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2025 Vol. 47, No. 3

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2025, 47(3): .
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Recent advancements in oil and gas exploration and potential zone prediction in Pearl River Mouth Basin
NI Chunhua, YANG Jun, WANG Yanqing, SONG Zaichao, JIANG Tianci, HUANG Bingqi, YAN Zehao, XING Zezheng, ZHU Zhenjun, LI Qi, CHEN Hehe
2025, 47(3): 451-465. doi: 10.11781/sysydz2025030451
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The Pearl River Mouth Basin (PRMB) is rich in oil and gas resources in the Cenozoic, with proven reserves growing rapidly. Geological breakthroughs, such as the identification of hydrocarbon accumulation controlled by low-angle detachment faults, strike-slip fault-controlled reservoirs in buried hills through weathering and leaching processes, and multi-type reservoir enrichment in deep-water areas, have offered new insights into exploration targets in PRMB. However, the complex geological structure and diverse target types in the basin increase the difficulty of exploration. Therefore, under the guidance of breakthroughs in exploration theory, it is crucial to reassess the Cenozoic oil and gas geological conditions in PRMB and identify potential oil and gas exploration zones. Through comprehensive analysis of the tectonic-sedimentary coupling relationships, hydrocarbon source rock and reservoir conditions, and oil and gas migration characteristics in PRMB, the oil and gas-bearing probability in different zones of PRMB was evaluated, and the total geological resource amount of the Cenozoic was calculated. The PRMB experienced significant tectonic evolution during the Cenozoic, characterized by rifting, post-rift depression, and structural activation. This evolution resulted in the formation of continental, transitional, and shallow marine sedimentary filling features, which controlled the development of two Paleogene hydrocarbon source rocks and two sets of continental and marine reservoirs. The oil and gas geological conditions in the shallow-water areas of the Lufeng, Huizhou, and Wenchang sags were favorable, with oil and gas-bearing probability exceeding 20% and relatively low geological risks. Therefore, these areas were classified as Class Ⅰ favorable zones. The total geological resource amount of the Cenozoic was approximately 13.8 billion tons, with oil accounting for 71% and natural gas 29%. Based on zone evaluation and actual exploration cases, future exploration should focus on buried hills, Paleogene, and deep-water oil and gas reservoirs, especially searching for those in low-angle detachment faults of the Enping, Kaiping, and Baiyun sags, fractured reservoirs controlled by deep strike-slip faults in buried hills of the Wenchang and Yangjiang sags, and deep-water reservoirs in the Baiyun and Liwan sags. These sags are expected to become important potential exploration zones for future oil and gas exploration in PRMB.
Transformation processes of Hetian paleo-uplift in southwestern Tarim Basin and its geological significance
LIU Shilin, DENG Mingzhe, CAI Pengrui, CAO Rizhou, ZHOU Yushuang, SHA Xuguang
2025, 47(3): 466-478. doi: 10.11781/sysydz2025030466
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The southwestern Tarim Basin experienced a complex construction and transformation process during the Paleozoic era. The unclear understanding of the superimposed transformation processes of the paleo-uplifts has restricted its oil and gas exploration. To address this issue, a series of studies, including seismic interpretation and structural analysis, were carried out based on the latest seismic and drilling data. The variation process of denudation was restored in different layers and periods, and the formation and transformation processes of the Hetian paleo-uplift were characterized. Based on the analysis of the ages and formation environments of basin-margin igneous rocks, the dynamic mechanism of the evolution and transformation of the paleo-uplift was discussed. Combined with the oil and gas exploration results, the controlling effects of the superimposed transformation of the paleo-uplifts were discussed. The results indicated that: (1) The denudation center in the southwestern Tarim Basin has undergone significant migration. During stage Ⅰ of the middle Caledonian period, denudation was confined to the southwestern margin of the basin. By stage Ⅲ of the middle Caledonian period, the denudation area expanded northward. During the early Hercynian period, the denudation center migrated eastward. In the late Hercynian period, it was located in the northwestern part of the basin. During the Himalayan period, the denudation center was located in the area where the present Bachu Uplift is situated. (2) The Hetian paleo-uplift exhibited a two-stage evolutionary pattern. It was an uplift along continental margins during stage Ⅲ of the middle Caledonian period and then transformed into an intracontinental uplift during the early Hercynian period. The Hetian paleo-uplift was mainly affected by the transformation of the western Maigaiti paleo-uplift in the northwestern margin of the Tarim Basin and the Bachu Uplift in the central basin, which adjusted the early paleogeomorphology of the Hetian paleo-uplift. (3) The migration and evolution of the paleo-uplift and the superimposed transformation between different paleo-uplifts controlled the distribution of different reservoir and caprock assemblages. The structural hinge zones between the Hetian, the western Maigaiti, and the Bachu paleo-uplifts were identified as favorable areas for oil and gas accumulation and should be the focus of future exploration efforts.
