. Thin section observation, scanning electron microscopy (SEM), and various experimental tests were conducted to systematically analyze the reservoir facies characteristics of the Lower Silurian Longmaxi Formation shale in the southern Sichuan Basin, and a comprehensive reservoir evaluation was conducted. The research results showed that the reservoir facies of the Longmaxi Formation shale in southern Sichuan were mainly overmature organic-rich siliceous shale (OR-S) and overmature organic-rich mixed shale (OR-M). Vertically, the reservoir facies showed a transition from overmature organic-rich siliceous shale (OR-S) at the bottom to overmature organic-rich mixed shale (OR-M) at the top. Laterally, the reservoir facies exhibited significant heterogeneity, and the siliceous mineral content gradually decreased from southwest to northeast, showing a transition from overmature organic-rich siliceous shale (OR-S) to overmature organic-rich mixed shale (OR-M) and overmature organic-rich argillaceous shale (OR-A). Through grey correlation analysis, a reservoir facies index grading standard was established. Total organic carbon (TOC) content, gas content, porosity, reservoir facies thickness ratio, siliceous mineral content, and clay mineral content were selected as key evaluation indicators, identifying overmature organic-rich siliceous shale (OR-S) as the optimal reservoir facies. This reservoir facies is characterized by moderate thermal maturity, high TOC content, high gas content, large porosity, high siliceous mineral content, and large reservoir facies thickness, exhibiting superior reservoir performance.关键词：Luzhou Block;Longmaxi Formation;thermal maturity;shale reservoir facies;reservoir characteristics47|19|0更新时间：2026-03-10
- 摘要：The Middle-Upper Permian marine shale formations in the middle Yangtze region are an important replacement field for shale gas exploration and development in China, with great resource potential. However, their reservoir development is complex. Based on previous studies, this study systematically summarizes the reservoir characteristics and research progress of three sets of shale formations from the Middle-Upper Permian: Gufeng, Wujiaping, and Dalong Formations in the middle Yangtze region. The results show that: (1) All three sets of shale formations are characterized by high total organic carbon (TOC) contents, moderate thermal maturity, and well-developed nanopores, exhibiting favorable reservoir quality. Among them, the Gufeng Formation shale exhibits the highest TOC content, with kerogen dominated by Type I. The Wujiaping and Dalong Formations show relatively lower TOC contents, and their kerogen is mainly Type II. In terms of lithofacies, the Gufeng and Dalong Formations are dominated by siliceous shale, whereas the Wujiaping Formation exhibits complex lithofacies and significant heterogeneity due to variable depositional environments. In terms of pore structure, the Gufeng Formation shale displays a wide pore-size range, with development from the nanoscale to the microscale, whereas the Wujiaping and Dalong Formation shales are dominated by micropores and mesopores. (2) The three sets of shale reservoirs are complex, characterized by diverse lithofacies, multiple pore types, and strong multi-scale heterogeneity. (3) Overall research on the Middle-Upper Permian marine shale reservoirs in the middle Yangtze region remains relatively limited. Therefore, it is recommended to carry out quantitative reservoir characterization through integrated multi-scale analysis of outcrops, cores, and experiments, promote interdisciplinary collaboration, introduce techniques such as artificial intelligence and big data analysis, establish a comprehensive shale reservoir evaluation system tailored to the geological characteristics of this region, and conduct graded optimization and evaluation of “sweet spot” intervals and areas, thereby providing solid theoretical support and decision-making guidance for large-scale exploration and effective development of Middle-Upper Permian marine shale gas in the middle Yangtze region.关键词：shale reservoir;Gufeng Formation;Wujiaping Formation;Dalong Formation;Middle-Upper Permian;middle Yangtze region35|109|0更新时间：2026-03-10
- 摘要：Exploration practices have shown that the southern Yanchuan block and Jinzhong block in Shanxi Province have significant exploration and development potential in the field of deep coalbed methane (CBM). However, studies on the characteristics of coal reservoir space and the main controlling factors of pore-fracture development remain limited, particularly regarding the coupling mechanism between the deep coal rock pore-fracture system and gas content , which hinders the production enhancement and cost-effective development of deep CBM in this region. Based on coal rock samples from key exploration wells in these blocks, this study systematically characterized the pore-fracture space types, full-scale pore size distribution characteristics, and fracture systems in deep coal reservoirs using optical microscope mosaics, field emission scanning electron microscopy (FE-SEM), and high-pressure mercury intrusion—low-temperature N2/CO2 adsorption techniques. Combined with coal composition, coal body structure, and gas content test data, the main controlling factors of pore-fracture development and their impact on gas content were revealed. The results showed that: (1) the main reservoir spaces in the 2nd coal seam of the Shanxi Formation in the southern Yanchuan block and the 15th coal seam of the Taiyuan Formation in the Jinzhong block could be divided into two major categories: pores and fractures. Pores could be further subdivided into six subcategories based on their genesis, including cellular pores, gas pores, intergranular pores, clay mineral intercrystalline pores, pyrite intercrystalline pores, and dissolution pores. Fractures could be subdivided into three subcategories: cleat fractures, bedding fractures, and tectonic fractures. The reservoir space of the No. 2 coal in the southern Yanchuan block was dominated by gas pores and cellular pores, followed by intergranular pores, with a small number of cleat fractures, tectonic fractures, and pyrite intercrystalline pores. In contrast, the reservoir space of the No. 15 coal in the Jinzhong block was dominated by cleat fractures and tectonic fractures, followed by cellular pores, gas pores, and intergranular pores, with a small