Oil & Gas Geology-2025, Volume 46 Issue 6

Current status， challenges， and future trends of the classification and grading evaluation of lacustrine shale oil in China

Xusheng GUO, Peirong ZHAO, Yu ZHANG, Baojian SHEN, Qianwen LI, Pei LI, Xiong LI, Keran QIAN, Shengjuan CAI, Xiaoxiao MA, Peng LI

2025, 46(6): 1745-1761. doi:10.11743/ogg20250601

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Scientific classification and grading evaluation provide a theoretical foundation and key prerequisite for the cost-effective development of lacustrine shale oil in China. Based on a systematic literature review， along with comprehensive investigation and judgement， we present a thorough summary of advances in research on the classification and grading evaluation of lacustrine shale oil in China， andidentify core challenges and future trends. The evolutionary path and inherent logic of the shale oil classification system are clarified. Furthermore， we elaborate high dynamism and type-dependence of key parameter thresholds， and systematically compare the applicability and limitations of various evaluation methods ranging from multi-parameter overlay to machine learning， while focusing on the “four-property” parameter system consisting of reservoir properties， oil-bearing capacity， oil mobility， and fracability for shale oil evaluation. The analytical results reveal three major limitations in the current classification and grading evaluation. First， the classification schemes， in spite of diversity， lack a unified framework， leading to conceptual confusion and hindered popularization. Second， the evaluation parameters prove cumbersome and lack universal criteria， resulting in key parameter threshold significantly varying by basin and type， thus the absence of a unified understanding of the formation mechanisms of shale oil. Third， the disconnection between assessment methods with exploration and exploitation practices is manifested in the mismatches between geological and engineering sweet spots and broken links in the upgrade chain from resource volume to productivity. Currently， the lacustrine shale oil evaluation paradigm in China is shifting from static description to dynamic prediction and from a single geological dimension to a geological-engineering-economic multi-dimension synergy. Future efforts should be put into constructing a dynamic， full-lifecycle classification and grading assessment system by deepening the integration and applications of multi-source data and artificial intelligence （AI） technologies. Furthermore， it is necessary to thoroughly analyze typical calibration areas and develop industry standards， thus enhancing the standardization， precision， and cost-effective applications of the classification and grading evaluation of lacustrine shale oil in China.

Practices and reflection on reporting proved oil initially-in-place of shale layers by SINOPEC

Yu ZHANG, Jun LI, Feng WANG, Yong ZHANG, Min WANG, Wei SUN

2025, 46(6): 1762-1777. doi:10.11743/ogg20250602

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Shale oil represents a new frontier in both the conceptual revolution and technological breakthroughs for global hydrocarbon exploration while also serving as a new target for sustaining the energy security and maintaining stable hydrocarbon production in China. Shale layers have always been primarily assessed as source rocks previously， leading to a lack of feasible methods and practical bases for estimating their proved oil initially-in-place. To address this， guided by the Specification of Shale Layers Oil Reserves Estimation （DZ/T 0501—2025）， effective since January 2025， SINOPEC has achieved rational control over the oil-bearing area and net pay thickness of shale layers by relying on the optimized deployment of horizontal and vertical wells-directional wells. Besides， the company further leveraged innovative technologies， including two-dimensional nuclear magnetic resonance （2D NMR） analysis of shale cores， to accurately determine key parameters such as shale physical properties and oil-bearing characteristics. Accordingly， a set of scientifically robust and systematic methods for estimating proved oil initially-in-place of shale layers have been developed. Using these technologies， SINOPEC has successfully reported the first batch of 1.8 × 10⁸ t proved oil initially-in-place of shale layers in the Fanyeping 1 block， Jiyang Depression and the Chujialou block of the Qintong Sag. This achievement validated the accuracy and effectiveness of the proposed methods. Building on the proved oil initially in place declaration practice， SINOPEC has gained the following key insights into optimizing shale strata oil exploration and development： strengthening the integrated deployment of exploration and development， acquiring complete and accurate data for reserve assessment， iteratively upgrading reserve assessment methods， and deepening the classification and grading evaluation of oil reserves. These approaches contribute to the elevated quality and efficiency of reserve reporting. Through innovations in the reserve estimation methods and advances in hydrocarbon exploration and development models， SINOPEC has transformed the reporting of proved shale oil originally-in-place from a theoretical concept into a practical reality， providing a replicable technical pathway for the efficient exploration and development of similar oil reservoirs in China.

Distribution patterns and integrated exploration strategy for conventional and unconventional hydrocarbon resources

Zongquan HU, Zhenxiang SONG, Zhuoming ZHOU, Zhongliang MA, Guoqiao YANG, Chuan HE

2025, 46(6): 1778-1791. doi:10.11743/ogg20250603

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Evaluation of hydrocarbon resources provides a crucial strategic foundation for accurately quantifying resource potential， scientifically planning exploration activities， and safeguarding the national energy security. Since the implementation of China’s 14th Five-Year Plan， the hydrocarbon exploration in China has gradually shifted from focusing solely on conventional resources to placing equal emphasis on both conventional and unconventional resources. Based on advances in the theoretical understanding， techniques and methods， and practical applications of the integrated evaluation of conventional and unconventional hydrocarbon resources， we examine the configuration relationships and distribution patterns of these resources within the evaluation areas and map favorable exploration targets in major petroliferous basins of China， gaining considerable achievements. Specifically， an innovative integrated evaluation technique for conventional and unconventional hydrocarbon resources has been developed based on TSM basin modeling， overcoming the limitations of traditional evaluation methods. Accordingly， it has been proposed that understanding the differential evolutionary patterns of the hydrocarbon generation， retention， and expulsion of various source rocks is the key to integrated resource evaluation. The new technique reveals the genetic relationship and synergistic evolution process across the whole sequence of hydrocarbon resources， providing an important guidance for integrated resource evaluation and decision-making for resource exploration. What’s more， the overall resource structure manifests as a decrease in conventional original in-place resources alongside a substantial increase in unconventional original in-place resources. These characteristics result in a resource configuration featuring balanced proportions of oil and gas resources， along with stable conventional resources and increased unconventional resources. This analysis also confirms that major basins remain the primary domain for significant exploration breakthroughs. At last， given the discovery rates and distribution characteristics of hydrocarbon resources， the orderly progression from conventional to unconventional oil and gas provides a robust resource foundation for stabilizing oil production while increasing gas output （“stabilizing oil， increasing gas”）. Primary targets for future integrated exploration of conventional and unconventional hydrocarbon resources include the Paleogene strata of the Bohai Bay Basin， the Cambrian， Permian， and the Jurassic strata of the Sichuan Basin， and the Carboniferous-Permian and Triassic strata of the Ordos Basin.