Optimal selection of high-production well targets for fault-controlled fractured-vuggy reservoir in Shunbei oil and gas field, Tarim Basin
GAO Lijun, LI Haiying, GONG Wei, YANG Wei, LI Hongyan
2025, 47(3): 479-489. doi: 10.11781/sysydz2025030479
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After years of exploration and development in the Shunbei oil and gas field, Tarim Basin, a series of technologies for ultra-deep fault-controlled fractured-vuggy target prediction, evaluation, and well location design have been formed, applicable to the No.1 and No.5 fault zones. As exploration efforts shift from the main No.1 and No.5 fault zones to the northeastern and northwestern fault zones in the eastern and western regions, the underground geological conditions become more complex, and exploration costs rise significantly. Existing reservoir characterization, target selection, and well trajectory design technologies are inadequate for the precise delineation of ultra-deep fault-controlled fractured-vuggy systems and high-yield well trajectory optimization. Through comparative analysis of the internal structural characteristics and seismic response variations of different regions and different types of strike-slip fault zones, integrated with actual well seismic calibration statistics and forward modeling, this study established a robust seismic identification model for high-yield and stable production wells. This model, based on the "source-connected faults + bead-string + deep chaotic high-amplitude background", provided a systematic framework for reservoir prediction and target selection. The Q-compensation seismic data processing technology developed through research improved the imaging resolution of fault-controlled fractured-vuggy systems in low signal-to-noise ratio seismic data under desert environments. Based on this, a reservoir quantification sculpting and target spatial positioning technology, centered on "facies-constrained inversion, " was established, which improved the accuracy of fault-controlled reservoir description and the precision of target selection. In response to the complex geological conditions of the overlying strata and Ordovician target layers in the Shunbei area, as well as challenges such as loss, overflow, and wellbore collapse during drilling, a key integrated geological engineering technology process focused on drilling risk prediction was established. This process included methods for optimizing well trajectories, selecting well locations, predicting formation pressures before drilling, and predicting wellbore stability, which improved drilling safety and efficiency. Drilling results from Shunbei's No. 4 and No. 8 fault zones indicated that the target selection and design technology for fault-controlled reservoirs could accurately identify and predict ultra-deep heterogeneous fractured-vuggy body targets, guide and optimize drilling trajectory design, avoid and reduce engineering risks along the drilling path, and improve the drilling success rate and high-yield well construction rate for large-scale reservoirs.
Main controlling factors and genesis models of reservoir development in Lower Paleozoic of Qingyang paleo-uplift, Ordos Basin
CHEN Zhaobing, PANG Tianyi, HAO Zekun, SONG Wei, YANG Kerong, MENG Fengming, GAO Jianrong, DUAN Chenyang
2025, 47(3): 490-503. doi: 10.11781/sysydz2025030490
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In recent years, significant progress has been made in exploring the Lower Paleozoic deep natural gas of the Qingyang paleo-uplift in the southwestern Ordos Basin. However, the reservoirs in this region are generally tight, and the formation mechanisms of high-quality reservoirs are complex, making sweet spot prediction difficult. Based on drilling, logging, and seismic data, as well as experimental test data, this study analyzed the reservoir development types and main controlling factors of the gas-bearing layers, including the Cambrian Zhangxia Formation and Sanshanzi Formation, and the second and fourth members of the Ordovician Majiagou Formation (Ma 2 and Ma 4). A genesis model of the Lower Paleozoic reservoirs in the Qingyang paleo-uplift was established. Four types of reservoirs were developed in the region: dolomite reservoirs, shoal reservoirs, karst reservoirs (supergene karst and fault-karst reservoirs), and structural micro-fracture reservoirs. Among them, the Sanshanzi Formation as well as the Ma 2 and Ma 4 members mainly featured dolomite reservoirs, while shoal reservoirs dominated the Zhangxia Formation. Karst reservoirs and structural micro-fracture reservoirs were developed across all layers. The controlling effect of sedimentary facies belts, weathered crusts, and faults on the development of Lower Paleozoic reservoirs in the Qingyang paleo-uplift was significant. Sedimentary facies belts controlled the development of intergranular (dissolution) pores in shoals and intercrystalline (dissolution) pores in dolomite. Two phases of weathered crusts controlled the development of supergene karst reservoirs, with the weathered crusts at the top of the Ordovician being the most influential. Karst residual hills controlled the planar distribution of strong dissolution areas. The vertical dissolution intensity and gas content of reservoirs were closely related to their distance from the top of the weathered crust. Faults controlled the distribution of fault-karst reservoirs, and their associated micro-fractures effectively improved the reservoir properties. Based on these findings, four reservoir genesis models, including shoal-fault type, residual hill-fault type, dolomite-karst type, and dolomite-fault type, were established, providing insights into the exploration of the Lower Paleozoic natural gas in the Qingyang paleo-uplift.
Shale sedimentary environments and their controlling factors in Lianggaoshan Formation of Fuxing area, Sichuan Basin
YANG Shufan, SHI Wenbin, LIU Zhujiang, CHEN Chao, WANG Daojun, LIU Xiaojing, AO Mingchong
2025, 47(3): 504-516. doi: 10.11781/sysydz2025030504
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Taking the shale in the second member of the Jurassic Lianggaoshan Formation (Liang 2) in the Fuxing area of the Sichuan Basin as the research object, this study employed geochemical and sedimentary analysis to systematically investigate the paleoenvironmental characteristics of the shale in the study area during the sedimentary period and their controlling effects on shale quality. Sedimentary models for the shale were established. The results showed that the shale in the Lianggaoshan Formation was deposited in a freshwater to brackish water environment with a paleo-water depth of 4.9 to 39.4 m, averaging 17.2 m. The paleo-productivity level was high with an average bio-barium content of 567.24 μg/g. The overall environment was anaerobic and reducing, and the climate was warm and humid in general. The total organic carbon (TOC) content of the shale in the Lianggaoshan Formation was controlled by paleo-water depth, paleosalinity, paleoproductivity, and paleo-water redox environment. Higher TOC content was positively correlated with water depth, salinity, productivity, and warm and humid climate. Under redox conditions, minor differences in reducing environments had little impact on TOC content. During the sedimentary period of the lower sub-member of Liang 2, the upper gas layers had a deeper water body, higher paleoproductivity, and a warmer, more humid paleoclimate compared to the lower gas layers, resulting in richer organic matter accumulation. Based on these findings, two types of shale sedimentary models were established for shale in the lower sub-member of the Liang 2 in the study area: (1) As the lower gas layers deposited, under freshwater to brackish water, semi-humid to semi-arid climate, moderate paleoproductivity, and anaerobic-reducing conditions, fair to medium-quality shale was mainly deposited. (2) As the upper gas layers deposited, under freshwater to brackish water, warm and humid climate, moderate to high paleoproductivity, and anaerobic-reducing conditions, medium to high-quality shale was primarily deposited.
