Table of Content

05 September 2024, Volume 45 Issue 4

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Petroleum Geology

Sedimentary environments and lithofacies characteristics of fine-grained sediments in typical continental basins in China

Xiaomin ZHU, Xiaolin WANG, Meizhou ZHANG, Xingyue LIN, Qin ZHANG

2024, 45(4):  873-892.  doi:10.11743/ogg20240401

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The sedimentary environments of fine-grained sediments and the spatio-temporal distribution patterns of the fine-grained lithofacies are identified as primary factors governing the enrichment and high yield of shale oil. Starting from previous relevant studies， we investigate the sedimentary environments and primary characteristics of fine-grained sediments in typical continental basins in China， including the Songliao， Bohai Bay， Ordos， and Junggar basins. The findings suggest that： （1） Fresh-to-brackish-water lacustrine basins typically contain claystones， siltstones， and transitional lithologies between them， showing the presence of silty， clayey， and organic laminae. In contrast， the lagoon and saline lakes mostly develop fine-grained carbonate rocks and mixed fine-grained sedimentary rocks， characterized by calcite （dolomite） laminae and the laminae of clayey marls. （2） Different evolutionary stages of continental basins developed the occurrence of varying assemblages of fine-grained lithofacies. Fine-grained sedimentary rocks formed during rifting are characterized by lithofacies assemblages rich in carbonate minerals， while organic-rich shale layers formed during depression are dominated by the assemblage of feldspathic and clayey sedimentary rocks. （3） Primary mechanisms for shale deposition in lacustrine basins include suspension settling， aeolian input， turbidity flows， hyperpycnal plumes， and muddy debris flows. （4） Continental shale oil in China exhibits diverse types. It boasts abundant resources in the Mesozoic-Cenozoic continental basins such as Songliao， Ordos， Junggar， and Bohai Bay basins serving as important targets for shale oil exploration and exploitation. （5） Future research on the sedimentary settings and lithofacies of fine-grained sediments should be focused on astronomical cycles to establish systematic and effective parameters and criteria for identifying paleosedimentary environments. Furthermore， it is essential to develop classification schemes and sedimentary models for the fine-grained sedimentary lithofacies of shale， interbedded， and mixed types in continental basins to effectively predict the spatio-temporal distributions of these lithofacies. Physical and numerical simulations of the sedimentary origin and processes of fine-grained sediments are recommended to examine the sediments’ coupled physical， chemical， and biological depositional processes， as well as its formation and development mechanisms. Additionally， it is necessary to pay attention to data integration， in-depth data mining， artificial intelligence （AI）， big data， and computer aided technology to investigate the distribution patterns of fine-grained sediments.

Exploring source rock-reservoir coupling mechanisms in lacustrine shales based on varying-scale lithofacies assemblages： A case study of the Jurassic shale intervals in the Sichuan Basin

Zongquan HU, Zhongbao LIU, Qianwen LI, Zhoufan WU

2024, 45(4):  893-909.  doi:10.11743/ogg20240402

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China’s lacustrine shale sequences exhibit complex sedimentary genesis and lithofacies assemblages， and studies on their source rock-reservoir characteristics and coupling mechanisms remain limited. Guided by theories of petrology， sedimentology， and unconventional reservoir geology， we investigate the Jurassic shale intervals within the Sichuan Basin. An integration of experimental and testing techniques such as rock and mineral analyses， organic geochemistry， and shale reservoir characterization is applied to explore the source rock-reservoir coupling mechanisms in the lacustrine shale based on varying-scale lithofacies assemblages. As a result， a methodology that combines macroscopic observations with microscopic analyses to identify lithofacies and uses varying-scale analysis to determine lithofacies assemblages is put forward in the study. Using this， we identify three types of lithofacies assemblage in terms of sedimentary genesis： terrestrial mud-sand sedimentary type， endogenetic mud-lime sedimentary type， and mixed source mud-sand-lime sedimentary type. Our findings indicate that many lamellar to thin-layered calcite-shell or silt layers tend to occur in the shale intervals featuring large-scale lithofacies assemblages consisting of shale interbedded with shell limestone or siltstone， with varying-scale interlayers within the same lithofacies assemblage being of the same type. Meter-scale shell-limestone or siltstone layers within large-scale lithofacies assemblages display inferior reservoir physical properties， thus contributing minimally to hydrocarbon accumulation. In contrast， millimeter-scale laminae and centimeter-scale thinly-layered calcite shells within small-scale lithofacies assemblages feature well-developed intragranular pores filled with dark organic matter， providing effective storage spaces for hydrocarbons. The source rock-reservoir coupling models for the three types of lithofacies assemblages are established， revealing that the correlations between the source rock （total organic carbon， TOC） and reservoir （porosity） for these lithofacies assemblages show a gradual improvement from terrigenous to mixed and then to endogenetic assemblages. This finding is closely associated with their differences in maturity， organic macerals， and inorganic minerals. Additionally， we explore the factors affecting the formation of various lithofacies assemblages different in type and scale and analyze the necessity of understanding the source rock-reservoir characteristics and their coupling mechanisms of lacustrine shale oil and gas from the perspective of varying-scale lithofacies assemblage， aiming to develop a novel philosophy of research on the hydrocarbon accumulation mechanism of lacustrine shales.

