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2026, 32(1)
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2026, 32(1): 1-4.
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2026, 32(1): 1-2. doi: 10.12090/jissn.1006-6616.20253201
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Research progress and development trends of low-friction drilling fluid for shale gas
SUN Jinsheng, CAI Wenhui, WANG Jintang, LYU Kaihe, ZHAO Ke, ZHANG Junhao
2026, 32(1): 3-14. doi: 10.12090/j.issn.1006-6616.2025151
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  Objective  Shale gas is an important unconventional natural gas resource in China, boasting significant potential reserves. Deep shale gas reservoirs generally have specific geological characteristics, such as low porosity and permeability, strong abrasiveness, and high temperature and pressure. Technical problems often arise during drilling, such as wellbore instability, friction in the long horizontal section, and large torque. Low-friction drilling fluid technology is key to safe and efficient drilling in deep shale gas reservoirs.   Methods  Based on an investigation of the current state of shale gas exploration and development in the world, this paper analyzes the evaluation index of drilling fluid lubricity and its drag reduction mechanisms, including, among others, lubrication film formation, rolling friction, and wettability regulation.   Results  This paper systematically reviews the lubrication performance and research progress of various low-friction drilling fluid systems, such as water-based and oil-based drilling fluid systems.   Conclusions  It is proposed that, in the future, it will be necessary to continue to strengthen the research and development of new, high-performance drilling fluid lubricants; to promote the intelligent and green transformation of drilling fluid systems; and to facilitate the multi-objective coordination between lubrication and wellbore stability technologies to meet the challenges posed by complex formations. [Significance] This research provides strong technical support for the safe and efficient development of global shale gas, for enhancing the productivity of deep oil and gas reserves.
The marine environment and organic matter enrichment model of the intracontinental Upper Yangtze Craton during the Middle Triassic
TANG Song, WANG Xianfeng, CHEN Anqing, ZHOU Linlang, QI Yan, PENG Qiu, QIAN Yangjiaojiao, YUE Dali
2026, 32(1): 15-30. doi: 10.12090/j.issn.1006-6616.2025055
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  Objective  The exploration of marlstone reservoirs represents a current frontier for expanding oil and gas resources. The recent discovery of unconventional marine oil and gas in the Lei 3-2 sub-member of the Middle Triassic Leikoupo Formation in Well CT-1 reveals a new prospective area. However, the organic matter enrichment mechanisms and exploration potential of this sub-salt lagoon marlstone remain unclear, hindering further exploration.   Methods  This study, focusing on Well CT-1 in the central Sichuan Basin, investigates the organic matter enrichment mechanism through rock mineralogy and paleo-oceanographic geochemical proxies. This study also characterizes the reservoir properties and distribution via reservoir characterization and sedimentary facies analysis to evaluate its potential.   Results  The marlstone was deposited in an anoxic, deep-water lagoon of a carbonate platform with high paleo-productivity. The enrichment of organic matter, with an average total organic carbon (TOC) content of 1.16% (reaching up to 1.78%), was co-controlled by these reducing conditions and high productivity. Analyses (CT and SEM) of the high-quality "sweet spot" intervals show that the storage space is predominantly composed of nano- to micro-scale pores and microfractures, with porosity exceeding 3%. The reservoir developed in a deep-water, marlstone- and gypsum-rich lagoon within an epicontinental sea carbonate platform.   Conclusion  The widespread distribution of deep-water lagoons during the deposition of the Lei 3-2 sub-member is associated with a maximum flooding event. Concurrently, the prevailing monsoon climate significantly enhanced weathering and nutrient input, while the overlying regressive evaporites provided a seal for long-term and efficient organic matter preservation. [Significance] Comprehensive analysis suggests that the extensively distributed, organic-rich deep-water lagoon marlstone formed during this transgression in the intracontinental sag of the Upper Yangtze Craton is not only a viable unconventional exploration target but also likely acts as a hydrocarbon source for conventional reservoirs within the Leikoupo Formation.
Assessment of shale gas enrichment factors and delineation of favorable exploration zones in the first submember of the first member of the Longmaxi Formation, Tiangongtang area, southwestern Sichuan
LIU Shengjun, YUE Wenhan, LIU Yongyang, NI Jia, FANG Rui, DING Jieming, XU Fei, FAN Cunhui, XIA Tong, XU Lu
2026, 32(1): 31-48. doi: 10.12090/j.issn.1006-6616.2025103
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  Objective  The shale gas reservoir in the First Member of the Longmaxi Formation in the Tiangongtang area of southwestern Sichuan exhibits significant heterogeneity. To investigate the factors influencing shale gas enrichment, this study systematically analyzed the enrichment conditions and exploration potential in southwestern Sichuan.   Methods  This was achieved through an interdisciplinary approach incorporating core analysis, geochemical analysis, mineralogical characterization, and well-logging interpretation.   Results  The first sub-member (Long 1-1) contains continuous organic-rich shale with a thickness of 25–60 m, featuring a TOC content of 1.0%–4.0% (average 3.19%). The lower intervals (Long 1-1-1 to Long 1-1-3) show significantly higher TOC values than the upper intervals. With Ro values ranging from 2.58% to 3.16%, the shale is in an overmature stage. The mineral composition is dominated by quartz (35%–45%),clay minerals (25%–35%), and carbonate minerals (15%–25%). Brittle mineral content exceeding 59% and brittleness indices of 60.3%–71% indicate favorable fracability. The reservoir space comprises organic pores (0.02–0.9 μm in diameter), inorganic pores (including intragranular dissolution pores and intergranular pores), and a multi-scale fracture system (including structural fractures, non-structural fractures, and microfractures). The porosity ranges from 3.0% to 6.0% (average 4.2%), while the permeability varies between 0.0003 and 0.2352 mD(2.96×10−7–2.32×10−4μm2), exhibiting a vertical permeability profile with low values at the top and bottom and high values in the middle. Analysis of structural preservation conditions reveals that gentle anticlines and monoclinal structures provide better preservation conditions, whereas areas near steep fault zones experience significant gas dissipation. Formation pressure coefficients show a positive correlation with production, and wells with a pressure coefficient exceeding 1.4 typically achieve daily production rates above 2.0×104 m3/d (e.g., Well Y203 at 3.626×104 m3/d).   Conclusion  Through establishing a comprehensive evaluation index system, the study area was subdivided into favorable zones of Class I (TOC > 2.4%, brittleness index > 65%, porosity > 4.5%, high-quality shale thickness > 35 m, burial depth 3000–4000 m, pressure coefficient > 1.4) and Class II, providing a scientific basis for shale gas exploration and development in the Tiangongtang area. [Significance] The research findings elucidate the key factors that control shale gas enrichment in complex structural settings and offer guidance for efficient shale gas development in southwestern Sichuan.