Mechanisms of the differential enrichment and high productivity of deep to ultra-deep marine shale gas reservoirs

Tonglou GUO, Xiaoxia DONG, Limin WEI, Siqin HUANG, Shaoke FENG

2025, 46(6): 1792-1806. doi:10.11743/ogg20250604

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Deep to ultra-deep marine shale gas has emerged as an important target for shale gas exploration and exploitation in China. In this study， we reveal the mechanisms governing the differential enrichment and high productivity patterns of deep to ultra-deep shale gas in the Sichuan Basin by analyzing representative shale gas reservoirs. The results indicate that the deep to ultra-deep shale gas reservoirs in the Longmaxi and Qiongzhusi formations can be categorized into three distinct types： high enrichment-high productivity， high enrichment-low productivity， and medium enrichment-high productivity. The achievement of the high enrichment and high productivity of deep to ultra-deep shale gas is predominantly governed by the synergistic coupling of positive structural setting， favorable preservation conditions， and moderately developed fractures. This finding contributes to the establishment of a high enrichment-high productivity model， characterized by structure-controlled shale gas accumulation， preservation condition-controlled shale gas enrichment， and fracture-controlled shale gas productivity （collectively referred to as the triple-control model）. It is recommended to strengthen the engineering sweet spot evaluation for deep to ultra-deep shale gas play fairways under the guidance of the triple-control model， with particular emphasis placed on areas featuring inherited positive structures and microfractures. Furthermore， differential fracturing techniques should be developed for various types of shale gas reservoirs. These efforts are expected to facilitate the discovery of new types of large-scale shale gas resources in new sequences and regions.

Classification and exploration practices of shale gas reservoirs in the Wufeng-Longmaxi formations in the Sichuan Basin and its periphery

Hongsheng YAO, Peixian ZHANG, Xipeng HE, Yuqiao GAO, Quanfang GAO, Jingya WAN, Dina ZHOU

2025, 46(6): 1807-1822. doi:10.11743/ogg20250605

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The Sichuan Basin and its periphery exhibit multiple shale sequences， various types of shale gas reservoirs， and considerable resource potential. Continuous advancements in shale gas exploration and exploitation have revealed that the geological conditions for shale gas accumulation vary significantly across different zones and sequences in this region， accompanied by complex shale gas enrichment patterns. This necessitates systematic classification of shale gas reservoirs to guide exploratory drilling for new types of shale gas reservoirs in underexplored zones and sequences. In this study， we investigate the conditions favorable for shale gas enrichment and high productivity， as well as the gas reservoir characteristics， of the Wufeng-Longmaxi formations. The shale gas reservoirs are systematically classified based on 12 factors and 21 specific indicators. Focusing on six individual key factors （i.e.， sedimentation， reservoir property， formation pressure coefficient， burial depth， in-situ stress， and structural style）， a set of classification schemes and criteria is proposed. This approach enables the establishment of a comprehensive classification and assessment system for shale gas reservoirs based on the dynamic combinations of multiple factors. Accordingly， shale gas reservoirs or gas-bearing structures within the Sichuan Basin and its periphery are classified. The classification and assessment system is applied to the classification of shale gas reservoirs in underexplored areas along the basin margin and beyond. The results reveal that the Nanchuan shale gas field， located along the basin margin， is characterized as moderately deep to deep， marine， fractured-porous， and dry shale gas reservoirs with medium to high in-situ stress and normal pressure conditions. In contrast， the Wulong gas-bearing structure， positioned outside the basin， is classified as shallow to moderately deep， marine， fractured-porous， and dry shale gas reservoirs with medium to low in-situ stress and normal pressure conditions. These findings provide a solid foundation for reserves reporting and the emplacement of exploration and appraisal wells in the Sichuan Basin and its periphery.

Orderly distribution and hydrocarbon accumulation patterns of multi-type reservoirs of integrated conventional and unconventional hydrocarbons in the Jurassic Ziliujing-Lianggaoshan formations， Sichuan Basin

Zhihong WEI, Wenbin SHI, Daojun WANG, Chao CHEN, Xiaojing LIU, Dongsheng WANG, Miaomiao LIU, Chengyin LI