number of bedding fractures and clay mineral intercrystalline pores. (2) The differences in reservoir space characteristics between the southern Yanchuan block and the Jinzhong block were primarily attributed to coal composition, coal body structure, and tectonic movement. Specifically, pore types were mainly influenced by coal composition. Matrix vitrinite predominantly developed gas pores and intergranular pores, while fusinite, semifusinite, and durinite mainly developed cellular pores. Clay minerals mainly developed intercrystalline pores and fractures. Fracture systems were primarily controlled by coal structure and tectonic movement. Cleat fractures were affected by the diagenesis of coal and the lithostatic pressure of overlying strata, relating to the thermal maturity and burial depth of the coal. Bedding fractures were associated with the depositional environment, and external fractures were formed by tectonic stress or fracture. (3) The pore-fracture structure of coal significantly affected the adsorption-desorption characteristics of CBM. The pore size distribution of matrix pores determined the specific surface area and adsorption capacity of coal, thereby affecting adsorption characteristics. The complexity of the fracture system determined the permeability of CBM, thereby affecting its desorption behavior. The differences in coal types and material composition between the two blocks resulted in distinct characteristics in pore-fracture types, mechanical properties, and adsorption-desorption behaviors. The study suggests that for reservoirs like the No. 2 coal in the southern Yanchuan block, which are dominated by matrix pores and exhibit stable gas desorption, a development strategy of “increasing fracturing scale, enhancing fracture creation, and adopting rapid drainage for pressure reduction” is recommended. For CBM reservoirs like the No. 15 coal in the Jinzhong block, which have well-developed fractures and complex pore-fracture networks, a development strategy of “improving sweep efficiency, large-volume far-field proppant placement, and controlled-pressure production” is recommended.关键词：southern Yanchuan block;Jinzhong block;deep coalbed methane;characteristics of reservoir space;adsorption and desorption35|11|0更新时间：2026-03-10
Oil and Gas Exploration
- 摘要：The efficient development of shale oil reservoirs is a current research focus and challenge. Due to characteristics—such as ultra‑tight formation, coexistence of minerals and organic matter, and the complex occurrence states of crude oil—conventional reservoir development technologies usually cannot achieve large-scale extraction of shale oil reservoirs. This study aims to improve oil recovery for the Jimsar shale oil reservoir. Using research methods such as micro-characterization and core flooding experiments, a nanofluid medium for enhancing oil recovery was developed, and its relevant mechanisms were revealed. Firstly, field emission scanning electron microscopy (SEM), high-pressure mercury intrusion, micro-CT scanning, and laser confocal analysis were used to analyze the shale pore structure and the distribution characteristics of crude oil. Subsequently, a stable and dispersed nanofluid was prepared by compounding nano-SiO2 particles, the surfactant hexadecyltrimethylammonium bromide (CTAB), and γ-mercaptopropyltrimethoxysilane (KH590). Finally, core experiments, including imbibition using formation water and nanofluid, CO2 huff and puff, CO2 flooding, and nanofluid flooding, were further conducted to clarify the differences in shale oil mobilization and the oil displacement mechanisms under different extraction methods. The results showed that the Jimsar shale reservoir pores were predominantly micro- to nano-scale with diverse morphologies and locally distributed micro-fractures. As the pore size decreased, the composition of the crude oil contained within became lighter, thereby affecting the produced gas-oil ratio during the development process. The original wettability of the shale was weakly oil-wet (water-rock contact angle≈110°), and it was transformed into a stable, strongly water-wet state (contact angle <30°) after nanofluid modification. The compounded nanofluid could maintain good long-term dispersibility and stability, and its density was close to that of formation water, avoiding potential damage to the reservoir. Constrained by characteristics such as small pore size and weak oil-wettability of the shale, the performance of formation water imbibition, CO2 huff and puff, and CO2 flooding was unsatisfactory, with displacement efficiencies all below 15%. Nanofluid imbibition outperformed formation water imbibition, though its effective distance remained limited. Nanofluid flooding achieved a oil displacement efficiency of 41.04% through the combined effects of multiple mechanisms such as wettability alteration, chemical flooding, and imbibition replacement, significantly outperforming other development methods. Among them, reservoir stimulation to expand the injection and sweep range of the nanofluid was a key prerequisite for field implementation. The nanofluid developed in this study can effectively improve the development conditions of shale reservoirs, and its flooding technology demonstrates notable advantages in enhancing oil recovery. The findings provide important guidance for the development and application of nanofluid-based shale reservoir modification technology to improve shale oil recovery.关键词：shale oil;Nanofluid;wettability;Microscopic characteristics;enhanced oil recovery80|48|0更新时间：2026-03-10