Geochemical characteristics and geological implications of dark shale in the second submember of the first member of the Qiongzhusi Formation, Ziyang–Weiyuan area, China
XIE Shengyang, YANG Xuefeng, LI Bo, ZHAO Shengxian, ZHANG Jian, ZHANG Chenglin, LIU Jiawei, ZHANG Deliang, HUANG Shan, CHEN Xin, LIU Yongyang, ZHU Ning, WANG Gaoxiang, YIN Meixuan
2026, 32(1): 49-66. doi: 10.12090/j.issn.1006-6616.2025125
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  Objective  The Lower Cambrian Qiongzhusi Formation, situated within the Ziyang–Weiyuan rift of the Sichuan Basin, represents a key target for deep to ultra-deep shale gas exploration and exhibits considerable resource potential. However, the high-resolution paleo-environmental evolution and the specific controlling mechanisms of organic matter (OM) enrichment within the core high-quality interval (dark shale of Bed 5, Submember 2, Member 1 of the Qiongzhusi Formation) remain insufficiently understood. This study aims to precisely reconstruct the paleo-depositional conditions—including climate, salinity, redox, water restriction, terrigenous input, and productivity—and to clarify the main factors controlling OM accumulation.  Methods  To precisely elucidate the paleo-depositional environment, productivity evolution, and controlling mechanisms of organic matter enrichment within this interval, a systematic geochemical investigation, including analyses of total organic carbon (TOC), major, trace, and rare earth elements, was conducted on black shale samples from Well Z201.  Results  The geochemical composition of the shales in Bed 5 exhibits significant vertical phasic heterogeneity. TOC abundance displays a ‘low–high–low’ trend, peaking in Bed 5-2 with an average of 3.72 %. Amongst major elements, Al2O3 and TiO2 show a distinct trough in Bed 5-2, indicating minimum terrigenous input. Redox-sensitive trace elements (e.g., U, Mo, V, Ni) are enriched in Beds 5-2 and 5-3, with U and Mo enrichment factors (EFs) and covariation patterns indicating a strongly reducing and restricted environment.  Conclusion  Based on the integrated analysis of these geochemical proxies, this study reconstructs the paleo-environmental evolution and elucidates the mechanism of organic matter enrichment. The shale deposition occurred under a stable warm–humid to semi-humid climate within a brackish and hydrographically restricted basin. The bottom water redox conditions fluctuated significantly, evolving from dysoxic in Bed 5-1 to strongly anoxic and euxinic in Beds 5-2 and 5-3, before reoxygenating to dysoxic conditions in Beds 5-4 and 5-5. Concurrently, terrigenous detrital input dropped to a minimum in Bed 5-2 but intensified significantly from Bed 5-3 upwards, while primary productivity peaked specifically in Bed 5-2. Consequently, the formation of the core high-quality source rock in Bed 5-2 resulted from the optimal convergence of high primary productivity, strong anoxic preservation, and weak terrigenous dilution. In contrast, organic matter accumulation in other intervals was suppressed by intensified terrigenous dilution and/or the deterioration of preservation conditions. [ Significance ] These findings clarify the complex coupling mechanism driving organic matter accumulation in deep shelf environments, highlighting that preservation conditions and sedimentation dilution are as critical as primary productivity.