2025, 46(6): 1823-1839. doi:10.11743/ogg20250606

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In this study， we characterize the whole petroleum system （WPS） and plays in the Jurassic Ziliujing-Lianggaoshan formations of the Sichuan Basin based on the current status and recent progress in lacustrine hydrocarbon exploration of the formations. Specifically， their characteristics are determined by the combination of reservoir-forming elements， with a focus on major source rocks. Furthermore， the characteristics and source rock-reservoir coupling relationships of various types of reservoirs within the WPS are explored， the integrated accumulation patterns of both conventional and unconventional hydrocarbons are summarized， and favorable exploration targets and directions for future breakthroughs are pinpointed. The results indicate that under the control of variations in sedimentary cycles， three stages of lacustrine transgressive sedimentary systems were formed within the Ziliujing-Lianggaoshan formations. The WPS of the formations contains three plays， characterized by superior source rock conditions， favorable reservoir properties， and highly conducive hydrocarbon accumulation configurations. A binary classification criterion based on the sandstone （limestone）/gross thickness ratio and the thickness of a single sandstone （limestone） interlayer is established， addressing the challenge of defining accurate boundaries of lacustrine shale reservoirs posed by their strong lithologic heterogeneity. Based on the criterion， three types of shale reservoirs within source rocks and two types of conventional reservoirs outside source rocks are identified in the Ziliujing-Lianggaoshan formations. Specifically， the shale reservoirs are classified into laminae， interlayer， and interbed types， while the conventional reservoirs consist of tight sandstone and limestone reservoirs. The source rock-reservoir configuration characteristics of these multi-type reservoirs are established. The laminae-type shale reservoirs exhibit moderate to high hydrocarbon generation potential， a self-sourced nature， and strong hydrocarbon retention capacity. In contrast， the shale reservoirs of the interlayer and interbed types show moderate hydrocarbon generation potential， a self-sourced nature， and micro-migration. Meanwhile， the sandstone and limestone reservoirs display hydrocarbon accumulation characterized by a lower source rock-upper reservoir configuration， hydrocarbon accumulation adjacent to source rocks， and hydrocarbon transport through faults. The multi-type reservoirs in the WPS of the Jurassic Ziliujing-Lianggaoshan formations are governed by sedimentary facies zones， demonstrating an orderly spatiotemporal distribution. Specifically， from bottom upward， hydrocarbon occurrences in the formations consist of shale reservoirs of the laminae and interlayer types in the 1st sub-member of the Dongyuemiao member； interlayer-type shale reservoirs and conventional limestone reservoirs in the Da'anzhai member； and shale reservoirs of the interlayer and interlayer-interbed types， together with conventional sandstone reservoirs， in the Lianggaoshan Formation. These hydrocarbon reservoirs， occurring both inside and outside source rocks， show a distribution pattern characterized by two types laterally and three floors vertically. Overall， the multi-type reservoirs in the WPS of the Jurassic Ziliujing-Lianggaoshan formations exhibit orderly， large-scale hydrocarbon accumulation and hold considerable resource potential. These reservoirs represent integrated conventional and unconventional hydrocarbon resources， rendering three-dimensional hydrocarbon accumulation applicable.

Enrichment characteristics and exploration targets of shale gas in ancient strata： Insights from the Cambrian shales in the Middle-Upper Yangtze region

Haikuan NIE, Haikun SU, Ke ZHANG, Tuo LIN, Zhongbao LIU, Pei LI, Jia RONG, Yuzhe WANG

2025, 46(6): 1840-1859. doi:10.11743/ogg20250607

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Breakthroughs in the exploration of the Cambrian shale gas within the Sichuan Basin have contributed to the discovery of the most ancient shale gas reservoirs globally. To reveal the mechanisms governing the shale gas enrichment in ancient strata， we investigate the Cambrian shales in the Middle-Upper Yangtze region in this study. In combination with exploration and exploitation data， we systematically analyze the lithofacies， reservoir properties， geochemical characteristics， and gas play types of the shales， with particular emphasis placed on shale gas preservation conditions. The results indicate that the Lower Cambrian strata in the study area contain two types of shales， i.e.， organic-rich and organic-lean shales， with total organic carbon （TOC） contents of greater than 3% and less than 1%， respectively. These shales contain organic matter with favorable kerogen types （dominated by types Ⅰ-Ⅱ₁） and exhibit high thermal maturity， as indicated by an equivalent vitrinite reflectance （EqVR_o） greater than 3.0%. Two types of shale gas plays are identified： self-sourced and migrated gas plays. The formation of the ancient shale gas plays is jointly controlled by the presence of high-quality reservoirs and the thermal maturity of organic matter， while the development of high-quality reservoirs is governed by the synergistic effects of diagenesis and hydrocarbon generation-induced pore formation. Preservation conditions play a key role in controlling the shale gas enrichment in ancient strata. The Deyang-Anyue rift trough demonstrates a high degree of shale gas enrichment attributable to its tectonic stability and resulting overpressure conditions with formation pressure coefficients ranging from 1.6 to 2.0. It is recommended that future shale gas exploration should focus on areas with both relatively low thermal maturity （EqVR_o < 3.5%） and favorable preservation conditions. The resource potential evaluation of the ancient Cambrian shale gas should focus on several key scientific issues， including the preservation condition limits for ultra-deep shale gas， formation mechanisms of high-quality reservoirs， and the quantitative assessment of hydrocarbon generation， expulsion， and retention in highly- to over-mature shales.

Carbonate metasomatism in siliceous shales of the Dalong Formation， Sichuan Basin and its impact on shale reservoir development

Longfei LU, Wangwei LIU, Weixin LIU, Fang BAO, Yuanyuan ZHOU, Lingjie YU, Baojian SHEN

2025, 46(6): 1860-1873. doi:10.11743/ogg20250608

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By integrating multiple analytical techniques， including X-ray diffraction （XRD）， scanning electron microscopy （SEM）， electron probe microanalysis （EPMA）， and carbon-oxygen isotope analysis， we investigate the origin of micritic calcites in the siliceous shale of the Upper Permian Dalong Formation， northeastern Sichuan Basin， along with their impacts on reservoir development. The siliceous shales generally exhibit a high quartz content， followed by carbonate minerals， with the clay mineral content proving low overall. Microscopic observations reveal that the siliceous shales contain a large quantity of radiolarian bioclasts， which are distributed in densely packed and scattered patterns within the siliceous mineral matrix. Radiolarian skeletons in the siliceous shales display iridescence unique to carbonate metasomatism under orthogonal-polarized light. Under SEM， these skeletons show representative pseudomorphic textures of partial and complete replacement. These observations， combined with the energy dispersive spectroscopy （EDS） analysis， demonstrate that the radiolarian skeletons are formed by diagenetic metasomatism. Metasomatism also occurs synchronously within the siliceous mineral matrix， which acts as the rock framework. The calcitereplacement appear in two forms： highly euhedral individual grains and poorly euhedral or even anhedral aggregates. These calcites occur within the siliceous mineral matrix in irregularly dotted or contiguous patterns， resulting in the formation of mosaic textures. The oxygen isotopic composition indicates that calcites in the siliceous shales are formed in a low-temperature environment. The EPMA results show that the calcites exhibit high silicon and anomalous strontium concentrations， which can be attributed to pore fluid-rock interactions in the early diagenetic stage. These interactions led to the infilling and destruction of numerous primary inorganic pores among quartz grains， thereby reducing the available in-situ space for the retention of liquid hydrocarbons generated in the late stage. The pore modification further affected the quantity of secondary organic pores and the total porosity in the highly- to over-mature stage. Therefore， carbonate metasomatism represents a significant mechanism governing the development of high-quality reservoirs in the siliceous shales of the Dalong Formation within the northeastern Sichuan Basin. Accordingly， its differential impact should be fully considered when selecting the optimal shale gas sweet spot intervals.