New insights into Cretaceous hydrocarbon accumulation and its significance for hydrocarbon exploration in Hashan area, northwestern margin of Junggar Basin
QU Yansheng, ZHONG Ningning, WANG Shengzhu, WANG Bin, YU Hongzhou, ZHOU Jian, WU Qianqian, LU Hongli
2025, 47(3): 517-529. doi: 10.11781/sysydz2025030517
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To address the challenges in understanding the ambiguous hydrocarbon accumulation patterns and improving the exploration effectiveness in the Cretaceous system of the Hashan area along the northwestern margin of the Junggar Basin, this study aims to delineate the differences in hydrocarbon accumulation models between the Cretaceous and the Jurassic, identify the key controlling factors for Cretaceous hydrocarbon enrichment, and expand exploration in basin-margin overlapping zones. By integrating data from rock cores, thin sections, biomarker compounds, and fluid inclusions, a multidisciplinary geological and geochemical method was employed to conduct systematic studies on oil and source correlation, hydrocarbon migration pathways, and transport system configurations. Key investigations focused on source rock characteristics, crude oil properties, accumulation stages, and the coupling relationship between strike-slip faults and sand bodies. A Cretaceous accumulation model was established and validated through 3D seismic interpretation and drilling data. The study found that: (1) Oil source differentiation: Cretaceous crude oils originated from alkaline-saline lithofacies of the Permian Fengcheng Formation in the Hashan Sag, characterized by C28/C29 sterane ratios of 0.6 to 1.1 and gammacerane/C30 hopane ratios of 1.58 to 2.02. Jurassic oils were mainly derived from brackish dolomitic lithofacies. (2) Transport systems: Cretaceous accumulation was controlled by a strike-slip fault-lobate sand body dual transport mechanism. Strike-slip faults (e.g., Haqian 23 to Haqian 34 faults) vertically connected deep hydrocarbon source rocks with shallow sand bodies (porosity greater than 20% and permeability greater than 200×10-3 μm2), forming seven oil-bearing layers. In contrast, Jurassic reservoirs were predominantly controlled by lateral "fault-blanket" type transport mechanism. (3) Accumulation stages: Homogenization temperatures of inclusions (110 to 140 ℃) and aromatic maturity parameters (Rc=1.21%-1.56%) indicated that the Cretaceous experienced a single-phase, high-maturity hydrocarbon charging, whereas the Jurassic underwent a mixed dual-phase charging. Based on these, several oil-bearing blocks, such as Haqian 23 to Haqian 10, have been identified, and the northern region of Haqian 24 is predicted to hold 45 million tons of reserves. The Cretaceous system is projected to develop a 50-million-ton exploration target. Breaking from the traditional "fault-blanket" theory, this study proposes a new transport mechanism of near-source vertical supply coupled with strike-slip faults and lobate sand bodies for the Cretaceous hydrocarbon accumulation. The inherent spatial configuration of efficiently conductive strike-slip faults and sand bodies distributed along grooves is critical for reservoir formation. The new theory redirects exploration focus from isolated targets toward regional-scale accumulation zones, significantly expanding the exploration potential along the northwestern margin of the Junggar Basin.
Differential characteristics and main controlling factors of hydrocarbon enrichment in Pinghu Slope, Xihu Sag, East China Sea Basin
GUO Gang, SU Shengmin, XU Jianyong, LIAO Jihua, LI Linzhi, LI Feng
2025, 47(3): 530-540. doi: 10.11781/sysydz2025030530
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The Pinghu Slope in the Xihu Sag of East China Sea Basin exhibits significant hydrocarbon exploration potential, characterized by strong heterogeneity in its enrichment patterns. Investigating the differential enrichment characteristics and their main controlling factors can offer a theoretical basis for oil and gas exploration in the Xihu Sag and similar areas. To this end, the study thoroughly examined typical hydrocarbon reservoirs and analyzed logging, seismic, and physical property testing data. It investigated the differences in enrichment and layer distribution of hydrocarbons in the Pinghu Slope and identified their influencing factors. The findings indicated a gradual decrease in hydrocarbon enrichment from the southern zone to the northern zone of the Pinghu Slope. Structural and lithologic as well as faulted anticline hydrocarbon reservoirs exhibited higher enrichment than faulted noses and fault block reservoirs. The hydrocarbon-enriched layers were classified into three types: multilayer enrichment in the Pinghu and Huagang formations, enrichment in the middle and upper sections of the Pinghu Formation, and enrichment in the lower and middle sections of the Pinghu Formation. The differential hydrocarbon enrichment in the study area was controlled by hydrocarbon supply distance, reservoir conditions, trap conditions, and fault sealing ability. Specifically, the hydrocarbon supply distance mainly controlled the differences in enrichment between different structural zones and reservoir types, while the differences in hydrocarbon enrichment between reservoirs of the same types were also influenced by reservoir conditions, trap conditions, and fault sealing ability. Shorter hydrocarbon supply distances, greater effective reservoir thicknesses, larger trap areas, and stronger fault sealing ability led to higher hydrocarbon enrichment. The vertical distribution of the hydrocarbon enrichment was influenced by fault transport capacity as well as fault and caprock configuration. When the fault's vertical transport capacity was robust and the residual sealing thickness exceeded the lower limit, hydrocarbons tended to accumulate in the middle and upper sections of the Pinghu Formation of the lower part of the regional caprock. In cases where the fault had a strong vertical transport capacity and had completely broken the caprock in the Pinghu Formation, hydrocarbons accumulated in both the Pinghu and Huagang formations. Conversely, when the fault transport capacity was weak, hydrocarbons mainly accumulated in the lower and middle sections of the Pinghu Formation. By focusing on the hydrocarbon supply distance, reservoir conditions, fault transport capacity, and fault and caprock configuration, this study provides a basis for determining the differences in hydrocarbon enrichment and identifying oil and gas enrichment strata in the Xihu Sag and similar areas.