Hydrocarbon generation potential of deeply buried shales within the Jurassic transitional Badaowan Formation, central Junggar Basin
ZENG Zhiping, LI Baoqing, WANG Jinduo, LIU Hui, LI Shaojie, GAN Runkun
2026, 32(1): 67-83. doi: 10.12090/j.issn.1006-6616.2025111
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  Objective  The deeply buried transitional shales within the Jurassic Badaowan Formation in the central Junggar Basin have become a frontier target for unconventional hydrocarbon exploration in recent years, yet their petroleum generation potential remains to be fully constrained. Recent exploration wells in the Fukang and Dongdaohaizi depressions have encountered shale sequences within the Badaowan Formation at burial depths exceeding 5000 m, offering a valuable opportunity to assess hydrocarbon potential of deeply buried shales in this area.   Methods  This study evaluated the hydrocarbon generation potential of the deeply buried shales of Badaowan Formation in the central Junggar Basin by integrating organic geochemistry, microscopic component analysis, hydrous pyrolysis experiments, numerical modeling, and biomarker analysis.   Results  The deeply buried shales of Badaowan Formation in the Fukang and Dongdaohaizi depressions were selected as research target, and following outcomes were obtained: (1) Shales exhibit relatively high organic matter abundances, with TOC values ranging from 0.75% to 5.06% and 0.81% to 5.27%, respectively, and kerogen is dominated by types II and III; (2) Maturation parameters (Ro=0.70%–0.82% and 0.51%–0.80%, respectively) indicate that the shales are currently in the main oil generation window; (3) Thermal history reconstruction shows that hydrocarbon generation began in the Late Jurassic, passed the main oil generation threshold in the Late Cretaceous, and has continued for approximately 150 million years; (4) Hydrous pyrolysis results show that total hydrocarbon yields of the shales are 380–500 mg/g; (5) Biomarker data reveal a transitional depositional environment of frequent redox fluctuations, with organic inputs from both aquatic organisms and higher terrestrial plants.  Conclusions  Consequently, Deeply buried shales of Badaowan Formation in the central Junggar Basin possess substantial hydrocarbon generation capacity and constitute a promising exploration target for shale oil and gas.
Genesis of organic-rich shales in the Fengcheng Formation, southern Mahu Sag: Evidence from organic petrology, biomarkers, and isotopes
CHEN Shanhe, QI Hongyan, WANG Wei, WANG Zhenlin, LI Yanghu, TANG Fukang, GUO Shouxin, FU Zhenghang
2026, 32(1): 84-106. doi: 10.12090/j.issn.1006-6616.2025146
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  Objective  The Mahu Sag, a pivotal, hydrocarbon-rich depression within the Junggar Basin, hosts the Permian Fengcheng Formation, a primary source rock interval widely regarded as a key “sweet spot” target for shale oil exploration. Unlike the well-studied depocenter and northern slope of the Mahu Sag, the Southern Mahu Sag represents a marginal lacustrine facies. Although possessing distinct source rock quality, organic matter (OM) occurrence, and paleo-environmental evolution, the underlying genetic mechanisms remain poorly constrained.   Methods  To address this, this study integrates organic petrology, molecular geochemistry, and stable carbon isotope analyses on 33 mudstone and shale samples from 12 wells in the Southern Mahu Sag. Systematic tests were conducted to comprehensively evaluate the geochemical characteristics and hydrocarbon generation potential. These included determination of the total organic carbon (TOC) and total sulfur (TS) content, Rock-Eval pyrolysis, measurement of vitrinite reflectance (Ro), chloroform bitumen “A” extraction, gas chromatography–mass spectrometry (GC–MS) of saturated and aromatic hydrocarbons, and analysis of the carbon isotope compositions of extracts and fractions.   Results  The results indicate that the OM abundance of the Fengcheng Formation source rocks in the Southern Mahu area generally reaches “good” to “excellent” levels. However, affected by the dilution of terrigenous detritus and transport effects, the OM is predominantly mixed Type II–III kerogen, contrasting significantly with the Type I–II OM typically found in the Northern Mahu area. The samples are generally within the peak oil-generation window (Ro>0.8%).   Conclusions  After rigorously assessing and calibrating the thermal maturity effects on source-related parameters (e.g., Pr/Ph, β-carotane, and ETR), multi-proxy analysis confirms that the OM mainly originates from lower aquatic organisms, such as algae and bacteria, with limited input from higher terrestrial plants. Regarding the depositional environment, the study area primarily evolved in a saline lacustrine slope setting, characterized by dual control of endogenous chemical precipitation and exogenous terrigenous detrital input. The water column exhibited weak reducing and high-salinity conditions.   Significance  This study (i) elucidates the material basis of the Fengcheng Formation source rocks as a “saline mixed sedimentary” shale oil enrichment zone in a marginal facies, (ii) reveals the depositional heterogeneity compared to the sag center and northern slope, and (iii) provides a theoretical foundation for expanding shale oil exploration in the Junggar Basin.
Impact of middle to late Triassic climate change on organic matter enrichment in hydrocarbon source rocks of the Chang 7 Member, Yanchang Formation, southeastern Ordos Basin
LU Man, DUAN Guoqiang, ZHANG Tongxi, HUANG Tianhua, WANG Zhaoyang, LI Dewei
2026, 32(1): 107-123. doi: 10.12090/j.issn.1006-6616.2025139
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  Objective  The middle to late Triassic was a period of critical climatic transition in Earth's history. Multiple global humid climate events during this time profoundly impacted both marine and terrestrial depositional environments, facilitating the development of marine and continental source rocks.   Methods  This study focuses on the hydrocarbon source rocks of the seventh member of the Yanchang Formation (Chang 7 Member) in the southeastern Ordos Basin. Based on integrated elemental geochemical and molecular organic geochemical analyses, this study explores the relationship between middle to late Triassic humid climatic events and organic matter enrichment in lacustrine settings.   Results  The lower to middle interval of Submember 3 of Chang 7 Member (695–660 m in depth) is characterized by high total organic carbon content and good hydrocarbon generation potential. Chemical weathering indices indicate that this interval was deposited underwarmer and more humid climatic conditions, while the overlying upper portion of Submember 3 and Submembers 2 and 1 were deposited under cooler and drier conditions. By combining global characteristics of middle to late Triassic humid events with palynostratigraphy, zircon U–Pb geochronology, and carbon isotope stratigraphy, this study links the lower to middle interval of the Submember 3 and the middle to late Triassic Ladinian–Carnian humid climate event.  Conclusions  The findings suggest that, under the influence of humid climate events, enhanced terrestrial nutrient influxes stimulated primary productivity in the lake. Concurrently, intensified water column stratification and bottom-water anoxia created favorable conditions for organic matter preservation, leading to the deposition of high-quality source rocks. Following the event, the climate shifted towards colder and drier conditions. This reduced terrestrial input, decreased primary lake productivity, lowered oxygen depletion in the water, and led to less favorable conditions for organic matter preservation and enrichment. [ Significance] This study not only provides new evidence for paleoclimatic and paleoenvironmental reconstruction during the middle to late Triassic but also offers an important reference for understanding organic matter enrichment mechanisms during major climatic transitions in Earth’s history.