Fluid occurrence patterns and source rock-reservoir coupling characteristics of the Middle-Lower Jurassic continental shale reservoirs in the Fuxing area， Sichuan Basin

Xinyu DU, Menhui QIAN, Yahui LIU, Huasheng QI, Feng ZHU, Zhiming LI, Lingjie YU, Chuxiong LI, Wentao ZHANG, Junying LENG

2025, 46(6): 1874-1891. doi:10.11743/ogg20250609

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The proved shale oil and gas initially-in-place （PIIP） in the Fuxing oilfield have been successfully booked， confirming the great resource potential of continental shale oil and gas in the Fuxing area， Sichuan Basin. Although substantial studies have been conducted， several bottlenecks persist in research on continental shales in this area， including distorted resource evaluation results caused by the failure to restore the original oil-water composition， a lack of methods for whole-fluid quantitative characterization， and an unclear understanding of source rock-reservoir coupling mechanisms. To address these challenges， we investigate the Middle-Lower Jurassic organic-rich continental shales in the Fuxing area， eastern Sichuan Basin， with target intervals including the lower sub-member of the 2nd member of the Lianggaoshan Formation （Liang 2 Member）， as well as the 1st sub-member of the Dongyuemiao Member （Dong 1 Sub-member） and the 2nd sub-member of the Da'anzhai Member （Da 2 Sub-member） of the Ziliujing Formation. A scheme for lithofacies classification based on four parameters （i.e.， color， organic matter abundance， sedimentary structure， and mineral composition of rocks） is established， enabling the identification of eight major shale lithofacies in the study area. The fluid occurrence patterns and source rock-reservoir coupling characteristics of various shale lithofacies are systematically investigated in this study. Based on the 2D T₁-T₂ nuclear magnetic resonance （NMR） chart for the quantitative identification of major hydrogen-bearing components in the Middle-Lower Jurassic shales in the Fuxing area， a workflow is developed for fluid restoration and the evaluation of fluid occurrence characteristics across various shale lithofacies. The in-situ fluid saturation and distribution in reservoirs are restored through drainage and imbibition experiments. Accordingly， the source rock-reservoir coupling characteristics of shales at the target intervals are comprehensively evaluated based on the source rock-reservoir coupling coefficient （SRCC） for continental shales. The results indicate that the occurrence state of shale oil is jointly controlled by organic matter type， organic matter abundance， porosity， pore size distribution， and fluid composition， which serve as the key indicators for evaluating high-quality reservoirs. The contents of free and adsorbed oil， along with their ratios， are important parameters for characterizing the oil-bearing properties and oil mobility of shales. Clay-bound water occupies part of spaces for shale oil occurrence， while capillary-bound water tends to block pore-throat channels， both factors significantly restricting the reservoir properties and fluid mobility. Both the grayish-black carbon-rich silty laminar clayey shale facies （L1） in the lower sub-member of the Liang 2 Member and the grayish-black carbon-rich silty shelly laminar clayey shale facies （L7） in the Dong 1 Sub-member are identified as Class A lithofacies characterized by favorable source rock-reservoir coupling relationships. The evaluation results are highly consistent with the experimental data， successfully restoring the oil-bearing properties， reservoir properties， and fluid mobility of the reservoirs under geological conditions. The methodology established in this study， integrating lithofacies identification， fluid restoration， quantitative evaluation based on key parameters， and coupling classification and grading， is highly practical and reliable， yielding encouraging well test and pilot production results. Furthermore， this methodology enables the accurate calculation of key parameters such as total organic carbon （TOC） content， free and adsorbed hydrocarbon contents， total porosity， and bound water content. Therefore， it serves as an effective approach for selecting continental shale enrichment intervals and optimal landing zones， thereby providing strong support for the three-dimensional exploration and efficient exploitation of continental shale oil and gas in the Fuxing area.

Lithofacies types of shales and their distribution in the lower Cambrian Qiongzhusi Formation， northern Sichuan Basin

Bo GAO, Jia RONG, Minghe ZHANG, Ziliang LIU, Jihong YAN, Wei DU, Wangpeng LI

2025, 46(6): 1892-1906. doi:10.11743/ogg20250610

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The identification and classification of the lithofacies types of shales are essential for assessing the potential for shale gas exploration and exploitation and for selecting the optimal shale gas sweet spot intervals. Based on observations of outcrops， cores， and thin sections， as well as whole-rock X-ray diffraction （XRD） mineralogy and total organic carbon （TOC） content determination， we investigate the lithofacies types of shales and their distribution characteristics in the Qiongzhusi Formation， northern Sichuan Basin. The developmental patterns of favorable lithofacies assemblages from taphrogenic troughs to intra-platform depressions are identified， and the sedimentary patterns of shales in the 1st and 2nd members of the Qiongzhusi Formation （also referred to as the Qiong 1 and Qiong 2 members， respectively） are established. The results indicate that a classification scheme based on TOC content and the respective contents of quartz + feldspar， clay minerals， and carbonate minerals allows the shales of the Lower Cambrian Qiongzhusi Formation to be classified into 13 lithofacies types， which are dominated by highly organic clay-bearing felsic shales， organic-rich clay-bearing felsic shales， moderately organic clay-bearing felsic shales， and highly organic felsic shales. Shale intervals with a TOC content of 1.0% or higher in the Qiongzhusi Formation primarily contain five favorable lithofacies assemblages：（1） highly organic to organic-rich clay-bearing felsic shales；（2） highly organic to organic-rich felsic shales；（3） moderately to highly organic clay-bearing felsic shales；（4） moderately to highly organic felsic shales； and （5） moderately to highly organic clay-bearing felsic shales and felsic shales. The distribution characteristics of these lithofacies associations are systematically documented for 1st and 2st members of the Qiongzhushi Formation. The research findings can provide a valuable basis for decision-making in both the assessment of target area selection and exploratory well emplacement for the exploration and exploitation of shales in the Qiongzhusi Formation in northern Sichuan Basin.