- 摘要：The second member of the Funing Formation (hereinafter referred to as the Fu-2 member) in the Gaoyou Sag of the Subei Basin is one of the important strata for continental shale oil exploration and development in eastern China. It is rich in shale oil resources and has become a crucial successor field for increasing reserves and production in the Jiangsu oilfield. At present, this zone is still in the exploration and evaluation stage, with a total of 8 pilot production wells put into production successively. Based on the analysis of production characteristics and patterns of these wells, it was clarified that compared with sub-member V, sub-member IV exhibited dynamic characteristics such as earlier oil breakthrough, faster water-cut decline, and higher initial productivity. The study proposed to adopt controlled-pressure production using a 3.0-4.0 mm choke to extend the flowing period and achieve long-term stable production. By integrating the geological background and engineering practices of the research area, a comprehensive evaluation system was established, encompassing 16 parameters in three categories: geological, engineering, and development factors. Geological parameters included total organic carbon (TOC) content, free hydrocarbon (S1), maturity, pressure coefficient, and lithofacies type. Engineering parameters include horizontal section length, sand and fluid addition intensity, stimulated reservoir volume, and fracture network complexity. Development parameters include soaking time, well-opening pressure, oil pressure at stabilized water cut, flowback rate at stabilized water cut, hydraulic pressure drop per thousand tons of fluid, and water-cut decline rate. Through statistical analysis and comprehensive multi-parameter correlation analysis, the key controlling factors affecting productivity were clarified. For geological factors, TOC content, pressure coefficient, and lithofacies type were the core parameters determining reservoir oil-bearing potential and energy foundation. For engineering factors, fluid addition intensity and fracture network complexity had a significant impact on effective stimulated reservoir volume and flow conductivity. For development factors, oil pressure at stabilized water cut, flowback rate at stabilized water cut, and water-cut decline rate directly reflected the reservoir energy maintenance capacity and fracturing fluid displacement efficiency, serving as important dynamic indicators for evaluating development effectiveness. This study identifies the key controlling factors of shale oil productivity in the Fu-2 member of the Gaoyou Sag, deepens the understanding of shale oil production patterns in this area, and provides a scientific basis and practical guidance for subsequent shale oil estimated ultimate recovery (EUR) prediction and the formulation of cost-effective development strategies.关键词：Gaoyou Sag;multi-factor correlation analysis;water-cut decline rate;lithofacies type;fracture network complexity;flowback rate39|6|0更新时间：2026-03-10
- 摘要：To improve the development efficiency of unconventional reservoirs, it is essential to clarify the microscopic occurrence states and flow migration characteristics of shale oil in clay mineral nanopores. Focusing on the widely distributed kaolinite in shale reservoirs and its interfacial effects, an intercrystalline nanoslit model was constructed through simulations of molecular dynamics (MD) to investigate the occurrence forms and dynamic behaviors of alkane components of shale oil in kaolinite nanopores. Simulations were conducted under different pore sizes (1-8 nm), reservoir temperatures (335.15-435.15 K), formation pressures (15-50 MPa), and driving forces. The influences of pore structure, temperature, pressure, and driving force on the density distribution, diffusion performance, and interfacial slip behavior of shale oil molecules were systematically analyzed, revealing the evolution mechanisms of shale oil in kaolinite pores under these effects. The results showed that increasing kaolinite nanopore size promoted the transition of shale oil molecules in the pore center from adsorbed to free states. The thickness of the adsorption layer increased simultaneously with the adsorption amount per unit area, forming a quasi-solid layer near the pore surface. Elevated temperature enhanced molecular thermal motion, weakened the interaction energy between molecules and the pore surface, and increased the diffusion coefficient by more than 3 times, indicating that thermal recovery could effectively improve shale oil mobility. Increased pressure strengthened liquid-solid interactions and molecular aggregation, restricting molecular motion and reducing the system’s overall diffusion capacity by approximately 30%. Under driving forces, shale oil exhibited pronounced interfacial slip, with slip length and average flow velocity increasing significantly with driving force, demonstrating that driving forces could effectively break through the limitations of nanoconfinement on molecular motion and enhance macroscopic flow response. Despite significant changes in flow states, the adsorption layer near the pore surface remained generally stable, reflecting the strong and stable adsorption capacity of clay surfaces for molecular layers. This study reveals the typical occurrence-migration synergistic mechanism of shale oil molecules in kaolinite nanopores and clarifies the variation patterns of molecular structure and transport parameters under different thermal and driving conditions. These insights provide molecular-scale theoretical support for the study of adsorption-controlled, diffusion-limited, and slip-dominated transport flow in clay pores and supply key microscopic parameters and model framework for optimizing thermal recovery and displacement strategies to enhance shale oil recovery.关键词：Kaolinite;nanopores;shale oil;molecular dynamics simulation;adsorption capacity;flow pattern46|58|0更新时间：2026-03-10
- 摘要：In the development of horizontal wells in low-permeability reservoirs with complex structures, when the formation dip angle is large and the direction of the maximum principal stress is perpendicular to the formation dip, the horizontal well trajectory tends to become a high-inclination pseudo-horizontal well due to structural constraints. At this point, the regulatory effects of formation dip angle on well productivity can no longer be neglected. To achieve rapid and accurate prediction of post-fracturing productivity for such wells, this study established a productivity prediction model for staged fracturing in high-inclination pseudo-horizontal wells based on the equivalent virtual wellbore radius theory, incorporating the effect of formation dip angle. By comparing with numerical simulation results, the reliability of the model was verified, and the influencing factors of the productivity of staged fracturing in high-inclination pseudo-horizontal wells were analyzed. The results showed that the longer the horizontal section, the higher the productivity of the high-inclination pseudo-horizontal well. Formation thickness and dip angle significantly influenced well productivity. As formation thickness increased, both the productivity and its growth rate gradually increased. As the formation dip angle increased, well