Refined characteristics and evaluation of shale reservoirs in the Wulalike Formation, central-western margin of the Ordos Basin
MA Mingyang, XIE Mengyu, ZHANG Dongdong, WANG Qianping, LIU Wenhui, WANG Tong, LI Fengjiao, SUN Wenyi, GUAN Xiaohan
2026, 32(1): 124-141. doi: 10.12090/j.issn.1006-6616.2025117
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  Objective  In recent years, exploratory breakthroughs in the Wulalike Formation on the western margin of the Ordos Basin have opened up a new field of marine shale gas in the North China Plate. Systematically characterizing the microscopic pore structure of low-TOC marine shale gas reservoirs and clarifying the main factors that control pore development is crucial for the prediction and evaluation of shale gas in the Wulalike Formation.   Methods  Well R16 was selected as the key research object, and a series of experimental tests such as X-ray diffraction whole-rock mineral analysis, argon ion polishing– scanning electron microscopy, and low-temperature gas adsorption were carried out. The storage space and capacity of the shale gas in the Wulalike Formation were characterized in detail.   Results  (1) The reservoir as a whole has low porosity and low permeability. The upper section is mainly composed of clay shale, the middle section of interbedded gley shale and mixed shale, but the lower section of siliceous shale. Porosity is highest in the upper section, intermediate in the middle section, and lowest in the lower section. Overall, organic pores are not developed, and inorganic pores and micro-cracks predominate. (2) The pore volume of shale ranges from 4.021×10−3 to 8.307×10−3 cm3/g, with an average of 6.031×10−3cm3/g. The main contributors are mesopores and macropores. The specific surface area ranges from 1.131 to 6.605 m2/g, with an average of 2.986 m2/g. Micropores are the main contributors, followed by mesopores; macropores are the least relevant. Shale gas primarily occurs in pores ranging from 0 to 10 nm, accounting for an average proportion of 86.7%. A large number of microfractures connected with nanoscale pores form a complex pore–fracture network system, which is the main channel for the seepage and diffusion of shale oil and gas. (3) The pore structure, physical properties, and gas-bearing capacity of the reservoir are mainly influenced by clay minerals, which results in more developed pore volumes and specific surface areas in the upper and middle sections compared to the lower section. The intergranular pores of illite, as the main mineral, provide a certain storage space for the reservoir and constitute the main carrier for natural gas.   Conclusions  Comprehensive analysis indicates that the siliceous shale in the lower member of the Wulalike Formation and the interval of interbedded argillaceous-mixed shale in the middle member are favorable exploration intervals. [Significance] This study provides an in-depth analysis of the gas storage characteristics and influencing factors of low-TOC shale reservoirs in the research area, which will contribute to advancing the exploration of marine "low-TOC" shale gas in northern China.
Mechanisms of stress evolution and infill-well fracture disturbance in shale gas reservoirs with natural weak planes
RUAN Qi, ZHANG Liehui, ZHAO Yulong, ZHANG Deliang, ZHENG Shizhuo
2026, 32(1): 142-158. doi: 10.12090/j.issn.1006-6616.2025144
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  Objective  Mid-to-deep shale gas reservoirs exhibit a composite fracture–matrix structure, in which internal weak planes play an essential role in stress evolution and fracture propagation. Few studies have treated natural fractures as both hydraulic and mechanical weak planes simultaneously, nor has there been systematic and quantitative analysis of the impact of these fractures on four-dimensional stress evolution and fracture propagation in infill-wells during production.   Methods  To address these knowledge gaps, this study conducts laboratory tests to obtain the normal stiffness and hydraulic properties of weak planes, and develops a four-dimensional stress evolution model for mid-to-deep shale gas reservoirs that captures the coupled hydraulic–mechanical weakening behavior of natural fractures. The model is then used to analyze how weak planes perturb the in-situ stress field and the morphology of hydraulic fractures in infill-wells at different stages of production.   Results  Low-stiffness weak planes are prone to deformation, with reduced internal stress and stress concentration at fracture tips. Moreover, the disturbance of the maximum horizontal principal stress increases progressively with the growing angle between the weak plane and the principal stress direction, while the minimum horizontal principal stress exhibits a non-monotonic response: first decreasing, then increasing. During production, the deviation of stress orientation is more pronounced when mechanical weak planes are considered. Correspondingly, infill well fractures extend farther along the original maximum horizontal stress direction when not in contact with fracture zones, while the lateral expansion is enhanced and the propagation along the original maximum horizontal stress is shortened. These differences remain relatively unchanged over time, reflecting the fact that weak planes primarily influence stress disturbance in the early stages, becoming stable later on.   Conclusions  This study reveals how weak planes disturb the four-dimensional stress evolution. It provides theoretical guidance and practical reference for stress management and fracture optimization in hydraulic fracturing and infill development of mid-to-deep shale gas reservoirs.