Comparative analysis of deep and ultra-deep shale reservoirs in the Wufeng-Longmaxi formations， eastern Sichuan Basin

Chuanxiang SUN, Ke ZHANG, Haikuan NIE, Haikun SU, Chengxiang WAN, Ruikang BIAN, Lingjie YU, Zhenheng YANG

2025, 46(6): 1907-1926. doi:10.11743/ogg20250611

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The Wufeng-Longmaxi formations in the Sichuan Basin hold considerable potential for deep and ultra-deep shale gas resources. However， their deep and ultra-deep reservoirs exhibit significantly different characteristics compared to their medium and shallow counterparts. In this study， we investigate deep （burial depth > 3 500 m） and ultra-deep （burial depth > 4 500 m） shales in the Fenglai and Liangping areas in the eastern Sichuan Basin through a series of experiments and analyses， including field emission scanning electron microscopy （FE-SEM）， pore characterization using high-pressure mercury injection （HPMI） combined with gas adsorption， 3D pore reconstruction using focused ion beam-scanning electron microscopy （FIB-SEM）， porosity and permeability tests under confining pressure， and fluid inclusion microthermometry. Furthermore， comparative analysis is conducted with the shallow to medium-depth shale reservoirs in the Jiaoshiba area， Fuling shale gas field. Accordingly， the characteristics of deep and ultra-deep shale reservoirs in the Wufeng-Longmaxi formations in both areas are elucidated， and the primary factors that distinguish them from the medium and shallow shale reservoirs are identified. The results indicate that the deep and ultra-deep organic-rich siliceous shales in the eastern Sichuan Basin still retain favorable reservoir properties， including organic matter-dominated pore systems， relatively high porosity and permeability， strong resistance to compaction， and limited fracture-fluid activity. Compared to the medium and shallow shale reservoirs， the deep and ultra-deep shales exhibit a significantly decreased density of inorganic pores and microfractures， a higher proportion of meso-to-macro-pores， and markedly lower permeability under the influence of higher overburden pressure. These differences are primarily controlled by the combined effects of tectonic location， mineral composition， diagenesis， tectonic evolution， and fracture-fluid activity. These findings serve to provide a geological basis for the exploration and exploitation of deep and ultra-deep shale gas resources in the Sichuan Basin.

Enrichment and high productivity mechanisms and accumulation patterns of shale oil in lacustrine shales with low total organic carbon content in the Subei Basin

Xipeng HE, Ling ZAN, Yuqiao GAO, Xiao CAI, Peng CHEN, Caixia HUA, Luanxi BAI, Wanlu ZHANG

2025, 46(6): 1927-1946. doi:10.11743/ogg20250612

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Shales in the 2nd member of the Funing Formation （also referred to as the Fu 2 Member） in the Subei Basin are characterized by low organic matter abundance， complex lithological composition， and small fault blocks. These geological characteristics pose considerable challenges for shale oil exploration， including uncertainties regarding resource potential， enrichment mechanisms， and exploration targets. To address these issues， we systematically investigate the mechanisms behind the hydrocarbon generation， reservoir formation， and hydrocarbon accumulation in shales with low total organic carbon （TOC） content in the Fu 2 Member. Accordingly， the potential and favorable targets for shale oil exploration of the shales are determined. The results indicate that shales in the Fu 2 Member consist primarily of five lithofacies types， in which lamellar clayey-felsic and felsic-carbonate mixed shales occurring predominantly in the 1st and 2nd sub-members are identified as favorable lithofacies. The shales contain types I and II kerogen， as well as a range of favorable hydrocarbon-generating parent materials， including the Leiosphaeridia， Botryococcus， dinoflagellates， and suberinite， exhibiting early-stage hydrocarbon generation， high conversion rates， low hydrocarbon expulsion efficiency， and significant free oil enrichment. Shale reservoirs in the Fu 2 Member are classified as fractured-porous reservoirs. In these reservoirs， pores are dominated by intercrystalline pores within clay minerals， intergranular pores within felsic minerals， and dissolution pores. Reservoir fractures consist primarily of bedding-parallel fractures， structural fractures， and diagenetic fractures， contributing to 17% ~ 21% of the reservoir porosity. Influenced by diagenesis and tectonic processes， shale oil experienced three stages of micro-migration within the source interval， resulting in the shale oil accumulation characteristics of micro-migration and self-sealing. Four shale oil accumulation patterns are identified in the Fu 2 Member： stable shale oil within deep low-lying zones， as well as shale oil hosted in highly-steep faulted terraces， complex fault blocks， and shallowly-buried monoclines. The enrichment and high productivity of shale oil are primarily governed by sedimentary diagenesis， preservation conditions， and fracability. A total of 12 exploration and appraisal wells， along with three test well groups， were deployed in the Qintong Sag. All wells yielded high productivity， with proven shale oil reserves exceeding 40 million tons having been reported. These results reveal that shales with low TOC content in the Subei Basin hold considerable potential for shale oil exploration and exploitation.