productivity decreased, and the rate of decline gradually accelerated. Both fracture half-length and the number of fractures significantly affected productivity. Oil well productivity increased with the increase of these parameters, but the rate of increase showed a slowing trend, indicating an optimal value range. The smaller the formation anisotropy, the higher the productivity of the high-inclination pseudo-horizontal well. Moreover, the increase rate of productivity grew as the anisotropy coefficient decreased. Through field application in a high-inclination well in the Subei oilfield, it was verified that the calculation results of the productivity model for staged fracturing in high-inclination pseudo-horizontal well established in this study were close to the actual productivity of well CD101X, with a relative error of less than 5%, meeting the accuracy requirements for field applications. This model is applicable to reservoir conditions with formation dip angles of 10°~40°. It can provide a basis for formulating a reasonable production system for low-permeability reservoirs with complex structures. Moreover, the model features a concise form, high computational efficiency, and strong practicality, making it easy for field promotion and application.关键词：high-inclination formation;pseudo-horizontal well;staged fracturing;productivity model;influencing factors38|41|0更新时间：2026-03-10
- 摘要：The Yangchungou block is located in the basin-margin transition zone on the southeastern margin of the Sichuan Basin. Its main development formation is the first member of the Longmaxi Formation, with a pressure coefficient ranging from 1.0 to 1.35, making it a typical normal-pressure shale gas reservoir. Affected by multiple phases of tectonic movements, the block is characterized by complex structure, large differences in preservation conditions, and rapid changes in in-situ stress, and its geological conditions are more complex than those of the adjacent Pingqiao and Dongsheng blocks. To improve the drilling rate of high-quality shale, stimulation effectiveness, and single-well productivity in complex structural areas, an integrated technical strategy was developed through research on improving geological model accuracy, optimizing key development parameters, facilitating the efficient and rapid implementation of horizontal wells, and enabling quantitative design of reservoir stimulation. (1) A high-precision full-sequence structural model was constructed based on fault spatial distribution correction and horizon information constraints, and a 3D geomechanical attribute model was established by integrating rock mechanics parameter analysis and 3D seismic inversion attribute constraints. (2) Well pattern-fracture network adaptive development technical policies were formulated through vertical optimization of development layers and target windows, as well as horizontal zonal differentiation of well spacing and well orientation design. (3) Wellbore structure and drilling parameters were optimized with a “zone-specific and well-specific strategy” approach based on high-precision models to enhance drilling efficiency and reservoir drilling rate. (4) Optimization design of fracturing parameters and quantitative evaluation of stimulation effectiveness were conducted to improve the simulation accuracy of the fracture network and optimize fracturing parameters to improve stimulation effectiveness. Practice shows that this technical system effectively improves the single-well productivity and estimated ultimate recovery (EUR) of the Yangchungou block, which is significantly better than that of the adjacent Dongsheng block, and provides a technical reference for the efficient development of normal-pressure shale gas in similar complex structural areas.关键词：normal-pressure shale gas;complex structural area;Longmaxi Formation;full-sequence structural model;reservoir stimulation40|42|0更新时间：2026-03-10
- 摘要：Identifying the differences in physical properties and gas production of coal reservoirs at different structural locations provides an important basis for the co-development of coalbed methane (CBM). Taking 20 CBM co-production wells in the Wulihou mine field as an example, the structural combination types of reservoirs were classified based on seam floor configuration and structural curvature of the target development layers (No.3 + No.4 coal seams and No.15 coal seam). Combined with existing exploration data, the study compared key physical parameters of reservoirs at different structural locations, such as maceral components, adsorption characteristics, coal structure, gas-bearing characteristics, and permeability, and analyzed the drainage and production curve characteristics of typical co-production wells. The results indicated that: (1) The structural combination of coal reservoirs in the study area could be classified into seven types: anticline-anticline, anticline-gentle, syncline-syncline, syncline-gentle, gentle-gentle, gentle-anticline, and gentle-syncline. (2) The differences in maceral components, adsorption characteristics, coal structure, gas-bearing characteristics, and permeability were identified between the No.3 + No.4 coal seams and the No.15 coal seam at different structural locations. The degree of reservoir deformation was strongly correlated with ash content, Langmuir volume, and coal structure. The difference in structural curvature between the No.3 + No.4 and No.15 coal seams was negatively correlated with the difference in gas content, with a relatively small range of gas content variation, but was positively correlated with the difference in permeability, which changed significantly. The differences in gas content (unit: m³/t) across different structural combination types followed the order: gentle-anticline (1.55) > gentle-syncline (1.42) > anticline-gentle (1.41) > gentle-gentle (1.32) > syncline-gentle (1.06) > syncline-syncline (0.77) > anticline-anticline (0.58). The differences in permeability (unit: 10-3 μm2) followed the order: anticline-gentle (0.24) > syncline-gentle (0.21) > gentle-syncline (0.19) = anticline-anticline (0.19) > syncline-syncline (0.17) > gentle-gentle (0.16) > gentle-anticline (0.11). (3) Comparisons of gas production characteristics of co-production wells at different structural locations showed that the anticline-anticline and anticline-gentle types had better gas output, with peak values generally exceeding 1 000 m3/d. The gentle-gentle, gentle-anticline, and gentle-syncline types showed significant production fluctuations, with peak values between 200 and 1 200 m3/d. The syncline-syncline and syncline-gentle types showed poorer gas production performance, with peak values only about 200-500 m3/d.关键词：Wulihou;multilayer drainage and production;structural curvature;reservoir properties;gas production performance32|5|0更新时间：2026-03-10