Advances and perspectives in the study of the genetic mechanism and organic matter enrichment models of marine fine-grained sediment

Zhensheng SHI, Tianqi ZHOU

2024, 45(4):  910-928.  doi:10.11743/ogg20240403

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This study provides a comprehensive analysis of global advances in the study of the characteristics， origin， and organic matter enrichment model of marine fine-grained sediments. These sediments， mainly composed of clay minerals， quartz， carbonate minerals， and organic matter， are predominantly transported by four geological agents： wind， hypopycnal plumes， hyperpycnal plumes， and bottom currents. They exhibit clayey and silty laminae； single， sequential， and alternating laminasets； and massive， graded， and alternating beds. Covering three major types of sedimentary facies， namely turbidite， bottom current， and pelagic to semi-pelagic facies， as well as their transition types， the sediment demonstrates two organic matter enrichment models under high productivity and enhanced preservation. In the high productivity-derived model， the organic matter enrichment in black shales typically involves upwelling currents， oxygen-minimum zones （OMZ）， and nearshore photic zone euxinia （PZE）. In the enhanced preservation-related model， the enrichment principally involves restricted basins， improved restricted basins， irregular bed form， expanding puddles， transgressive chemocline， and transgressive nearshore （TN） zones. Current challenges in the research on the genetic mechanism and facies models of marine fine-grained sediments primarily include non-standard terminology， undefined origins of different mineral compositions， and the difficulty in distinguishing among three sedimentary facies： fine-grained turbidite， contourite， and semi-pelagic facies. Further research is required to address these issues.

Frontiers and trends in the research on carbonate sedimentology and reservoir geology

Jingao ZHOU, Zhehang XU, Shiwei HUAN, Wenzheng LI, Junmao DUAN, Yongjin ZHU, Jianfeng ZHENG, Dongxu WU, Shaoying CHANG

2024, 45(4):  929-953.  doi:10.11743/ogg20240404

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Carbonate rocks typically contain abundant hydrocarbon resources， which establish them as a crucial target for current and future hydrocarbon exploration and exploitation. To determine the frontiers and trends of research on carbonate sedimentology and reservoir geology， we perform a literature review on carbonate rocks. The three advances in carbonate sedimentology are summarized here. （1） An improved classification of carbonate factories in five types is developed based on the determination of the genetic relationships between producers， environments， and products. These provide a novel philosophy for reconstructing carbonate sedimentary environments， localizing source rocks and reservoirs， and investigating the source-to-sink sedimentary system of carbonate rocks. （2） A systematic elucidation of the mechanisms behind carbon sequestration and oxygen generation by microbes， carbon sequestration and rock formation by microbes， microbially induced carbonate fabrics， and microbial involvement in sedimentation and evolution. These mechanisms function as a new theoretical basis for reconstructing the carbon cycling， atmospheric oxidation， biological evolution， and carbon sequestration in geological history. （3） The basin-scale lithofacies paleogeographic reconstruction， and the development of unique sedimentary patterns. These allow for the expansion of hydrocarbon exploration toward both the interior carbonate platforms and deep to ultradeep ancient carbonate rocks. Recent advances in the understanding of carbonate reservoir geology include： （1） Innovations made in the genetic mechanisms of dolomites， with three novel models being established： microbially induced dolomitization， dissolution/precipitation-driven dolomitization， and high silica concentration-driven dolomitization， being of new theoretical models for understanding dolomization； （2） The identification of sedimentary facies， dolomitization， dissolution， and structural modification as dominant factors controlling reservoir formation， and the determination of the formation and distribution patterns of microbialite-dominated reservoirs and fault-controlled reservoirs. These assist in expediting breakthroughs in oil and gas exploration in carbonate rocks. The advances in experimental techniques for carbonate rocks include the establishment of uranium and lead （U-Pb） isotopic dating， and clumped， Mg， and S isotope tests for carbonate minerals. These advances provide new technologies and methods for reconstructing the evolution of reservoir porosity， the process of reservoir formation， and the evolution of hydrocarbon accumulation. Overall， it can be concluded that physical simulation， numerical simulation， and artificial intelligence represent the trends of research on carbonate sedimentology， reservoir geology and experimental technology.