Differential formation mechanisms of shale oil reservoirs in the 2nd member of the Paleogene Taizhou Formation， Subei Basin

Yuqiao GAO, Xiao CAI, Wei XIA, Xiaodong MA, Ling ZAN, Caixia HUA, Hui LI, Yichuan ZHU, Yumeng WANG

2025, 46(6): 1947-1959. doi:10.11743/ogg20250613

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This study aims to examine the lithofacies fabrics， reservoir types， oil-bearing properties， and crude oil mobility of shale oil reservoirs in the 2nd member of the Paleogene Taizhou Formation （also referred to as the Tai 2 Member） in the Subei Basin. To this end， a series of experiments are conducted on shale samples from cored well HY2， including analysis of large-area thin-section mosaic imaging， argon ion milling-field emission scanning electron microscopy （FE-SEM）， and whole-rock X-ray diffraction （XRD）， together with total organic carbon （TOC） content determination， petrophysical property analysis， and confocal laser scanning microscopy （CLSM） observation. Building on these， we systematically examine the developmental characteristics and differential formation mechanisms of shale reservoirs in the Tai 2 Member. The results indicate that the shale reservoirs are characterized by mineral composition of high carbonate and clay mineral content and low felsic mineral content. The carbonate minerals primarily occur as dispersed micrite， lumps in matrix， and laminae. The shale laminae exhibit a low degree of development and simple types. They are dominated by carbonate and bioclastic laminae， with a minor presence of felsic laminae. Primary mineral assemblages of the shale laminae include “carbonate minerals with clay minerals” and “bioclasts with clay minerals.” The shales consist predominantly of two lithofacies types： massive calcareous mudstones and lamellar argillaceous/ calcareous shales. The reservoir spaces are dominated by intercrystalline pores within clay minerals， with rare lamina-parallel fractures and high-angle fractures. In addition， small quantities of dissolution pores， intergranular pores， and organic pores are locally visible. Shale oil is mainly dispersed， with a light-to-heavy component ratio ranging from 0.52 to 0.77. In shale reservoirs in the Tai 2 Member， lithofacies assemblages are governed by the sedimentary environment， pore evolution is controlled by diagenetic processes， and fracture systems are determined by tectonism. Additionally， the distribution of shale oil in these reservoirs is governed by the hydrocarbon generation and thermal evolution histories of shales.

Characteristics and genetic mechanism of natural fractures in shales from the upper sub-member of the Sha 4 Member to the lower sub-member of the Sha 3 Member in the Dongying Sag， Bohai Bay Basin

Huimin LIU, Junliang LI, Xinjin LIU, Fusheng YU, Jiajie YAN, Yong WANG, Jia REN, Haifeng FENG, Xiaoliang WEI, Chen YANG

2025, 46(6): 1960-1979. doi:10.11743/ogg20250614

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Natural fractures act as both important reservoir spaces and primary seepage pathways in shale oil reservoirs， governing the migration， enrichment， and single-well productivity of shale oil and gas. However， the types and developmental patterns of natural fractures are yet to be clarified for the shales from the upper sub-member of the 4th member of the Shahejie Formation （Es^4U） to the lower sub-member of the 3rd member of the formation （Es^3L） in the Dongying Sag. In this study， we analyze the developmental characteristics， evolutionary stages， major controlling factors， and genetic mechanisms of natural fractures in the shales by integrating core observations， formation micro-imaging （FMI） log interpretation， convolutional neural network （CNN）-based prediction， and petrophysical experiments. The results indicate that natural fractures in the shales can be classified into three types： structural fractures， diagenetic fractures， and anomalously high pressure-induced fractures. Among these， structural fractures predominate in the sag and can be further divided into six sub-types： low-angle tensile-shear composite fractures， medium- to high-angle shear fractures， medium- to high-angle Y-shaped shear fractures， high-angle transtensional fractures， high-angle hybrid fractures， and nearly vertical tensile fractures. These various types of fractures extend in the NEE， nearly EW， and NWW directions and closely coexist with faults. These fractures have experienced six tectonic evolutionary stages， and their development is jointly controlled by structural influence， total organic carbon （TOC） content， and the brittleness index of the shales. Specifically， the fracture density shows a negative correlation with the distance from faults， whereas it exhibits positive correlations with both the TOC content and brittleness index of the shales. Additionally， the fracture development is controlled by tectonic stress regimes. Under extensional stress during the rifting stage from the Es^4U to Es^3L and from the Sha 2 Member （Es²） to the Dongying Formation， medium- to high-angle shear fractures and tensile-shear composite fractures are formed. In contrast， the compressive stress during the late depositional stage of the Dongying Formation led to the formation of low-angle tensile-shear composite fractures， while the depression-rifting process during the deposition of the Guantao-Minghuazhen formations caused the development of both nearly vertical tensile fractures and anomalously high pressure-induced fractures. Results from direct shear tests demonstrate that for the same type of fractures， their development patterns are affected by the dip angle and thickness of shale beddings， as well as the bond strength along bedding planes.

Authigenic minerals and their control over micro-pore development for saline lacustrine shales： A case study of the Shahejie Formation， Jiyang Depression， Bohai Bay Basin

Junliang LI, Huimin LIU, Xiaoliang WEI, Kuihua ZHANG, Pengfei ZHANG, Feng QIN, Yong WANG, Shun ZHANG, Zheng LI, Xinjin LIU, Weiqing WANG, Wei MENG

2025, 46(6): 1980-1997. doi:10.11743/ogg20250615

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This study focuses on the saline lacustrine shales of the Shahejie Formation in the Jiyang Depression， Bohai Bay Basin. Using a range of techniques， including scanning electron microscopy （SEM）， cathodoluminescence （CL）， and energy-dispersive spectroscopy （EDS）， we systematically investigate the characteristics of authigenic minerals in the shales and their influence on micro-pore evolution. The results indicate that coarse-grained calcites or calcites with epitaxial overgrowth precipitated substantially in an alkaline diagenetic environment， leading to significantly reduced porosity. The diagenetic dolomites， in spite of low content and scattered distribution， also indirectly hindered pore preservation due to the weakened reworking by acidic fluids during cementation in an alkaline environment. Ankerites are mostly formed in a Fe²⁺-rich acidic environment， frequently associated with illitization and albitization. Albites and ankerites exhibit pronounced positive correlations with thin-section porosity， although they are not direct pore carriers themselves. This relationship reflects the synergistic effects of acidic fluid-induced reworking and mineral transformation. Illites act as important pore carriers， and their platy or fibrous aggregates facilitate the formation and interconnectivity of intergranular pores， bedding-plane pores， and microfractures in an acidic environment. Authigenic quartz， except for some tiny quartz grains that fill pores， can occur as distinctive vein-like aggregates that provide rigid support for surrounding pore structures， thereby mitigating the damage to pores caused by subsequent compaction and cementation. Overall， the pore evolution in the shales of the Shahejie Formation is dominated by alternating dissolution-induced porosity enhancement in an acidic environment and cementation-induced porosity reduction in an alkaline environment. Furthermore， various authigenic mineral assemblages and their spatial distributions can serve as important indicators for assessing the potential for pore preservation in shale reservoirs.