- 摘要：Coalbed methane (CBM) is developed through pump drainage and depressurization. The production and migration of pulverized coal are important factors affecting the production characteristics of CBM wells. Due to the influence of coal heterogeneity, reservoir stimulation, and drainage system, the characteristics of pulverized coal production and migration vary across different production stages of CBM wells. Based on the collection and analysis of pulverized coal from CBM wells in the Panzhuang, Shouyang, and Shizhuang blocks of the Qinshui Basin, the morphology, concentration, and composition characteristics of pulverized coal produced during drainage were revealed. To investigate the influence of the shape factor of pulverized coal particles on the static settling final velocity, the characterization parameters of the pulverized coal shape factor were introduced to modify the calculation model for static settling final velocity based on the particle size distribution characteristics of pulverized coal produced from CBM wells. The modified model was then validated and analyzed through laboratory experiments. Additionally, based on the results of laboratory simulation experiments of pulverized coal migration in wellbores, the critical flow velocity for particle migration was determined, and the critical discharge rate for the migration of pulverized coal of different particle sizes was analyzed and evaluated. The results showed that the main components of pulverized coal from CBM wells were clay minerals, with an average mass fraction of 74.4%. The particle size of pulverized coal was concentrated in the range of 2~50 μm. The particle size of the pulverized coal first increased and then decreased in the CBM production stage. The calculated results were in good agreement with the experimental results (R² = 0.99) by introducing the pulverized coal shape factor into the particle static settling final velocity model, thereby improving the accuracy of critical migration velocity calculation of pulverized coal in the wellbore. Based on the production systems of CBM wells in the Panhe and Shizhuang study areas and laboratory simulated wellbore pulverized coal migration experiments, the critical migration velocities for pulverized coal particles of >180~250, >150~180, and 38~380 μm were 0.020 m/s, 0.010 m/s, and 0.035 m/s, respectively. The corresponding minimum water production rates were 5.2 m3/d, 2.6 m3/d, and 8.5 m3/d, respectively. A daily water production of a single well exceeding the minimum water production can reduce the risk of pulverized coal accumulation and pump sticking within the wellbore, providing technical support for optimizing production systems and achieving continuous and stable production of CBM wells.关键词：coalbed methane;pulverized coal;settlement;model modification;migration experiment38|10|0更新时间：2026-03-10
- 摘要：Micro-nano water-gas dispersion system (MNWDS) flooding is a novel enhanced oil recovery technique. By injecting gas-water dispersed phases at the micro–nano scale, it can enter smaller pore spaces, thereby expanding the swept volume and effectively improving recovery efficiency. At present, field tests of this method have been conducted in the Wuliwan Chang 6 pilot area. When using numerical simulation to predict oil production after MNWDS flooding, multiple parameters such as bubble size, gas-liquid ratio, and fluid properties, as well as complex gas-liquid interactions, must be considered. This process is complex and time-consuming, making it difficult to rapidly simulate oil production after MNWDS injection. This study aims to accurately predict the oil production of wells after MNWDS injection. Based on actual production data from the test area and geological model parameters, an artificial neural network (ANN) algorithm was employed to establish a production prediction model for MNWDS flooding. The model used oil production, water cut, permeability, injected MNWDS volume, waterflooding reserves, porosity, and effective thickness of wells before MNWDS injection in the test area as input parameters, and used the oil production over the 12 months after flooding as the output parameter to construct the training sample set. K-means clustering analysis was performed on the sample set to remove invalid samples, and a training set of 59 samples was finally obtained. During model training, an optimization algorithm was introduced to automatically adjust model parameters, which significantly improved prediction accuracy on the test set. Based on this model, oil production was predicted for 21 well groups scheduled to undergo MNWDS flooding. Comparisons with numerical simulation results indicated an agreement rate of up to 95%, verifying the accuracy of this model. The model provides a new approach for oil production prediction of MNWDS flooding.关键词：micro-nano water-gas dispersion system flooding;machine learning;K-Means clustering analysis;artificial neural network;Levenberg-Marquardt algorithm56|10|0更新时间：2026-03-10
- 摘要：The Dina-2 gas reservoir is a large edge-water tight sandstone gas reservoir in the Tarim Basin, with strong reservoir heterogeneity. Natural fractures are key factors influencing its high production and water invasion. Investigating fractures is crucial for understanding the water invasion patterns and formulating water control strategies for the gas reservoir. Based on geological data including core samples, thin sections, and imaging logs, this study analyzed the static geological characteristics of natural fractures. By combining production dynamic characteristics including water production, gas production, and pressure, this study analyzed the influence of different factors on water invasion. The analytic hierarchy process was used to identify the controlling factors, and the influence of structural fractures with different morphologies on water invasion characteristics was studied, and water invasion patterns for the gas reservoir were established. The results showed that structural fractures