Advances in well log-based assessments of fine-grained sedimentary rocks

Xiaojiao PANG, Guiwen WANG, Dali YUE, Dong LI, Hongbin LI, Chongyang WANG, Lichun KUANG, Jin LAI

2024, 45(4):  954-978.  doi:10.11743/ogg20240405

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Fine-grained sedimentary rocks， which serve as the source rocks and reservoirs of tight/shale oil and gas， are the focus and frontiers of petroleum geology. The log-based assessments of these rocks hold great significance for the exploration and exploitation of unconventional hydrocarbons. In this study， the advances in both domestic and international log-based assessment techniques are systematically analyzed for fine-grained sedimentary rocks. The analytical results indicate that the combination of conventional and emerging logging techniques allows for the assessment of more than seven properties of fine-grained sedimentary rocks， including lithology， physical and electrical properties， oil-bearing capacity， oil mobility， wettability， brittleness， and source rock property. The log-based assessment of fine-grained sedimentary rocks has， therefore， further evolved into the assessment of their reservoir property， oil-bearing capacity， oil mobility， and fracability， collectively known as the “new four properties”. Specifically， the reservoir property of these rocks is assessed based on parameters such as lithology， lithofacies， pore type， microscopic pore structure， lamellation， total porosity， and effective porosity. Their oil-bearing capacity is assessed using parameters like clay mineral content， TOC content， free hydrocarbon content， oil saturation， oil occurrence， and movable oil content. The oil mobility in fine-grained sedimentary rocks is assessed according to parameters such as maturity， formation pressure， crude oil density and viscosity， and gas/oil ratio. The fracability of these rocks is assessed using parameters like the respective compositions and contents of clay and brittle minerals， Young’s modulus， Poisson’s ratio， and the maximum and minimum principal stresses. The formation micro-imaging （FMI） logging slicing technology enables the manual identification and assessment of meter-， millimeter-， and even micron-scale laminae in fine-grained sedimentary rocks. Additionally， log data facilitate the identification and assessment of the lithofacies of fine-grained sedimentary rocks. The techniques and methods for log-based assessments of fine-grained sedimentary rocks are evolving from conventional and emerging logging techniques toward artificial intelligence approaches based on mathematical statistics.

Characteristics and determinants of shale reservoirs in the Upper Permian Dalong Formation， Sichuan Basin

Yuehao YE, Wei CHEN, Hua WANG, Jinmin SONG, Ying MING, Xin DAI, Zhiwu LI, Haofei SUN, Xiaogang MA, Tingting LIU, Hui TANG, Shugen LIU

2024, 45(4):  979-991.  doi:10.11743/ogg20240406

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Marine black shales are found in the Upper Permian Dalong Formation within the Kaijiang-Liangping trough in the Sichuan Basin. Recently drilling of wells LY1， DY1， and HY1 has revealed high-yield shale gas in this formation， suggesting considerable potential for marine shale gas exploration in the Dalong Formation of the northern Sichuan Basin. Hence， it is highly significant to investigate the characteristics and determinants of shale reservoirs in this formation. In this study， we investigate the organic geochemistry， brittle mineral content， pore types， and pore structures of shales in the Dalong Formation in well DY1， aiming to elucidate the characteristics and determinants of the shale reservoir within. The findings show that the black shales in the Dalong Formation are of deep-water shelf deposits， exhibiting major facies of siliceous and mixed shale， high in brittle mineral contents. The organic matter of these shales exhibits a high abundance， with TOC content averaging at 7.84 %， type Ⅱ₁-Ⅱ₂ kerogens， and high porosities， averaging at 5.78 %， and the organic pores act as main storage space with the micro-pores’ peak value the highest. The development of pores in the shales is governed by the abundance， type， and thermal maturity of organic matter， while carbonate minerals are detrimental to their growth.