Sweet spot evaluation and feasibility of cube development of continental shale oil in the Permian Lucaogou Formation， Jimusar Sag， Junggar Basin

Enze WANG, Maowen LI, Yong TANG, Xiaoxiao MA, Menhui QIAN, Tingting CAO, Zhiming LI, Yingxiao FU, Zhijun JIN

2025, 46(6): 1998-2011. doi:10.11743/ogg20250616

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Continental shale oil and gas have emerged as an important contributor to petroleum reserve growth and production addition in China. However， their efficient development of multiple reservoirs simultaneously in a three-dimensional space， that is， cube development， requires fine-scale geological sweet spot evaluation. The Lucaogou Formation in the Jimusar Sag， Junggar Basin represents one of China’s three major demonstration areas of shale oil production capacity construction. This study aims to ascertain the shale oil resource prospects and sweet spot distribution of the Lucaogou Formation to provide theoretical support for its future cube development. Based on a detailed analysis of the geological characteristics of the formation， we assess its “four key properties”， that is， oil-bearing property， oil mobility， reservoir property， and fracability. Accordingly， the concept of sweet spot index is proposed to quantitatively assess the resource quality of shale oil plays. Furthermore， we systematically identify the lithofacies and lithofacies assemblages of shales， quantitatively evaluate the resource potential of varying lithofacies assemblages， and determine the vertical distribution of sweet spot layers. The results indicate that 11 lithofacies can be identified in the Lucaogou Formation based on variations in mineral composition， organic matter abundance， and sedimentary structures. These lithofacies can be further classified into four lithofacies assemblages according to the source rock-reservoir configurations. The most favorable lithofacies for shale oil exploration is identified as the lamellar organic-rich argillaceous siltstone within two lithofacies assemblages：（1） an assemblage consisting of lamellar organic-rich mudstones and limy dolomites and lamellar organic-rich siltstones and （2） an assemblage composed of lamellar organic-rich mudstones and limy dolomites， lamellar organic-rich siltstones， and massive organic-rich to organic-lean siltstones and mudstones. Within the lithofacies assemblage of lamellar organic-rich mudstones and limy dolomites， parts of lamellar organic-rich felsic mudstones and lamellar organic-rich mixed mudstones exhibit considerable potential for shale oil exploration. Shale oil hosted in oil plays characterized by adjacent and integrated source rock-reservoir configurations represents a favorable exploration target in the Lucaogou Formation within the Jimusar Sag. This formation contains multiple sweet spot layers with significant resource potential. Overall， the study area holds promising resource prospects. For continental shale oil systems with multiple superimposed sweet spot layers， the cube development should be adopted based on a fine-scale geological sweet spot evaluation to reducing costs.

Mechanisms behind source rock-reservoir coevolution of shales in the Fengcheng Formation， Mahu Sag， Junggar Basin

Zhongliang SUN, Zhiming LI, Wenjun HE, Junying LENG, Qingmin ZHU, Deguang LIU, Ruyue WANG

2025, 46(6): 2012-2025. doi:10.11743/ogg20250617

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This study aims to investigate the interplay between reservoir evolution and the hydrocarbon generation of source rocks. To this end， we conduct formation porosity thermocompression simulation experiments of hydrocarbon generation on low-maturity source rock samples from well Feng 5 in the Mahu Sag. Accordingly， we systematically analyze the dynamic source rock-reservoir coevolution process at varying stages. The results indicate that the hydrocarbon generation and evolution of shales in the Fengcheng Formation， Mahu Sag can be divided into three stages： the early （simulated vitrinite reflection， Easy R_o = < 0.75%）， middle （Easy R_o = 0.75% ~ 1.06%）， and late oil-generation stages （Easy R_o = 1.04% ~ 1.14%）， with the middle stage representing the main oil generation period. Under the influence of hydrocarbon generation， the reservoirs correspondingly experienced three stages of evolution： poor pore development （Easy R_o < 0.75%）， slowly increasing pore volume （Easy R_o = 0.75% ~ 0.97%）， and rapidly increasing pore volume （Easy R_o = 0.97% ~ 1.14%）. For shales in the Fengcheng Formation， hydrocarbon generation and evolution influences reservoir properties in five aspects： the generation of secondary inorganic pores， bitumen filling and shrinkage， microfracture development induced by hydrocarbon generation pressurization， acidic fluid-induced dissolution， and the formation of authigenic minerals. Meanwhile， improvements in reservoir properties can promote the hydrocarbon generation and expulsion of shales， while an increase in the gas/oil ratio can enhance the hydrocarbon expulsion efficiency under poor reservoir physical properties. Based on the interplay between source rocks and reservoirs， the source rock-reservoir coevolution of shales in the Fengcheng Formation can be divided into four stages： early， slow， rapid， and late stages. The early evolution stage （Easy R_o < 0.75%）， among others， is characterized by a low hydrocarbon yield of the source rocks and poor reservoir properties. During the slow evolution stage （Easy R_o = 0.75% ~ 0.97%）， the hydrocarbon yield， hydrocarbon expulsion efficiency， and hydrocarbon retention rate of the source rocks increased slowly， while the reservoir properties improved gradually. The rapid evolution stage （Easy R_o = 0.97% ~ 1.06%） is characterized by favorable reservoir properties and a high hydrocarbon yield， hydrocarbon expulsion efficiency， and hydrocarbon retention rate of the source rocks. The late evolution stage （Easy R_o > 1.06%） exhibits a decrease in the hydrocarbon yield of the source rocks， favorable reservoir properties， and an increasing oil expulsion efficiency. At present， in areas with breakthroughs in shale oil exploration in the Fengcheng Formation， Mahu Sag， the source rock-reservoir coevolution of shales is generally in the rapid evolution stage， demonstrating considerable resource potential.