in the study area were classified into shear fractures and tensile fractures, with filled fractures being dominant. The fillings were mainly calcite, followed by quartz and clay minerals, but the fracture apertures were relatively large. Based on production dynamic characteristics, the production wells were categorized into four types: early-stage violent water-flooded wells, late-stage violent water-flooded wells, water-producing wells, and water-free wells, each with significantly different production characteristics. Based on the production and geological characteristics, the main controlling factors for water invasion in the gas reservoir were analyzed considering five factors: structural position, faults, interlayers, formation coefficient, and fractures. Fractures were identified as the primary controlling factor, with faults, interlayers, and formation coefficient as secondary factors, and structural position as irrelevant. A comprehensive water invasion evaluation index was established using the analytic hierarchy process. By considering fracture morphology differences and production characteristics, this study clarified the influence of complex fractures on high gas production and water production in gas wells. Accordingly, three water invasion patterns were established: dominant fracture-controlled type, fault-fracture compartment-controlled type, and dominant fracture-fault-sandbody composite type, summarizing the water invasion patterns of the gas reservoir. These findings provide strategic guidance for the development of similar gas reservoirs and offer valuable insights for studying water invasion patterns and development evaluation in similar water-bearing gas reservoirs.关键词：Tarim Basin;Kuqa Depression;natural fractures;water invasion characteristics;water invasion patterns46|16|0更新时间：2026-03-10
Oil and Gas Development
- 摘要：Shale oil reservoirs are characterized by complex structures, low permeability, and low porosity. The fluid supply capacity from the matrix to the fractures is weak. Fracturing stimulation measures are key methods for improving the degree of fracture development and fluid flow capacity in the reservoirs. In traditional fracturing construction plans, there are limited direct studies on the influence of reservoir structural characteristics on fracturing intensity, which leads to poor production enhancement results. To optimize the fracturing design, systematic research was conducted based on the reservoir structure, and X-ray diffraction (XRD) experiments were used to clarify the mineral composition and content of the rocks. Small-diameter true triaxial experiments were performed to obtain rock mechanics parameters and stress-strain test curves. Scanning electron microscope data and thin section observations were combined to determine the microstructure of the reservoir. Imbibition experiments and nuclear magnetic resonance (NMR) experiments were conducted, and the pore size distribution characteristics of the reservoir rocks were analyzed based on the T2 spectrum curves. Numerical simulation method was used to compare the fracture propagation patterns and production capacity differences between conventional intensity fracturing and high-intensity fracturing. The results showed that the shale from Subei Basin had a high content of brittle minerals. After failure in the direction parallel to bedding, fractures mainly developed along the bedding, while in the direction vertical to bedding, the fracture patterns were diverse, and complex intersecting fractures were formed inside the core. The microstructure of the reservoir was mainly composed of intergranular pores, and the micro-fractures were mainly layer-bedding fractures. The NMR T2 spectrum curves showed that the reservoir core developed small pores, medium pores, and natural micro-fractures. The numerical simulation results indicated that the rock characteristics of this block were suitable for implementing the high-intensity fracturing plan (displacement rate of 20 m3/min, single-stage fluid volume of 4 000 m3, and single-stage sand volume of 400 m3). After the implementation of this plan, significant variations were observed in the oil saturation field and pressure field of the reservoir near the horizontal well, indicating that high-intensity fracturing could form a more complex fracture network system, enhance the fluid mobility of the reservoir, and effectively improve the fracturing stimulation effectiveness. The research findings provide a reference for the optimization of fracturing stimulation plans in shale oil reservoirs.关键词：Subei Basin;continental shale oil;mineral components;rock mechanics parameters;microstructure;pore size distribution;imbibition effect;high-intensity fracturing107|138|0更新时间：2026-03-10
- 摘要：The Huazhuang area in the Gaoyou Sag of the Subei Basin is a key block for shale oil exploration in the Jiangsu Oilfield. The shale in the Huazhuang Ⅱ block is buried at depths exceeding 4 000 m, accounting for 42% of the total shale oil resources in the Huazhuang area. Therefore, achieving efficient development of this block is of great significance to the Jiangsu Oilfield. However, with increasing burial depth, shale oil fracturing faces challenges such as high operational pressure and difficulty in sand addition. To address these issues, the research team conducted hydraulic fracturing physical simulation experiments with the goals of increasing fracture complexity, expanding supported fracture area, and improving fracture conductivity. The influence of different injection rates and fracturing fluid viscosity on fracture morphology was analyzed, and numerical simulations were used to optimize multi-stage cluster design, ball-throwing temporary plugging techniques, and proppant combinations. The results showed that injecting medium- to high- viscosity fracturing fluid at high displacement improved fracture penetration capability but reduced the number and area of opened bedding planes. Using low-viscosity fracturing fluid with conventional displacement injection facilitated the connection and formation of bedding fractures. A single-stage design with fewer clusters was beneficial to improve the energy of each cluster, promoting more balanced fluid and sand injection among fractures. Simulation results showed that having 5-6 clusters per stage could achieve balanced fracture propagation and proppant support. At the same time, simulations were conducted to examine the impact of temporary plugging balls under different injection rates, quantities, and diameters. The optimized parameters for the temporary plugging of ball throwing were determined as follows: injection rate of 12-14 m³/min, ball diameter of 15 mm, and ball quantity of 50%-60% of the number of perforation holes. Combined with simulations of complex fracture proppant transport and placement, the optimal proppant combination and pumping parameters were determined to improve the transformation effect. This technology was successfully implemented in well HY7, yielding a peak daily oil production of 52.3 t and a single well estimated ultimate recovery of 4.6×104 t. The results represent a major breakthrough in deep shale oil exploration in the Huazhuang Ⅱ block of the Jiangsu Oilfield and provide important reference for the development of similar shale oil reservoirs.