Experimental study on the elastic–plastic deformation and failure behavior of deep shale with well-developed inclined bedding
HUO Tingwang, WANG Daobing, SHENG Mao, DONG Yongcun, WANG Qiuyan, HUANG Weihan, YU Bo
2026, 32(1): 159-183. doi: 10.12090/j.issn.1006-6616.2025133
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  Objective  Deep shale reservoirs are characterized by high temperature, high pressure, and well-developed bedding structures, which jointly govern the mechanical response of rocks during hydraulic fracturing. Previous studies have primarily focused on the effects of single temperature conditions or the mechanical behavior of bedding under conventional environments. However, systematic understanding of the elastoplastic deformation behavior and anisotropic failure mechanisms of bedded shale under coupled high-temperature and high-confining-pressure conditions remains insufficient, particularly in terms of the quantitative characterization of strength parameter evolution, damage features, and fracture complexity.  Methods  Therefore, this study employs a high-temperature and high-pressure triaxial rock mechanics testing system to conduct triaxial compression experiments on shale specimens with different bedding orientations. In combination with CT scanning, ultrasonic testing, scanning electron microscopy (SEM), X-ray diffraction (XRD), and nuclear magnetic resonance (NMR) techniques, the internal structural evolution, fracture development, and pore structure variations of the rocks are comprehensively characterized. Meanwhile, the evolution laws of strength parameters are analyzed based on the Mohr–Coulomb, Hoek–Brown, and Drucker–Prager criteria, and the fracture complexity and thermal damage characteristics are quantitatively evaluated using fractal dimension, energy dissipation theory, and damage factor calculations.   Results  The results indicate that increasing temperature promotes the expansion of bedding structures and induces thermally damaged microcracks. Fracture complexity increases with temperature, accompanied by a pronounced attenuation of wave velocity, while the peak strength and elastic modulus of shale exhibit decreasing trends, demonstrating that thermal stress significantly degrades its mechanical properties. Comprehensive analysis based on the three yield criteria shows that, under high-temperature and high-confining-pressure conditions, shale cohesion gradually decreases whereas the internal friction angle increases, and the failure mode transitions from brittle-dominated behavior to elastoplastic deformation. The coupled effects of temperature and pressure enhance the accumulation of plastic strain prior to failure. Energy analysis and damage factor results further reveal that elevated temperature markedly increases the proportion of dissipated energy and intensifies rock damage, reflecting enhanced microcrack propagation and irreversible deformation processes. Fractal dimension analysis demonstrates that the fracture network becomes progressively more complex with increasing temperature, facilitating the formation and connectivity of multiscale fracture systems. Anisotropy index analysis shows that thermal stress amplifies the anisotropic differences in compressive strength and elastic modulus among shales with different bedding orientations, whereas confining pressure suppresses such directional disparities to some extent by restricting crack opening and bedding-controlled deformation. Together, these factors determine the overall anisotropic mechanical response of deep shale.   Conclusions  In summary, the combined effects of high temperature and high pressure intensify the elastoplastic deformation and damage evolution of bedded shale. Under such conditions, the failure mode shifts from brittle behavior to plastic-dominated deformation, accompanied by enhanced energy dissipation and damage development. This process promotes the increasing complexity of fracture networks and alters the anisotropic failure patterns governed by bedding structures. [Significance] This study systematically elucidates the mechanisms of elastoplastic deformation and anisotropic failure of bedded shale under high-temperature and high-pressure conditions, providing essential mechanical insights for the stability evaluation of deep shale reservoirs and the optimization of hydraulic fracturing parameters. The findings hold significant scientific relevance and engineering value for the efficient development of deep unconventional oil and gas resources.
Refined characterization of the 3D fracture complexity index based on Well-Seismic Integration
ZHANG Jinfa, FENG Yongcun, HE Bing, MA Sijia, WEI Jingyi, DENG Jin'gen
2026, 32(1): 184-196. doi: 10.12090/j.issn.1006-6616.2025059
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  Objective  The accurate characterization of formation fracture complexity is of great significance for evaluating lost circulation risks, hydraulic fracturing stimulation effectiveness, and various operational stages throughout the oil and gas drilling and production lifecycle. Addressing the limitation of the inability of existing fracture characteristic parameters to comprehensively represent fracture complexity, this study proposes a method for establishing a 3D fracture complexity index based on the concept of Well-Seismic Integration. Using an oilfield in the Bohai Sea, China, for a case study, this method refines the characterization of formation fracture complexity.   Methods  Considering the influence of both fracture aperture and fracture intensity on fracture complexity, we establish a 1D fracture complexity index model. This model is based on expert decision-making and well-logging data; it uses a combined subjective and objective weighting approach that integrates the Analytic Hierarchy Process and the Entropy Weight Method. Furthermore, the fracture development degree attribute volume derived from seismic inversion is used as a constraint condition for Kriging interpolation to construct the 3D fracture complexity index attribute volume.   Results  This method is used to derive the 1D fracture complexity index profiles of drilled wells. Comparing these profiles with borehole image logs shows that a higher fracture complexity index corresponds to a greater number of fractures or larger fracture apertures at the corresponding depth, confirming the feasibility of this method for characterizing fracture complexity. In the 3D fracture complexity index model, the attribute volume profile is extracted along the drilled well and compared with formation lithology and dual laterolog profiles. The results indicate that a higher fracture complexity index corresponds to a greater difference in dual laterolog responses. Furthermore, the lithology of this well interval is identified as granitic basement gneiss, further validating the reliability of this method.   Conclusions  A fracture complexity index was constructed using a combined weighting approach that integrates the subjective Analytic Hierarchy Process and the objective Entropy Weight Method. This index not only reflects the extent of fracture distribution but also captures the internal structural heterogeneity of fractures. It addresses the issue of low prediction accuracy in existing lost circulation risk prediction methods, which rely solely on fracture intensity as the fracture-characterizing parameter. Moreover, it compensates for the limitations of current methods for evaluating hydraulic fracturing stimulation, which assess compressibility based on a single factor, such as fracture intensity or fracture aperture. [ Significance ] The research provides a theoretical foundation and engineering guidance for predicting lost circulation risk and assessing compressibility.