Challenges and prospects of hydraulic fracturing for the Jurassic lacustrine shale oil and gas development， Sichuan Basin

Guangfu WANG, Haibo WANG, Jianchun GUO, Lingzhi XIE, Ke XU, Fengxia LI, Tong ZHOU, Shijing CHEN

2025, 46(6): 2026-2040. doi:10.11743/ogg20250618

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Lacustrine shales in the Sichuan Basin host abundant hydrocarbon resources totaling 6 × 10¹² m³ （gas equivalent）， predominantly as condensate reservoirs. Compared to marine shale gas reservoirs， these lacustrine shales display distinctive lithofacies characteristics， elevated clay contents， and unique gas reservoir types， primarily distributed in shallow to semi-deep lacustrine sedimentary environments of the Qianfoya/Lianggaoshan formations， as well as the Dongyuemiao and Daanzhai members of the Ziliujing Formation， of the Jurassic. Presently， the Critical development challenges include short production plateau， rapid decline rates， and low estimated ultimate recovery （EUR） per well， undermining economic viability.. This study systematically analyzes three Jurassic lithofacies assemblages and identifies critical fracturing constraints as follows. First， Strong heterogeneity arising from multi-lithofacies combinations restricts fracture propagation and proppant transport， limiting the stimulated reservoir volume. Second， the high clay content induces hydration swelling， impairing long-term fracture conductivity. Third， the dynamic stress-seepage coupling in multi-scale， multi-porosity， multi-phase systems complicates hydrocarbon flow mechanisms， highlighting inadequacies in current geoengineering models and numerical simulations. Essential research priorities， thereby， include fracture network formation in highly heterogeneous shales， fluid-rock coupled pore-fracture evolution incorporating spatiotemporal fluid distribution， and multi-phase flow modeling within complex porous media. Consequently， we propose an integrated “multi-lithofacies/multi-porosity/multi-scale/multi-phase” geoengineering optimization framework （i.s.， “modeling-fracturing-simulation”） to establish a comprehensive “theory-technology-demonstration” solution for economically viable shale resource development.

Evolutionary paths for the theoretical and technological developmentof shale oil and gas reservoir simulation

Tingxue JIANG, Jun ZHOU

2025, 46(6): 2041-2058. doi:10.11743/ogg20250619

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This study presents a comprehensive review of the development process and evolutionary paths of the theories and technologies for China’s shale oil and gas resevoir stimulation， aiming to provide theoretical guidance and technical support for the efficient exploration and exploitation of shale resources in the future. By comparing the geological parameters and characteristics of shale reservoirs in China and the United States， we systematically organize the evolutionary paths of fracturing concepts， as well as theoretical models and critical technologies for reservoir stimulation， using the citation tracking method. Accordingly， an overall development framework of techniques for China’s shale oil and gas reservoir stimulation is established. China has adopted “intensive stimulation” techniques to overcome the disadvantages of its shale reservoirs. Consequently， the viscosity of fracturing fluids has been gradually reduced， with slickwater predominating presently （accounting for more than 90%）. Meanwhile， proppants have evolved toward micro-proppants for supporting multi-scale fractures， and high-precision processing and interpretation have been achieved for fracture monitoring. These advancements have collectively contributed to the development of a fracturing technology system capable of generating complex fracture networks and the establishment of a closed-loop control system. The evolutionary pattern of the shale reservoir simulation technologies with Chinese characteristics is thus revealed， and future development directions， including geological-engineering integration， water-saving and environmentally friendly technologies， and intelligent equipment， are proposed. This study can serve as a valuable guide for advancing the shale oil and gas revolution and achieving national energy strategic goals.

Efficient exploitation and carbon storage efficiency of shale condensate gas reservoirs

Hui CHEN, Xiaopeng CAO, Qiang SUN, Jianhui DUAN, Fei FAN, Junping BEI

2025, 46(6): 2059-2070. doi:10.11743/ogg20250620

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Condensate gas reservoirs with ultra-high gas condensate content （> 600 g/m³） tend to undergo rapid retrograde condensation when reservoir pressure falls below the dew point pressure. This leads to condensate liquid accumulation in near-wellbore zones， thereby seriously impacting gas well productivity. In this study， we investigate the condensate gas reservoirs with ultra-high gas condensate content in block X. While considering the adsorption-diffusion mechanisms specific to shale condensate gas reservoirs， we investigate the role of CO₂ injection for energy replenishment on reducing condensate liquid content and restoring well productivity. It also evaluates the carbon storage efficiency across various CO₂ sequestration forms. The results indicate that during depletion recovery， continuous production of light components shifts the reservoir fluid system from a condensate gas state to volatile oil. Injecting CO₂ at the low-pressure production stage can effectively reduce condensate liquid content in the formation and restore gas mobility in the near-wellbore zone. In contrast， injecting CO₂ at the high-pressure production stage transforms the system into a volatile oil state， thereby increasing the condensate liquid volume instead. For condensate gas reservoirs with ultra-high gas condensate content， CO₂ injection fails to significantly reduce the dew point pressure. In contrast， in condensate gas reservoirs with medium or low gas condensate content， CO₂ injection can effectively lower the dew point pressure， thereby mitigating retrograde condensate pollution. CO₂ sequestrated underground through structural and residual trapping mechanisms constitutes the dominant proportion of total storage， while that sequestrated via dissolution and adsorption trapping accounts for comparatively minor proportions. Additionally， the injection and production parameters， including injection duration， injection rate， and soaking time， for the single-well CO₂ huff-n-puff process are optimized， providing a theoretical basis for the efficient exploitation of and carbon sequestration in shale condensate gas reservoirs with ultra-high gas condensate content.

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