Microscopic pore structure characteristics and mobility of shale oil reservoirs in Liushagang Formation, Weixinan Sag, Beibu Gulf Basin
YOU Junjun, HU Desheng, YUAN Zhenzhu, ZHOU Gang, JIANG Li
2025, 47(3): 541-551. doi: 10.11781/sysydz2025030541
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Shale oil reservoirs are characterized by tightness and strong heterogeneity, and the microscopic pore structures affect the storage and flow of shale oil in reservoirs. However, conventional single analytical methods often fail to accurately characterize these microscopic pore structures. This study aims to reveal the microscopic pore structure and mobility characteristics of shale oil reservoirs, thereby guiding efficient exploration and development of offshore shale oil. Three types of shale oil reservoirs—matrix-type, laminated-type and interbedded-type—in the Liushagang Formation, Weixinan Sag, Beibu Gulf Basin were selected as the research objects. Integrated analytical and testing methods were employed, including cast thin-sections, scanning electron microscopy, high-pressure mercury intrusion, nitrogen adsorption, and nuclear magnetic resonance, to analyze pore structure parameters, mercury intrusion morphology, and adsorption curve characteristics. The results showed that the matrix-type and laminated-type reservoirs exhibited finer grain sizes and relatively underdeveloped pores, dominated by slit-shaped pore morphologies. These reservoirs commonly featured bedding fractures, organic pores, interlayer pores within clay minerals, and intercrystalline pores within pyrite. The interbedded-type reservoirs mainly had ink-bottle-shaped pore morphologies, along with intergranular pores within mineral particles, dissolution pores, and fracture networks, showing good pore size distribution and reservoir connectivity. Analysis of shale oil mobility through fluorescence thin sections and nuclear magnetic resonance revealed that the matrix-type and laminated-type reservoirs exhibited relatively poorer mobility, with movable porosities of 0.72% and 4.62%, respectively, along with lower movable oil content. The interbedded-type reservoir exhibited a movable porosity of 6.37%, with lighter hydrocarbon components, better mobility, and higher movable oil content, making it the most favorable reservoir type for shale oil exploration in the Weixinan Sag.
Selection of favorable shale lithofacies based on an integrated geology and engineering approach: a case study of Lishu Fault Depression in Songliao Basin
LIN Xuan, ZHU Jianfeng, PANG Haiming, LI Zhongbo, WANG Wei, LIU Shuo, LI Haibin, JIANG Zhenxue, LI Zhuo, QIN Chunyu, CHEN Kangbo
2025, 47(3): 552-568. doi: 10.11781/sysydz2025030552
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The Lishu Fault Depression in the Songliao Basin holds significant potential for shale gas exploration and development. This study took the shale in the Yingcheng Formation of the Lishu Fault Depression as the research subject. A series of experiments, including total organic carbon (TOC) content measurement, rock pyrolysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), and small-scale hydraulic fracturing physical simulations, were conducted to identify the most favorable shale lithofacies based on an integrated geology and engineering approach. The results indicated that the study area exhibited a high content of clay and carbonate minerals, with well-developed dissolution pores in carbonates and a complex fracture system. The seepage mechanisms of the shale reservoirs included desorption and adsorption, diffusion, slippage flow, and Darcy flow. Small-scale hydraulic fracturing experiments revealed that clay rock content significantly influenced fracturing performance. Specifically, clay-rich lithofacies exhibited low fracture pressure peaks, rapid fracturing pressure declines, and an inability to form transverse fractures. Vertical and bedding-parallel lamellated fractures mostly developed, resulting in poor fracturing efficiency. Through analyzing multi-scale pore structures and reservoir permeability, the study found that shale reservoirs in the study area primarily developed mesopores, which enhanced pore connectivity and volume. These mesopores were also the main contributors to the improved specific surface area and served as the primary channels for fluid seepage. Therefore, slippage flow was identified as the predominant seepage mechanism in the study area. High clay content significantly affected fracturing efficiency. Mixed lithofacies with lower clay content and well-developed dissolution pores demonstrated superior artificial fracture propagation and enhanced permeability after fracturing modification. The most favorable lithofacies in the study area were identified as the organic-rich laminated calcareous mixed shale and the organic-rich laminated siliceous mixed shale. After implementing the integrated geology and engineering production approach in well X-A, shale gas production increased substantially. These findings provide important theoretical support and practical guidance for optimizing shale gas exploration and development in the study area.