Developmental models of organic-rich shales in the Cambrian Qiongzhusi Formation in the piedmont zone of northern Sichuan Basin

Minghe ZHANG, Xiangfeng WEI, Bo GAO, Jia RONG, Zhujiang LIU, Jihong YAN, Qihang YANG, Jiale WANG, Huiping LIU, Lang YOU, Ziliang LIU

2024, 45(4):  992-1006.  doi:10.11743/ogg20240407

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Investigating the distributions， dominant controlling factors， and sedimentary patterns of organic-rich shales in the Cambrian Qiongzhusi Formation in the Micang-Daba piedmont zone of the northern Sichuan Basin holds great significance for shale gas exploration within. Based on data from field geological surveys， drilling， and core observation， as well as analytical and test data derived from rock thin section observations， whole-rock X-ray diffraction （XRD） pattern， and total organic carbon （TOC） content determination， we explore the sedimentary patterns， distributions， and dominant controlling factors of organic-rich shales in the Qiongzhusi Formation， piedmont zone of the northern Sichuan Basin. The results indicate that shales in the Qiongzhusi Formation consist primarily of highly brittle siliceous shales and moderately brittle silica-clay mixed shales. In terms of their TOC content， sedimentary structures， and mineral components， these shales can be categorized into 16 lithofacies types， with the organic-rich laminated siliceous shale facies of high brittleness， organic-rich bedded siliceous shale facies of high brittleness， and the organic matter-bearing bedded siliceous shale facies of high brittleness dominating. The former two dominant shale facies are identified as the primary targets for the exploration and production of shale gas. The organic-rich shales， with TOC content typically exceeding 2 %， are thicker in the south and west but thinner in the north and east， corresponding to a higher organic matter abundance in the south and west and lower abundance in the north and east； The intracratonic sag and the paleogeographic patterns exhibiting alternating uplifts and sags within are identified as the primary causes of the differential distribution of organic-rich shales in the Qiongzhusi Formation. The imbalanced structural evolution in the zone enhances the heterogeneous distribution of shales. The flourishing lower plankton and bacteria serve as substantial sources of organic matter. The anoxic deep-water environment under rapid transgression in the early stage creates favorable conditions for the preservation of organic matter， whereas the continuous uplift of the Motianling and Hannan oldlands in the late stage inhibits the organic matter enrichment. The eustatic movements and paleoclimate evolution govern the vertical cyclic distribution of organic-rich shales.

Petroleum geology and ring-shaped distribution of the Paleogene-Neogene hydrocarbon resources in western Qaidam Depression，Qaidam Basin

Guoyong LIU, Jianqin XUE, Songtao WU, Kunyu WU, Boce ZHANG, Haoting XING, Na ZHANG, Peng PANG, Chao ZHU