Study on the influence of in-situ stress changes on shale fracture propagation considering the effect of effective stress coefficients
ZHANG Chenxi, TANG Huiying, TANG Yuxin, CHEN Yue, DENG Wenbin
2026, 32(1): 197-212. doi: 10.12090/j.issn.1006-6616.2025145
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  Objective  The geometry of multi-stage hydraulic fractures in shale gas horizontal wells is influenced by the three-dimensional in-situ stress distribution. The single-well stress profile serves as a crucial basis for predicting fracture height, and both the effective stress coefficient (Biot's coefficient) and the vertical grid resolution significantly impact the interpreted stress profile, consequently affecting the accuracy of fracture height prediction.   Methods  This study employs different Biot's coefficients (constant values and functions varying with logs) and vertical grid resolutions to compute stress profiles. It simulates and analyzes the differences in planar 3D fracture geometries under various stress profiles, systematically investigating the influence of Biot's coefficient on the stress profile and fracture geometry, and subsequently optimizing the vertical grid resolution and the method for interpreting Biot's coefficient.   Results  The results indicate that as Biot's coefficient decreases, the variation amplitude of the vertical in-situ stress profile increases, thereby restricting the vertical propagation capability of hydraulic fractures. Increasing the vertical grid resolution in the fracturing model helps to reduce the influence range of stress extremes; a 1 m vertical grid resolution achieves a favorable balance between simulation efficiency and accuracy. The Biot's coefficients calculated using empirical formulas and the poroelastic model yield similar results, with errors relative to laboratory measurements ranging from 3.68% to 3.93%. These methods provide a better match to stress test results from different formations. Furthermore, the simulated fracture heights using these variable coefficients align more closely with actual downhole fracture height monitoring results compared to using a constant Biot's value, showing errors of 8.64% to 9.94% compared to microseismic monitoring results from a vertical-to-horizontal well at the same site.   Conclusions  Through the analysis of initial in-situ stress fitting accuracy and the subsequent correspondence between simulated fracture height and monitoring data, it can be concluded that selecting an appropriate Biot's coefficient enables more realistic predictions of in-situ stress distribution and fracture propagation geometry. [Significance] This study provides valuable insights for future stress distribution calculations and fracture height predictions in shale gas wells through an in-depth discussion on the effects of Biot's coefficient and vertical grid resolution.
Evaluation of post-fracturing production efficiency in shale oil horizontal wells based on behind-casing fiber-optic monitoring
WAN Youyu, LIN Hai, ZHOU Wei, LIU Zhen, JIANG Haoyan, XIE Guiqi, LIU Shiduo, LIU Yong, YANG Jianxuan, WU Kunyu
2026, 32(1): 213-226. doi: 10.12090/j.issn.1006-6616.2025090
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  Objective  The efficient development of shale oil in the Yingxiongling area of the Qaidam Basin relies on horizontal well volumetric fracturing. Accurately evaluating cluster efficiency during stimulation and post-fracturing production performance remains a key challenge. This study aims to investigate the application and effectiveness of behind-casing fiber-optic sensing technology for this purpose.   Methods  Based on the principles of distributed fiber-optic sensing, this technology was deployed behind the casing to monitor fracturing operations and subsequent production in shale oil horizontal wells. The analysis focused on interpreting the monitoring data to assess fracture initiation and cluster contribution.   Results  The behind-casing fiber-optic monitoring provided clear diagnostic results. Compared to the conventional uniform perforation method, employing a tapered perforation design increased the cluster initiation rate during fracturing from 62% to 88%, representing a 26% improvement. Furthermore, the post-fracturing production efficiency per stage was enhanced from 0.94 m3 per stage to 3.20 m3 per stage, a 2.4-fold increase. An additional operational finding was that controlling the fracturing operation to within 8 hours after setting the metallic dissolvable bridge plug reduced fluid loss during the treatment by 7.43%.   Conclusions  The tapered perforation strategy significantly improves both cluster initiation and production contribution in the studied shale oil formation. Furthermore, optimizing the timing of fracturing operations after bridge plug setting can effectively mitigate fluid loss. [Significance] This study demonstrates the practical value of behind-casing fiber-optic monitoring for guiding key engineering decisions. The findings provide precise guidance for optimizing perforation design and operational timing in volumetric fracturing of shale oil horizontal wells in the Qaidam Basin, contributing to enhanced stimulation effectiveness and development efficiency.