Research progress and challenges in thermal maturity evalution of Lower Paleozoic source rocks
ZHENG Xiaowei, JIANG Fujie, ZHANG Yu, ZHOU Jingqi
2025, 47(3): 569-579. doi: 10.11781/sysydz2025030569
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Marine source rocks in China's Lower Paleozoic are predominantly in the highly to over-mature stage. The lack of vitrinite in these strata has made thermal maturity evaluation a persistent technical challenge in deep hydrocarbon exploration. This study systematically summarizes organic matter maturity evaluation methods based on organic petrology, geochemistry, and spectroscopy, with the goal of assessing the applicability of various maturity parameters for highly to over-mature source rocks in the Lower Paleozoic, thereby providing insights for deep hydrocarbon resource exploration. Special emphasis is placed on analyzing graptolite reflectance, aromatic hydrocarbon molecular marker parameters, and Raman spectroscopy parameters, highlighting current challenges and future research directions. (1) Owing to its excellent thermal sensitivity, graptolite reflectance is extensively employed to characterize the maturity of Lower Paleozoic source rocks. Nevertheless, different graptolite types exhibit varying rates of reflectance increase, with "reflectance anomalies" observed within the gas window. (2) Aromatic hydrocarbon compounds (e.g., phenanthrene series and dibenzothiophenes) and their derived parameters (e.g., methylphenanthrene index MPI-1, and 4-MDBT/1-MDBT in methyldibenzothiophene) exhibit sensitive thermal stability responses, rendering them effective maturity evaluation parameters. However, their applicability might be constrained by the initial organic matter type and depositional environment. (3) Raman spectroscopy can effectively characterize molecular structure evolution and thermal maturity, through parameters derived from the D1 and G peaks. However, variations in laboratory instruments, wavelength selection, and spectral interpretation methods might limit comparability across studies. Finally, this study summarizes the theoretical foundations and practical applicability of these parameters, highlighting the impacts of mineral catalysis, radiation effects, and thermal simulation experiments on their suitability. The results demonstrate that a multi-parameter integrated approach significantly improves the accuracy of maturity evaluation. However, current calibration methodologies still require refinement to achieve optimal performance.
Thermal evolution trend of aromatic hydrocarbons in shales from Permian Dalong Formation in Sichuan Basin and its significance in thermal maturity
ZHANG Cunyang, ZHANG Xiaotao, LIU Yan, YANG Jiajia, SUN Weilin, SHEN Bin, XU Xuemin, XU Zhichao, TIAN Tao
2025, 47(3): 580-592. doi: 10.11781/sysydz2025030580
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The Paleozoic marine shales in southern China hold great significance for hydrocarbon exploration. However, the lack of organic matter (vitrinite) derived from higher plants in marine sediments leads to considerable uncertainties in maturity assessment. In this paper, an thermal simulation experiment of hydrocarbon generation and expulsion for the Permian Dalong Formation shales in Guangyuan, Sichuan Basin was conducted to explore the applicability of aromatic maturity parameters in highly mature to over-mature stages. Analysis of the aromatic hydrocarbon extracts from the solid samples after thermal simulation was performed using gas chromatography-mass spectrometry (GC-MS). The results revealed that the thermal simulation residual oil from Dalong Formation shales in Shangsi section, Guangyuan area, Sichuan, contained abundant aromatic hydrocarbon compounds, including naphthalene, phenanthrene, chrysene, benzo(a)anthracene, dibenzothiophene, biphenyl, dibenzofuran, fluorene, fluoranthene, pyrene, anthracene, and triaromatic steranes. Most aromatic maturity parameters exhibited turning points with increasing thermal simulation temperatures, and the parameter values showed different trends before and after the turning points, indicating that these parameters have specific applicable ranges. Among them, aromatic maturity parameters (such as MNR, DNR, MPI3, DPR, F1, F2, MDR and DBDBT2) can be used to evaluate the maturity of shales at mature to highly mature stages (0.8% < Easy Ro < 2.5%), while PMNr is more suitable for evaluating high to over-mature shales (2.5% < Easy Ro < 4.5%). It was found that the parameters of C-2 DBF-1/MDBF-1 and C-2 DBF-2/MDBF-1 are effective for evaluating shales at mature to over-mature stages (0.8% < Easy Ro < 4.5%), showing a stronger correlation with temperature in the high-temperature evolution stages. This suggests their potential for assessing high to over-mature shales.
Characteristics and indication of hydrocarbon-generating organisms in sub-salt Majiagou Formation of well T112, central and eastern Ordos Basin
ZHANG Yinuo, ZHANG Dongdong, WEI Liubin, LIU Wenhui, SHI Pingping, WANG Xiaofeng, ZHANG Qian, LI Yining, JIN Zhicheng
2025, 47(3): 593-605. doi: 10.11781/sysydz2025030593
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In recent years, breakthroughs in natural gas exploration have been continuously achieved in the Ordovician Majiagou Formation of the central and eastern Ordos Basin, with geochemical characteristics of self-generation and self-storage. However, there are still controversies surrounding the evaluation of carbonate hydrocarbon source rocks in the Majiagou Formation, characterized by low organic matter abundance and high thermal evolution. Research on hydrocarbon-generating organisms can provide new perspectives and methodologies for assessing the hydrocarbon potential and source environments of these rocks. The study analyzed the core samples from the Majiagou Formation of the well T112 in the Ordos Basin using optical microscopy, scanning electron microscopy, and geochemical analyses. The results revealed various types of hydrocarbon-generating organisms with vertical distribution differences. These organisms primarily included planktonic algae, benthic algae, animal organic debris, and mineral-bituminous groundmass. Different assemblages of these organisms were observed across various members of the Majiagou Formation. The fifth member (Ma 5 member) contained more planktonic algae, the fourth member (Ma 4 member) was dominated by benthic algae, and the third member (Ma 3 member) predominantly contained mineral bituminous groundmass. Geochemical data indicated higher total organic carbon (TOC) content in the Ma 3 and Ma 5 members, with minimal variations in organic carbon isotope compositions. Carbon and oxygen isotopes in the Ma 3 member are generally lighter. Comprehensive analysis suggested that the sedimentary environments in the Ma 3 and Ma 5 members were favorable for the development of hydrocarbon-generating organisms. The high TOC values in these members were associated with planktonic algae, while saline environment, terrigenous inputs, and restricted marine sedimentary facies were the primary controlling factors on phytoplankton development. Moreover, negative drifts in inorganic carbon isotopes indicated that large-scale hydrocarbon generation events have occurred in the Majiagou Formation, suggesting that its carbonate rock sequences might be an effective hydrocarbon source for oil and gas accumulation.