2024, 45(4):  1007-1017.  doi:10.11743/ogg20240408

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The western Qaidam Depression features rich Paleogene-Neogene petroleum systems， with conventional and shale oil accounting for 82.4 % and 100 % of the counterparts of the whole basin， respectively. Based on the investigated sedimentary reservoirs and petroleum geology， we analyze the sedimentary facies and hydrocarbon accumulation characteristics of the Paleogene-Neogene in the western Qaidam Depression and propose a ring-shaped hydrocarbon distribution pattern therein. The results reveal that the Paleogene-Neogene sedimentary facies zones in the depression present a ring-shaped distribution pattern comprising outer， middle， and inner rings. The outer ring， featuring deltaic and beach-bar facies， is dominated by clastic sediment， with the presence of small quantities of carbonate sediment. This ring contains conglomerate， coarse-grained conglomeratic sandstone and medium-grained sandstone reservoirs. The middle ring is dominated by the limy dolomite flat and limy muddy flat microfacies of the shore-shallow lacustrine subfacies， including fine-grained sandstones， siltstones， limy dolomites， and algal limestones. Of these， algal limestones serve as the most distinctive lithofacies with the highest porosity observed in the middle ring. The inner ring is composed of fine-grained diamictites of the semi-deep to deep lacustrine facies， encompassing deep- and dark-gray fine-grained sedimentary rocks. This establishes the middle ring as the key area to source rock development in the Paleogene-Neogene system. Reservoir types differ across the different sedimentary facies rings. In the outer ring， which is distant from hydrocarbon kitchens， hydrocarbons， transported via faults， accumulate in clastics such as conglomerates and coarse-grained sandstones， resulting in structural hydrocarbon reservoirs. The middle ring， immediately adjacent to the major hydrocarbon kitchens， has hydrocarbons migrating through faults and accumulating in carbonate reservoirs like algal limestones， resulting in the structural-lithological hydrocarbon reservoirs. The inner ring sitting on major source rock sequence has hydrocarbons either undergo short-distance migration or reside in situ in fine-grained diamictites， forming shale oil reservoirs. The western Qaidam Depression exhibits overlapped structural-lithological hydrocarbon reservoirs and shale oil reservoirs vertically from external to intra source rocks， and manifests a ring-shaped distribution of structural hydrocarbon， structural-lithological hydrocarbon， and shale oil reservoirs in a plan view.

Breakthroughs in hydrocarbon exploration in the Ganchaigou area， Qaidam Basin and their implications

Yan CHEN, Yongshu ZHANG, Zhaohui XU, Yinghai JIANG, Chao ZHU, Jing ZHANG, Caiyan ZHANG

2024, 45(4):  1018-1031.  doi:10.11743/ogg20240409

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No significant hydrocarbon exploration discoveries were achieved for over 60 years of efforts， and breakthroughs have ultimately been made since 2019 when seismic survey targeting mountainous regions was performed and study on the formation of and hydrocarbon accumulation in mixed siliciclastic-carbonate reservoirs developed in plateau salinized lacustrine environment went further. The discovery of structural reservoirs located in the Lower Ganchaigou Formation of the Paleogene， along with great potentials shown in the exploration and development of Yingxiongling shale oil and lacustrine carbonate lithological reservoirs in this area， can be attributed to the following factors. First， high-quality 3D seismic data serve to reveal the underground structure geometry in the Ganchaigou area， where a faulted anticline favorable for hydrocarbon accumulation as a trap is detected in the east； Second， large-scale mixed carbonate rocks of salinized lacustrine facies have storage capacity， while clastic rocks， lacustrine carbonate rocks and gypsolyte are well-aligned both laterally and vertically， thus being of a good source rock-reservoir-caprock assemblage as a whole； Third， both conventional （out of source rocks） and unconventional （within source rocks） hydrocarbon are generated and accumulate as a total petroleum system （TPS） in the study area. In investigating the exploration process in the study area， we confirm that the progress in seismic exploration technology lays a solid foundation for the discovery of the complex structural trap underground and its petroleum geological characteristics. The mixed carbonate rocks developed in large scale in the dry salinized lacustrine environment function as both source rocks and reservoirs， a finding that has extended our understanding in exploration and been a key in fulfilling the breakthroughs. The adoption of the TPS concept serves to push hydrocarbon exploration to go further into the source rocks while revealing the great potentials of Yingxiongling shale oil to be developed.

Micro-pore structure characteristics of the Paleogene sandstone reservoirs and genesis of microscopic tight zones in the Mahaidong area， Qaidam Basin

Zhuang RUAN, Rui XU, Jie WANG, Qiuhong CHANG, Dahua WANG, Jiandong WANG, Guangqing ZHOU, Bingsong YU