关键词：Subei Basin;deep shale oil;ultra-dense fracturing;ball-throwing temporary plugging;composite particle size66|17|0更新时间：2026-03-10
- 摘要：As a new block for shale oil development in China, Mabei area has huge development potential. However, the impact of fracture network structures generated by hydraulic fracturing on oil well drainage efficiency has not been fully studied. Therefore, accurately characterizing fracture networks is crucial for improving oil well production. This study monitored the pressure data after shut-in of 7 shale oil wells in Mabei area and used the Bourdet method to plot pressure drop characteristic curves to evaluate the fracture network morphology. By integrating fracturing parameters and production test data, this study aims to provide a scientific basis for the efficient development of shale oil in this area. The study selected seven wells of shale oil in the Mabei area as research subjects. Initially, detailed monitoring of shut-in pressure data from these wells was conducted. Subsequently, pressure drop characteristic curves were plotted using the Bourdet method, which effectively reflects the morphology and characteristics of fracture networks. By analyzing the morphology and characteristics of the pressure drop derivative curves, combined with fracturing parameters (such as breakdown pressure and sand volume per meter) and production test data (such as oil breakthrough time and production rates), a comprehensive evaluation of fracture network characteristics was performed. The study focused on key parameters such as main fracture length, secondary fracture width, density, and permeability, aiming to systematically reveal the development characteristics of fracture networks. The results showed that fracture networks of shale oil in Mabei area could be classified into three types. Type I fracture networks had short main fracture lengths, medium secondary fracture widths, high density, and high permeability. The pressure drop derivative curves showed deep V-shaped characteristics leaning to lower left, indicating that this type of fractured network was dominated by conductivity and could effectively improve oil well drainage efficiency. Type Ⅱ fracture networks had medium main fracture lengths, wide secondary fracture widths, medium density, and low permeability. The pressure drop derivative curves showed shallow V-shaped characteristics leaning to upper right, indicating that this type of fractured network was mainly storage-oriented. Although their conductivity was relatively weak, they still held certain development potential. Type Ⅲ fracture networks, characterized by long main fracture lengths, narrow secondary fracture widths, low density, and medium permeability, were overall underdeveloped. Their shut-in pressure drop derivative curves lacked distinct morphological characteristics, indicating that this type of fractured network had late oil breakthrough during the production process and was unfavorable for efficient oil well development. The study also revealed an important pattern. In wells with low breakdown pressure, under the same fracturing conditions, excessively high sand volume per meter tended to lead to the formation of Type Ⅲ fracture networks. Therefore, to improve shale oil development efficiency in Mabei area, subsequent fracturing designs should focus on avoiding the formation of Type Ⅲ fracture networks. Specific measures include optimizing fracturing parameters, such as reasonably controlling sand volume per meter, to enhance the conductivity and storage capacity of fracture networks, thereby achieving efficient shale oil development. In conclusion, this study provides valuable insights into the characteristics of fracture networks in the Mabei shale oil area and offers practical recommendations for optimizing hydraulic fracturing operations to maximize well productivity. Future research can expand the sample size and incorporate numerical simulations and field experiments to further validate these findings and refine the strategies for efficient shale oil development.关键词：shale oil in Mabei area;shut-in;pressure drop curve;fracture network;pressure drop derivative31|9|0更新时间：2026-03-10
- 摘要：Shale oil, as an unconventional oil and gas resource, has become a global hotspot for energy extraction. However, shale oil reservoirs are characterized by low porosity and low permeability, making it difficult for traditional extraction technologies to achieve efficient production, and hydraulic fracturing technology is required for development. The mechanical characteristics of shale significantly influence the fracturing effectiveness. Through rock mechanics experiments and X-ray diffraction whole-rock analysis, the mechanical parameters, such as elastic modulus, Poisson’s ratio, and in-situ stress variations of three different types of shale (laminated, bedded, and interbedded) in the Chang 7 Member of the Ordos Basin, were compared and analyzed, clarifying the mechanical properties and reservoir characteristics of different shale types and establishing the relationship between mineral composition and rock mechanical characteristics. Additionally, the variation patterns of fracture conductivity were revealed through proppant conductivity experiments and embedding experiments, providing guidance for proppant selection. The results showed that: (1) interbedded shale had a high elastic modulus and a small Poisson’s ratio, making it easy to create fractures, while laminated and bedded shales had higher in-situ stress gradients, making fracture propagation more difficult. (2) The higher the content of rigid minerals in the rock, the larger the elastic modulus and the smaller the Poisson’s ratio. The higher the content of brittle minerals, the larger the brittleness index. Compared with bedded and laminated shales, interbedded shale was hard and brittle, making it easier to generate fractures and effectively maintain fracture opening during fracturing. (3) Based on the mechanical properties of interbedded shale, it had the smallest proppant embedment depth and the highest conductivity, which facilitated fluid flow. According to the proppant selection experiments, it is recommended to use 10-20 mesh quartz sand as the proppant under low confining pressure, with a proppant packing density of 14 kg/m2.关键词：Ordos Basin;shale oil;rock mechanics parameters;triaxial compression experiment;embedding experiments;conductivity36|94|0更新时间：2026-03-10