Quality and oil-bearing properties of argillaceous hydrocarbon source rocks across different lithofacies of Permian Lucaogou Formation in Jimsar Sag, Junggar Basin: a case study of well J10025
HE Jinyi, LENG Junying, HE Wenjun, LI Zhiming, LIU Deguang, YANG Sen, LI Chuxiong
2025, 47(3): 606-620. doi: 10.11781/sysydz2025030606
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The study on the quality and oil-bearing properties of argillaceous hydrocarbon source rocks across different lithofacies is crucial for understanding shale oil enrichment patterns and predicting sweet spots. 57 mudstone samples from the Permian Lucaogou Formation in the well J10025 of the Jimsar Sag, Junggar Basin were selected in this study. Based on lithofacies classification, the quality and oil-bearing properties of those argillaceous hydrocarbon source rocks across different lithofacies were systematically investigated through X-ray diffraction (XRD), thin-section observation, rock pyrolysis, organic petrology, vitrinite reflectance (Ro) measurement, and multi-temperature pyrolysis. The results indicated that 7 lithofacies were predominantly developed in the Lucaogou Formation of the Jimsar Sag, including massive felsic mudstones, massive calcareous mudstones, massive dolomitic mudstones, laminated felsic mudstones, laminated calcareous-bearing mudstones, laminated calcareous mudstones, and laminated dolomitic mudstones. Distinct quality differences were observed in those source rocks. The massive felsic mudstones and massive calcareous mudstones exhibited poor quality, while massive dolomitic mudstones were moderate-quality source rocks. The laminated felsic mudstones demonstrated good quality, whereas laminated calcareous-bearing mudstones, laminated calcareous mudstones, and laminated dolomitic mudstones were high-quality hydrocarbon source rocks. The massive dolomitic mudstones exhibited relatively favorable oil-bearing capacity and mobility, making them potential sweet spot lithofacies. In the well J10025, mudstones with relatively good oil-bearing properties were deposited at depth intervals of approximately 3 500 to 3 570 m and 3 700 to 3 750 m. However, its overall poor mobility restricted the development of the mudstone-type shale oil sweet spots. The main factors influencing the oil-bearing capacity and mobility of mudstones included hydrocarbon-generating capacity, hydrocarbon expulsion efficiency, and total organic carbon (TOC) content. The content of free hydrocarbons was significantly controlled by the hydrocarbon-generating capacity of mudstones. Meanwhile, the widespread efficient hydrocarbon expulsion in mudstones directly led to a reduction of free oil content. Additionally, high TOC content resulted in a large amount of adsorbed oil, which constrained shale oil mobility.
Oil and source correlation and its geological significance of Fengcheng 1 well block in Wuxia fault zone, Junggar Basin
LIU Guanbo, CHEN Shijia, HE Wenjun, ZHANG Yangyang
2025, 47(3): 621-633. doi: 10.11781/sysydz2025030621
Abstract(18) HTML (4) PDF-CN(7)
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As the conventional oil and gas exploration in the Wuxia fault zone of the western uplift of the Junggar Basin enters its later stages, great breakthroughs have been made in shale oil exploration of the Lower Permian Fengcheng Formation in the past two years. In the process of exploring the accumulation patterns of conventional and shale oil reservoirs in the Fengcheng Formation, it was found that previous understanding of the oil sources in Fengcheng 1 well block was inaccurate. Earlier researchers believed that crude oil in this well block was solely derived from the source rocks of the Fengcheng Formation. To reevaluate this understanding, various organic geochemical data from Permian source rocks and crude oil in existing exploration wells of this area were systematically analyzed. By applying the geochemical oil and source correlation theory and petroleum geology theory, and using chromatography, chromatography-mass spectrometry, and carbon isotope data from source rocks and crude oil, the study reexamined the oil sources in various oil-producing formations in the well block, combined with single-well simulations of source rock thermal evolution history. The results showed that the lower gray-black and black mudstone section of the Lower Permian Jiamuhe Formation, with a thickness of approximately 95 m, had a sedimentary environment and parent material type similar to those of the Fengcheng Formation. However, the parent material type in the Jiamuhe Formation was relatively more humic, with higher organic matter abundance, making it a highly mature humic type, good to high-quality source rocks. The mature crude oil in the upper part of the first member of the Fengcheng Formation in Fengcheng 1 well originated from the source rocks of the Fengcheng Formation. The highly mature crude oil in the two lower oil layers and the Jiamuhe Formation oil layer in Fengcheng 011 well mainly sourced from the source rocks of the Jiamuhe Formation, with a small contribution from the source rocks of the Fengcheng Formation, rather than exclusively from the source rocks of the Fengcheng Formation. It is speculated that the source rocks of the Jiamuhe Formation have a wide spatial distribution range and can provide substantial oil and gas resources for conventional oil and gas accumulation in the Wuxia fault zone. Therefore, it is recommended to strengthen the research on the thickness distribution of source rocks of the Jiamuhe Formation in this area, providing a basis for identifying new oil and gas exploration fields.