2024, 45(4):  1032-1045.  doi:10.11743/ogg20240410

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Discoveries have been made in the Paleogene hydrocarbon exploration in the Mahaidong area on the northern margin of the Qaidam Basin. However， the current productivity is low primarily due to the limited understanding of the characteristics of micro-pore structures， restricting hydrocarbon exploration and exploitation in the area. To reveal the microscopic characteristics of the Paleogene sandstone reservoirs in the Mahaidong area， we investigate the petrology， physical property characteristics， micro-pore structures， and heterogeneity of low-permeability sandstone reservoirs in the Mahaidong area using techniques such as the micro-petrographic observation， X-ray diffraction （XRD） analysis， and high-pressure mercury injection （MICP） experiments. Additionally， we quantitatively characterize the degree of reservoir heterogeneity using the coefficient of variation. The findings reveal that the Paleogene sandstone reservoirs consist primarily of feldspathic litharenites， with calcite identified as primary interstitial fillings. The porosity of the reservoirs decreases in the order of sandstone member Ⅰ of the Lulehe Formation， sandstone member Ⅱ of the Lower Ganchaigou Formation， and sandstone member Ⅱ of the Lulehe Formation. The reservoir rocks have undergone diagenetic processes such as compaction， cementation， and dissolution. Consequently， the reservoir heterogeneity decreases in the order of sandstone member Ⅱ of the Lulehe Formation， sandstone member Ⅱ of the Lower Ganchaigou Formation， and sandstone member Ⅰ of the Lulehe Formation. Low-permeability sandstones rich in plastic detrital lamina or matrix are identified as tight reservoirs， with calcite cementation and deformation of plastic clayey debris as the predominant factors contributing to reservoir tightness.

Characteristics and controlling factors of deep to ultra-deep tight-gas clastic reservoirs in the Junggar Basin

Jing SUN, Xincai YOU, Jingjing XUE, Menglin ZHENG, Qiusheng CHANG, Tao WANG

2024, 45(4):  1046-1063.  doi:10.11743/ogg20240411

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To explore favorable deep to ultra-deep tight-gas clastic reservoirs in the Junggar Basin， we investigate the developmental characteristics， storage space types， changes in physical properties， and controlling factors of these reservoirs using data from drilling， logging， thin-section observation， and assays. Key findings are as follows： （1） Favorable deep to ultra-deep tight-gas clastic reservoir rocks in the basin are mainly of deltaic conglomerates and sandstones， which are dominated by fine-， medium-， and medium- to fine-grained conglomerates/sandstones and can be classified as lithic sandstones. Of these， gravels and sandstone detritus consist primarily of tuffs， and the cements are dominated by calcite， with locally enriched zeolite. （2） The storage spaces consist of pores and fractures， dominated by pores. Accordingly， the storage spaces can be categorized into three types： pore， fracture， and mixed pore-fracture types. The pores are mainly primary residual and secondary dissolution pores， with the latter being predominant， while the fractures are composed mainly of diagenetic compaction-induced micro-fractures and tectonic fractures， （3） forming three secondary pore zones vertically. （4） Major factors governing the favorable reservoirs include rock composition， constructive diagenesis， and anomalously high pressure， which jointly control the development and distribution of favorable deep to ultra-deep tight-gas clastic reservoirs in the Junggar Basin.

Characteristics of source rocks in the Cambrian Xiaoerbulake Formation in the northwestern Tarim Basin

Yongjin GAO, Chengming YIN, Lihong LIU, Darong XU, Youxing YANG, Yuanyin ZHANG, Zezhang SONG, Mantong ZHEN

2024, 45(4):  1064-1078.  doi:10.11743/ogg20240412

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In recent years， a series of discoveries and breakthroughs in hydrocarbon exploration have been achieved in the Cambrian strata in the northwestern Tarim Basin （hereafter referred to as the study area）. Therefore， investigating the characteristics of the Cambrian source rocks holds great significance for guiding subsequent hydrocarbon exploration efforts. Previous studies have generally suggested that the Cambrian marine source rocks in the Tarim Basin primarily occur in the Lower Cambrian Yuertusi Formation. To investigate the characteristics of source rocks in a new sequence in the Cambrian Xiaoerbulake Formation， we conduct petrologic and geochemical analyses of samples collected from four wells （i.e.， wells BY1， KTJ1， KPN1， and XSC1） and three outcrops. The analytical results indicate that the source rocks in the formation in the study area consist predominantly of argillaceous limestones and mudstones. The test results of samples show that the lower member of the Cambrian Xiaoerbulake Formation exhibits average total organic carbon （TOC） contents of 1.55 %， 2.39 %， 0.45 %， 0.89 % （for the four wells）， and 1.10 % （for the three outcrops）， respectively， suggesting fair-to-good source rocks. The formation’s source rocks contain sapropelic parent materials， with bitumen reflectance values ranging between 2.23 % and 2.57 %， suggesting overmature organic matter and natural gas-prone source rocks. These source rocks vary in thickness from approximately 20 to 90 m， exhibiting higher quality in the middle to lower members than in the upper member. Drilling results and seismic profiles reveal that these source rocks principally occur in the intra-platform depression centered on wells BY1 and KTJ1， establishing this depression as the most favorable area for the occurrence of source rocks.