- 摘要：Self-suspending proppants are innovative materials designed to address the limitations of conventional proppants in hydraulic fracturing, including rapid settling, uneven distribution, and poor fracture support. Through specialized design and preparation techniques, self-suspending proppants maintain their suspension in low-viscosity fluids, thereby enhancing their uniform distribution and fracture conductivity. Consequently, they significantly improve oil and gas well productivity while reducing reservoir damage. Based on the self-suspension mechanisms, self-suspending proppants are classified into three types: gas-assisted, density-controlled, and surface-modified self-suspending proppants. This review summarizes the preparation techniques for self-suspending proppants, including surface modification techniques, low-density proppant preparation methods, and functional coating technologies. The field application performance of self-suspending proppants is reviewed, and their prospects for green and efficient oil and gas exploitation are analyzed. Existing studies demonstrate that self-suspending proppants significantly enhance fracturing performance. Field applications in various oil and gas reservoirs show that using self-suspending proppants increases daily or cumulative production by approximately 2 to 7 times. Moreover, the application of self-suspending proppants in oil and gas development reduces the consumption of water and thickening agents, mitigates environmental pollution, and aligns with the principles of a green and circular economy. Despite the challenges of production costs and technological complexity, self-suspending proppants exhibit superior stimulation performance and significant production enhancement potential. Future research and development should focus on several key aspects to promote the widespread application of self-suspending proppants: first, improving material stability and environmental adaptability to ensure reliable performance under extreme conditions; second, reducing production costs of self-suspending proppants by optimizing preparation processes and raw material utilization; third, conducting long-term performance evaluation to ensure the sustained effectiveness of the proppants during extended field applications; and finally, developing multifunctional self-suspending proppants with additional capabilities, such as corrosion resistance, enhanced fracture complexity, or improved oil and gas flow behavior. Through continuous innovation and technological advancement, self-suspending proppants are expected to play an increasingly important role in future oil and gas field development, contributing to both oil and gas production enhancement and environmental protection.关键词：self-suspending proppant;self-suspension mechanism;chemical coating;low-density proppant;oil and gas production enhancement22|12|0更新时间：2026-03-10
Engineering Techniques
- 摘要：Traditional oil and gas reservoir research methods usually rely on the division of labor and collaboration among different specialized disciplines, with research and development conducted in a relay-style approach. However, this model faces challenges in achieving efficient collaboration across different stages and has limitations in optimizing overall benefits. To address this issue, an intelligent gas reservoir digital twin system was proposed, integrating four core technologies: artificial intelligence algorithm adaptation, data preprocessing, data analysis applications, and automatic model updating and prediction, aiming to construct a comprehensive platform that integrates multidisciplinary collaboration, efficient data utilization, and dynamic optimization and prediction. The results showed that, in response to the multidimensional, heterogeneous, and high-noise characteristics of data during the exploration and development process, the system ensured data accuracy and reliability through an integrated data preprocessing scheme incorporating outlier handling, missing value imputation, data transformation, statistical analysis, and quality assessment. By encapsulating artificial intelligence algorithms such as random forest and gradient boosting, the system was able to construct the optimal regression model between multiple parameters and gas reservoir productivity, focusing on three key problems—production analysis, fracturing analysis, and “sweet spot” prediction—thereby improving production prediction accuracy, optimizing fracturing operation parameters, and effectively identifying “sweet spot” areas. In addition, the system adopted an automatic modeling engine to dynamically update the structural, phase, and attribute models of the gas reservoir, and combined it with a simulator engine for real-time simulation, tracking, and prediction, thereby ensuring model adaptability and accuracy throughout the gas reservoir development process. By leveraging digital twin technology, the system constructed a virtual model consistent with the physical gas reservoir in virtual space, enabling analysis, prediction, and optimized management throughout the entire lifecycle of the gas reservoir. The research results provide strong theoretical support and technical assurance for promoting the development of gas reservoir management toward intelligent, refined, and efficient practices.关键词：gas reservoir;exploration and development;artificial intelligence;digital twin;integrated platform44|89|0更新时间：2026-03-10
Comprehensive Research
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