Quantitative fluorescence techniques and their applications in shale oil reservoir research: a case study of Permian Fengcheng Formation in Mahu Sag, Junggar Basin
JIANG Chengzhou, WANG Guiwen, SONG Lianteng, HUANG Liliang, WANG Song, ZHANG Yilin, HUANG Yuyue, FAN Xuqiang
2025, 47(3): 634-644. doi: 10.11781/sysydz2025030634
Abstract(19) HTML (3) PDF-CN(7)
Abstract:
The shale oil reservoirs of the Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin are characterized by a source and reservoir integration. Their formation process is affected by various factors, including sedimentation, diagenesis, and organic matter evolution, resulting in highly complex source rock properties and reservoir characteristics. Currently, the effects of inorganic mineral development and organic matter evolution on reservoir and shale oil properties remain unclear. To address these issues, this study extends the application of quantitative fluorescence (QF) techniques, which are widely used in conventional reservoir research, to continental shale oil reservoirs. Techniques such as quantitative grain fluorescence on extract (QGF-E) and total scanning fluorescence (TSF) were utilized. By combining QGF-E analysis and rock pyrolysis, it was found that free hydrocarbon (S1) was positively correlated with QGF-E intensity, and their variation range was significant. This indicated that oil saturation was mainly controlled by S1. Under the same testing conditions, the normalized TSF spectra's maximum intensity and two-dimensional nuclear magnetic resonance (2D NMR) experimental results showed that the differences in shale oil density (API gravity) were related to the adsorption of hydroxyl-rich heavy organic matter by clay minerals. Higher clay mineral content was found to adsorb more organic matter. The crude oil maturity index (R1) further indicated that the differences in bio-precursors under the original depositional environment and the variations in pore types and structures after diagenetic alteration were key factors affecting the properties of shale oil in the reservoir. These analytical techniques and methods serve as a bridge connecting different parameters, facilitating a deeper understanding of the characteristics of the shale oil reservoir and providing valuable references for the exploration and development of unconventional oil and gas resources.
Quantitative characterization of adsorbed and free shale oil microscopic distribution based on nuclear magnetic resonance: a case study of Chang 7 member of Triassic Yanchang Formation in Ordos Basin
LIU Fei, DU Jinliang, SUN Lin, GUO Ruiliang, HAO Bofei, LIU Peng
2025, 47(3): 645-658. doi: 10.11781/sysydz2025030645
Abstract(16) HTML (5) PDF-CN(9)
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Quantitative evaluation of shale oil occurrence states and mobility is a key and challenging issue in current shale oil geological research. Taking the shale from the seventh member of the Triassic Yanchang Formation (Chang 7 member) in the Ordos Basin as the research object, this study combined nuclear magnetic resonance (NMR) experiments with saturation-centrifugal tests, using the shale oil adsorption ratio equation proposed by previous research. It conducted a comprehensive study on the adsorbed and free oil amount, ratio, microscopic distribution, and mobility characteristics of shale oil. The results showed that under conditions of saturation with n-dodecane and centrifugation at 20 ℃, the average amounts of free oil and adsorbed oil in shale of the Chang 7 member were 1.981 4 mg/g and 1.548 1 mg/g, respectively. The average proportion of adsorbed oil was 0.430 7. The average density ratio between the adsorbed and free phases of shale oil was 1.171 3, the average density of adsorption phase was 0.877 8 cm3/g, and the average thickness of the adsorption layer was 0.980 2 nm. Adsorbed oil mainly exist in micropores (< 100 nm), and the amount of free oil in micropores, mesopores, and macropores sequentially decreases. Organic-matter-rich shale generally contain higher amount of free oil and lower amount of adsorbed oil due to the existence of hydrocarbon generation-induced microfractures and less developed organic pores. Quartz-related pores significantly increase the specific surface area of pores, thus providing more occurrence sites for adsorbed oil, whereas an increase in clay mineral content significantly reduces the pore volume available for free oil. The ratio of free oil amount (Qf) to median centrifugal force (ΔPL) is identified as a new and effective parameter for evaluating shale oil mobility. Higher ratio indicates better shale oil mobility. For shale in Chang 7 member, Qf/ΔPL=1.339 4 mg/(g·MPa) represents the threshold at which shale oil mobility undergoes a significant change. Above this threshold, the shale oil mobility significantly improves. The lower limit of theoretical pore size of free oil, calculated using the adsorption ratio equation, is between 1.960 4 nm and 5.881 2 nm, and the specific size is related to pore morphology.
Discussion on key technologies in micro-CT experiments and their applications in oil and gas exploration
HUANG Xiangsheng, LUO Chengfei, ZHANG Qun, CHEN Jinding, ZHANG Yaoyuan, LIU Xiaowen
2025, 47(3): 659-670. doi: 10.11781/sysydz2025030659
Abstract(27) HTML (6) PDF-CN(11)
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Micro-CT technology has been widely applied in oil and gas exploration and development. However, unified standards for key control parameters and data processing methods have yet to be established, significantly affecting data accuracy and comparability. To systematically study the impact of micro-CT experimental parameters on test results, seven representative samples from the Beibuwan Basin and the Yinggehai Basin in the South China Sea were used as the research subjects. The research focused on the impact of scanning resolution, representative volume element (RVE) size, and data processing methods on experimental outcomes. The findings indicated that: (1) A fixed scanning resolution is a key factor in ensuring data reliability, as it significantly affects the extraction of pore structure parameters and subsequent analysis. Resolution should be optimized considering sample size and lithological characteristics. (2) For characterizing the porosity of sandstone samples, better result accuracy can be achieved by increasing the RVE size. While constructing pore network models, the RVE size should be no smaller than 600×600×600 voxels to ensure model representativeness. (3) Use interval-based statistics to calculate the cumulative volume frequency of pore diameters (Φ), and plot the pore size distribution curves. Use the volumetric method to calculate the average pore diameter. These methods can provide a more accurate characterization of rock pore structure. The study offers theoretical support for the application and workflow optimization of micro-CT technology in oil and gas exploration, providing a reference for establishing experimental standards.