Micromechanical characteristics and classification of the grains of lacustrine fine-grained sedimentary rocks： A case study of shales in the 7^th member of the Upper Triassic Yanchang Formation， Ordos Basin

Xinhui Xie, Hucheng Deng, Lanxiao Hu, Yong Li, Jinxin Mao, Jiajie Liu, Xin Zhang, Boyang Li

2024, 45(4):  1079-1088.  doi:10.11743/ogg20240413

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Fine-grained sedimentary rocks contain abundant hydrocarbon resources. To examine the microscopic structural and micromechanical characteristics of their grains， we explore such rocks in the 7^th member of the Upper Triassic Yanchang Formation （also referred to as the Chang 7 Member） in the Ordos Basin. Using scanning electron microscopy （SEM） and nanoindentation experiments， we delve into the geometric characteristics and micromechanical properties of the grains of these rocks. The results indicate that based on five characterization parameters， namely grain size， flatness， angularity， hardness， and modulus of elasticity， the fine-grained sedimentary rocks in the Chang 7 Member can be categorized into six major grain types： grain size and angularity predominating； flatness and angularity predominating； flatness， angularity， modulus of elasticity， and hardness predominating； modulus of elasticity and hardness predominating； angularity， modulus of elasticity， and hardness predominating， and grain size， angularity， and modulus of elasticity predominating. Five types of grain assemblages can be further identified based on the relative contents of the six types of grains. Additionally， the coupling relationships between the grain types and mineral types of the fine-grained sedimentary rocks are determined. The proposed scheme for microscopic grain classification of fine-grained sedimentary rocks assists in understanding the microscopic structural characteristics of fine-grained sedimentary rocks and predicting the spatial distributions of geological sweet spots， thus holding great theoretical and scientific significance for the hydrocarbon resource assessment and efficient hydrocarbon exploitation of fine-grained sedimentary rocks.

Lithofacies classification and microscopic pore characteristics of fine-grained sedimentary rocks in the Hetang Formation， Lower Yangtze region

Qin ZHANG, Donglian LU, Kai WANG, Chang LIU, Mingqiang GUO, Mengjie ZHANG, Chaojie GUO, Ying WANG, Wenzhong HU, Xiaomin ZHU

2024, 45(4):  1089-1105.  doi:10.11743/ogg20240414

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The lithofacies and microscopic pore characteristics of fine-grained sedimentary rocks in the Lower Cambrian Hetang Formation in the Lower Yangtze region remain unclear， which restricts the exploration and exploitation of shale gas in this region. In this study， we obtain data using methods including ordinary thin section observation， scanning electron microscope （SEM） image analysis of argon-ion milled sample surface， physical property tests， X-ray diffraction （XRD） analysis of whole-rock and clay mineralogy， N₂ and CO₂ isothermal adsorption experiments， and focused ion beam-scanning electron microscope （FIB-SEM） image analysis. Using these experimental data， we develop a lithofacies classification scheme for fine-grained sedimentary rocks in the Hetang Formation and analyze the microscopic pore structure characteristics of various lithofacies. The results indicate the presence of five major lithofacies of the fine-grained sedimentary rocks， namely massive siliceous mudstone， lamellar siliceous shale， massive clay-bearing siliceous mudstone， massive mixed siliceous-calcareous mudstone， and massive mixed calcareous mudstone， which differ greatly in porosity and permeability. Main pores in the Hetang Formation include intergranular， intercrystalline， intragranular， and organic matter-hosted pores and microfractures， with pores of nano-to-micron scale dominating. Of these， mesopores range in size from 2.0 to 10.0 nm， while micropores range from 0.4 to 0.9 nm. The massive mixed siliceous-calcareous mudstone features high organic matter and brittle mineral contents， well-developed intergranular pores and microfractures， high porosity and permeability， excellent pore connectivity， and large specific surface area， which establish itself as the most favorable lithofacies for shale gas exploration and exploitation in the Hetang Formation. The massive clay-bearing siliceous mudstone is characterized by large specific surface area and substantial pore volume but lower brittleness index， porosity， and permeability compared to the massive mixed siliceous-calcareous mudstone， thereby identified as the secondary favorable lithofacies.