Intelligent prediction method and application of single-well in-situ stress in shale reservoirs driven by multi-source data
SHEN Baojian, LI Dan, HE Jianhua, XU Bilan, WU Yanfeng, WANG Ruyue, JIANG Rui, LI Ruixue, HUO Zhizhou, LIU Kun
2026, 32(1): 227-244. doi: 10.12090/j.issn.1006-6616.2025126
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  Objective  Deep shale reservoirs are characterized by high temperature, high pressure, elevated in situ stress, and strong plasticity. Conventional in-situ stress testing methods and log interpretation models, often calibrated under simplified laboratory conditions, suffer from limited predictive accuracy, high operational cost, and poor generalizability—challenges that constrain their utility in guiding shale gas exploration and development.   Methods  Focusing on a structurally complex shale gas block in southern Sichuan as a representative case, we integrated dynamic and static multi-source data across drilling, logging, testing, and production stages. Along with experimental measurements of the physical and mechanical properties of rock under different conditions, we developed a hybrid stress prediction model by combining machine learning techniques with geomechanical principles. This multi-method, log-based intelligent prediction framework enables the generation of high-resolution in-situ stress profiles for efficient shale gas development.   Results  In the first member of the Longmaxi Formation (Long-1 Member), organic content, confining pressure, and lamination structures significantly influence mechanical anisotropy, particularly in Beds 1–4, which exhibit stronger anisotropy than the upper beds. Based on these findings, we developed a mechanically calibrated anisotropic stress interpretation model for deep shales. Using laboratory- and field-calibrated synthetic stress datasets, we established a standardized stress database for the southern Sichuan shale reservoir. Key sensitive logging parameters, including shear wave slowness, resistivity, acoustic logs, and Young's modulus were identified via Pearson correlation analysis. An optimized XGBoost model achieved interpretation accuracies above 90% for all three principal stress components, with an RMSE of 6.63, an MAE of 3.89, and a coefficient of determination (R2) of 0.91, indicating strong robustness and generalizability. The results revealed four distinct stress barrier layers from the Wufeng Formation to the Longmaxi Formation, and the top of Bed 1 and Bed 6 acted as dominant stress-sealing interfaces. Localized compressive stresses induced by fold-related deformation further enhanced vertical stress compartmentalization and increased the minimum horizontal principal stress, thereby exerting significant influence on hydraulic fracturing performance.   Conclusions  The study revealed the geological factors controlling the mechanical anisotropy of the shale in the Long-1 Member, and established an isotropic in-situ stress interpretation model suitable for deep shale reservoirs accordingly. An integrated intelligent model, L-XGBoost, was adopted to achieve a prediction accuracy exceeding 90% for three-dimensional in-situ stresses. The research also clarified the development characteristics of four sets of stress barrier layers within the Long-1 Member shale and their impact on fracturing effectiveness.  Significance  These insights provide a scientific basis for fine-scale stratigraphic subdivision and three-dimensional well pattern design for shale gas development in the tectonically complex southeastern Sichuan Basin.
An intelligent lithofacies identification method for well logging of deep carbonate rocks incorporating sequence stratigraphic prior information
ZHANG Mingdi, LI Meng, LIU Yuanyang, HUANG Yuan, CUI Shuyue
2026, 32(1): 245-257. doi: 10.12090/j.issn.1006-6616.2025108
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  Objective  Lithofacies identification constitutes a core component of reservoir characterization and is of great significance for oil and gas exploration and development. Traditional lithofacies identification relies primarily on expert experience and manual interpretation, suffering from high subjectivity, low efficiency, and poor consistency. Moreover, identifying carbonate lithofacies such as bioreefs and bioclastic shoals solely through geological and geophysical data combined with limited core samples and thin-section analysis is labor-intensive and cannot meet the requirements of refined oil and gas field development. This study aims to address the major challenges in intelligent lithofacies identification, namely the insufficient modeling of spatial dependencies in the depth direction, the lack of technical prior knowledge, and the inadequate integration of geological understanding with data-driven approaches.   Methods  We propose an intelligent well-logging lithofacies identification method for deep carbonate rocks that integrates sequence stratigraphic prior information. The method applies a deep neural network, termed Sequence-Constrained Long Short-Term Memory Network (SC-LSTM), as its core framework. This network embeds sequence stratigraphic units as geological constraints into the input feature space of the model, achieving an organic integration of geological understanding with logging response characteristics. The network architecture comprises two parallel feature extraction modules: a curve feature extraction module that utilizes convolutional layers to extract local patterns and depth-directional variation characteristics from logging responses, and a sequence feature extraction module that performs convolutional encoding on sequence division schemes to convert discrete sequence and system tract information into continuous feature representations. The method uses conventional well logs, including natural gamma ray, acoustic transit time, density, neutron, and resistivity as input data. A sliding time-window sampling strategy expands the training dataset to address the problem of limited labeled samples, while a weighted averaging prediction method enhances the stability and reliability of the identification results.   Results  The application to the Changxing Formation carbonate reservoir in the Yuanba gas field demonstrates that an optimal sample length of 40 meters can (i) completely cover the vertical evolution sequence from reef base to reef core to reef cap, or (ii) encompass a complete reef-shoal depositional combination controlled by sea-level cycles. This, enables the model to fully learn the orderly stacking patterns and facies transition characteristics within sequence units. The model achieved 92% identification accuracy on the test set. Comparative experiments between conventional LSTM and SC-LSTM networks reveal that the proposed method effectively avoids geologically unreasonable predictions that may arise from relying solely on logging response characteristics. For example, it avoids erroneously predicting reef cap facies during the early highstand system tract or misidentifying reef cap facies as reef/shoal interfacies at reef tops.   Conclusions  These findings confirm that the integration of sequence stratigraphic prior information can effectively constrain model predictions and avoid geologically unreasonable results. The conventional LSTM model learns lithofacies characteristics only from numerical patterns of logging curves and easily confuses lithofacies types with similar logging responses under different sequence backgrounds. In contrast, the SC-LSTM model enables the network to understand the geological rules and the combined characteristics of lithofacies development within different sequence units and system tracts by fusing sequence stratigraphic information. This improves the geological rationality and prediction accuracy of lithofacies identification. [Significance] The significance of this study lies not only in its practical applications—enabling rapid establishment of regional lithofacies distribution patterns to guide well deployment and providing timely support for reservoir fine characterization and the exploitation of remaining oil and gas potential through the real-time updating of lithofacies interpretation schemes as new well data accumulate—but also in its theoretical contributions. It particularly advances the integration of domain knowledge with artificial intelligence technology by linking sequence stratigraphy theory, depositional environment evolution, and deep learning algorithms in a unified framework for intelligent lithofacies identification. This opens new avenues for automated and intelligent reservoir characterization in complex carbonate formations.