Microscopic seepage process of gas and water in fractures of tight reservoirs
HOU Shiwei, LÜ Xunqing, MENG Suyun, ZHANG Hao, DU Xiuli
2025, 47(3): 671-679. doi: 10.11781/sysydz2025030671
Abstract(15) HTML (3) PDF-CN(2)
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To investigate the dynamic seepage mechanisms of fluids within fractures of tight reservoirs, a three-dimensional digital core fracture structure of an actual reservoir was constructed based on deep learning segmentation results. First, the fracture connectivity was evaluated. Then, single-phase flow permeability simulation was conducted, and gas-water two-phase flow displacement was studied using a level-set method coupled with Navier-Stokes (N-S) equations, with solutions obtained using the finite element method. The results showed that the deep learning method efficiently and automatically segmented fractures in core images with an accuracy of 85%. Connected fractures played an important role in rock permeability. Different fluid properties affected flow pressure and velocity, thereby affecting permeability. During the displacement simulation, the distribution characteristics of gas and water phases were clearly observed. As the displacement progressed until seepage completion, the fluid saturation in narrow fracture channels remained nearly unchanged, serving as the primary storage space for residual gas phase. Fractures with relatively good connectivity, characterized by great width and straightness, became the main seepage channels where gas recovery rates tended to stabilize. The research findings provide guidance for studying gas-water two-phase flow in fracture spaces of tight reservoirs under microscopic conditions.
Reservoir connectivity of offshore oilfields with a sparse well pattern: a case study of the third member of Weizhou Formation of oilfield A in Weixinan Sag, Beibuwan Basin
ZHU Jinqi, YANG Zhaoqiang, YANG Yan, CHEN Kui, FU Tao
2025, 47(3): 680-692. doi: 10.11781/sysydz2025030680
Abstract(15) HTML (3) PDF-CN(2)
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To address the prominent injection and production contradiction, complex remaining oil distribution, and utilization issues in the third member of the Weizhou Formation (W3) of oilfield A in the Weixinan Sag, Beibuwan Basin, the study developed a comprehensive reservoir configuration characterization system for offshore oilfields with a sparse well pattern, involving reservoir configuration interface classification, anatomy of composite sand body, and quantitative characterization of reservoir configuration unit. The reservoir connectivity was studied, aiming to optimize production strategies in the area. Vertically, the different oil groups in the third member of the Weizhou Formation in oilfield A could be divided into 3 to 4 monogenetic sand bodies. For lateral characterization, the study integrated multiple approaches, including reservoir contact pattern analysis, sand body scale constraints, well and seismic combination, and dynamic verification of production data to obtain the reservoir configuration profiles of different injection and production wells in the same period. Combined with variations in sedimentary microfacies of different oil groups and the positive correlations between the thickness and width of subaqueous distributary channels, the reservoir configuration unit of the third member of the Weizhou Formation in oilfield A was further quantitatively characterized. Based on that, the lateral and vertical connectivity of W3ⅣD and W3ⅣE oil groups in the main development layers of oilfield A was analyzed. Profile characterization of the W3ⅣD oil group showed that the subaqueous distributary channel sand bodies were vertically superimposed with moderate inter-channel sand body continuity and overall good lateral connectivity. Planar analysis showed that the river channels in the southwest provenance direction swung slightly with significant scale variations. Small-scale mouth bars were locally developed. The river channels in the northeast provenance direction were relatively straight with few scale variations. For W3ⅣE oil groups, the northern wells showed rapid changes in vertical sedimentary microfacies of single well and sand body thickness between wells, with moderate sand body continuity. The southern wells generally exhibited weaker connectivity. Planar studies revealed evident swings of river channels in the southwest provenance direction and well-developed mouth bars. The river channels in the northeast provenance direction were relatively straight, and the interdistributary bays were more developed.
Influencing factors and prevention optimization of shallow shale gas inter-well frac-hits
JIANG Ming, ZOU Qingteng, XIAO Zhuang, WANG Yong, GE Jingnan, CHEN Zhao
2025, 47(3): 693-704. doi: 10.11781/sysydz2025030693
Abstract(9) HTML (2) PDF-CN(2)
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The Zhaotong shallow shale gas field is the first pilot demonstration area in China for medium to shallow shale gas development, with main burial depths ranging from 1 000 to 2 200 m. Due to asynchronous production and infrastructure construction and a small horizontal stress difference in the regional fault system, inter-well interference frequently occurs during the fracturing of new wells. This presents a series of problems such as extensive frac-hits and difficulty in restoring production. The frac-hits between fractured wells and producing wells are mainly characterized by fast response, difficult production recovery, and multiple occurrences. Statistical analysis of affected wells showed that the longer the production time, the lower the recovery rates after the implementation of frac-hits control measures. To address these challenges, it is imperative to analyze the influencing factors of inter-well frac-hits and propose preventive measures. The study comprehensively reviewed the dynamic and static parameters under the engineering and geological conditions from 32 wells experiencing frac-hits in the Zhaotong shallow shale gas field. A random forest model was trained to evaluate the influence of geological and engineering parameters on frac-fits. The main controlling factors were identified as well spacing, construction intensity, and the production time of the parent well. Numerical simulations suggested an optimal parent-child well spacing of 450 m. Orthogonal design simulations revealed that parent wells consistently suffered negative interference after experiencing frac-hits, with the interference ratio increasing from 6.3% to 35% as the production time extended. When the parent-child well spacing exceeded 400 m within the first year of parent well production, child wells experienced positive interference, and the interference degree ranging from 2.5% to 8.6% as well spacing increased. The proposed well spacing optimization strategy supports well location deployment and fracturing parameter optimization in the Zhaotong shallow shale gas field, validating the research results.

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