Governing factors and mechanisms of CO2 microscale sweep efficiency in shale reservoirs based on causal machine learning
JIANG Jiatong, ZHANG Yihang, SONG Zhaojie, YAN Ruisheng, ZHENG Lijun, ZHANG Kaixing, LI Peiyu, HUANG Shengjie, TANGPARITKUL Suparit
2026, 32(1): 258-271. doi: 10.12090/j.issn.1006-6616.2025116
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  Objective  During CO2 fluid injection into oil reservoirs or saline aquifers, CO2-water-rock interactions can alter porous media properties, thereby influencing the CO2 microscale sweep efficiency, primarily due to capillary effects. Laboratory experiments and micro/nanoscale numerical simulations often struggle to isolate the specific contributions of individual pore properties, limiting targeted injection optimization for maximizing geological storage potential.   Methods  To investigate the dynamic evolution of pore structures and properties during multi-mineral competitive dissolution-precipitation reactions under CO2 injection, we developed a lattice Boltzmann method (LBM). This method made it possible to simulate CO2-water-rock interactions in shale oil reservoirs and to analyze pore properties (e.g., average wettability, roughness, porosity) and CO2 microscale sweep efficiency. The LBM simulations generated a dataset covering various pore property scenarios to support causal machine learning. Using a double machine learning framework with a random forest algorithm, a causal inference prediction model was built for CO2 microscale sweep efficiency, treating reaction time as a continuous treatment variable.   Results  This model quantified the relative importance of key pore parameters—porosity, wettability, and mean pore diameter—on sweep efficiency within the pore network. Its results indicate that reservoirs with higher proportions of carbonate minerals (calcite) exhibit greater CO2 microscale sweep efficiency. The CO2-water-rock reaction triggers calcite dissolution, forming preferential flow paths, while the secondary precipitation of oil-wet calcite induces localized wettability alteration. This dynamic "dissolution–secondary precipitation" process modifies capillary forces by altering the structure and physical properties of pore-throats, thereby influencing the microscale sweep range of CO2 fluids. However, under identical mineral proportions, CO2 sweep efficiency varies among samples, with higher calcite proportions correlating with broader variation in sweep performance.   Conclusions  These findings underscore the crucial role of physical pore properties, beyond mineral composition alone, in governing sweep efficiency. Causal learning identified key pore-throat parameters that control CO2 microscale sweep behavior, with wettability emerging as the most influential factor. Neutrally water-wet pore-throats exhibited the highest CO2 sweep efficiency. [Significance] By constructing a Lattice Boltzmann model for CO2-water-rock interactions and quantifying the impact of key physical parameters, this study provides a reference and guidance for the targeted adjustment of CO2 injection strategies and the enhancement of the geological CO2 storage effectiveness.
J.S.Lee’s scientific thought and the pioneering of China’s offshore oil industry (1954–1971): A study based on archival research and strategic practice
ZHAO Man
2026, 32(1): 272-284. doi: 10.12090/j.issn.1006-6616.2025180
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  Objective  During the 1950s, the prevalent presumption that China was oil-poor constrained its exploration efforts and hindered its oil exploitation.   Methods  Based on historical materials such as letters, manuscripts, speeches, and works by J.S.Lee during his tenure as Minister of Geology from 1954 to 1971, this paper comprehensively outlines the complete practical course of his guidance for China's offshore oil exploration.  Results  Based on his analysis of the Neocathaysian structural system, J.S.Lee proposed a strategy of "balanced development between eastern and western regions, with simultaneous advances on land and at sea." He also used the principle of "Find the oil region first, then locate the oil field," thereby putting into practice a comprehensive system for petroleum survey and exploration.   Conclusions  Following the breakthrough at the Daqing Oil Field, J.S.Lee personally oversaw the formulation of a progressive "from land to sea" strategy. Starting with the Bohai Sea, he systematically planned the layout for oil and gas exploration across China's entire maritime territory and issued the strategic call to "march toward the ocean." [Significance] This paper provides an important historical reference for understanding the logical implications of national strategies such as achieving self-reliance and self-improvement in science and technology and ensuring energy and resource security.
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