Characteristics and controlling factors of high-quality reservoirs of mixed siliciclastic-carbonate sediments in the 1^st to 2^nd members of the Paleogene Shahejie Formation， Zhuanghai area， Bohai Bay Basin

Huan TONG, Shifa ZHU, Hang CUI, Wendian CAI, Lichi MA

2024, 45(4):  1106-1120.  doi:10.11743/ogg20240415

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Mixed siliciclastic-carbonate sediments （MSCSs） occur extensively in the 1^st to 2^nd members of the Shahejie Formation （Es_1-2）， Zhuanghai area， Bohai Bay Basin. Over recent years， breakthroughs have been constantly achieved in hydrocarbon exploration in the MSCSs in the Zhuanghai area， making these rocks gradually become significant exploration targets of the Paleogene strata. Using techniques such as core observation， thin section observation， scanning electron microscopy （SEM）， and porosity and permeability analyses， we investigate the characteristics of MSCS reservoirs in the Zhuanghai area and the factors controlling the formation of high-quality reservoirs within. The results indicate that terrigenous clastic grains in the MSCSs in the Zhuanghai area are dominated by proximal sediment and exhibit lowmaturity in rock component. Rock debris originating from the Changdi uplift is dominated by intermediate-acidic extrusive rock detritus， while that from the Chengdao uplift consists primarily of the detritus of metamorphic rocks such as quartzites. Using terrigenous clasts， chemogenic micritic carbonates， and biogenic carbonate grains as three end-members， the MSCSs in the Zhuanghai area are categorized into four types： terrigenous clast-dominated MSCSs （terrigenous clast content： 50 % to 85 %）， chemically precipitated carbonate-dominated MSCSs （chemically precipitated carbonate content： 50 % to 90 %）， ortho-MSCSs （contents of the three components： all less than 50 %）， and bioclast-dominated MSCSs. The reservoirs of bioclast-dominated MSCSs exhibit the most favorable physical properties among others， with an average porosity ranging from 15 % to 25 % and storage spaces composed largely of primary intergranular and bioclastic pores. Micritization and the sparry cementation on the rims are the most developed in the bioclast-dominated MSCSs， with the rigid framework formed by both allowing for the preservation of primary pores. Meteoric water leaching and organic acid charging are conducive to the formation of secondary pores in the MSCS reservoirs. Carbonate cementation with poikilitic textures is the most developed in the ortho-MSCSs， while continuous compaction produces the most significant impacts on the chemically precipitated carbonate-dominated MSCSs. Favorable conditions for the formation of high-quality MSCS reservoirs include （1） the high rock-texture maturity and bioclastic content in the depositional period； （2） the development of micrite coats， meteoric water leaching， and the formation of the sparry cements around the rims during the penecontemporaneous period， and （3） strong organic acid dissolution during the burial and diagenetic period.

Fine characterization and lithologic trap distribution patterns of delta-beach bar sedimentary system under high-precision sequence constraints： A case study of the upper submember of the 4^th member of the Shahejie Formation in the eastern segment of the southern gentle slope of Dongying Sag， Jiyang Depression， Bohai Bay Basin

Chenglong LIU, Yanzhong WANG, Huaiyu YANG, Yingchang CAO, Shuping WANG, Chaofan GUO, Hao GUO, Zhaoxiang CHEN, Linkun SONG, Xinyuan HUANG

2024, 45(4):  1121-1141.  doi:10.11743/ogg20240416

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The study aims at revealing the development of lithologic traps in the lowstand systems tract （LST） in the slope zone in a downfaulted basin， and investigates the LST in the upper submember of the 4^th member of the Shahejie Formation （the Sha 4 Member） in the eastern segment of the southern gentle slope zone of the Dongying Sag， Jiyang Depression， in the Bohai Bay Basin （the study area）. Using data from cores and logs， we examine the high-precision division， comparison， and dynamic evolution of sequences and perform the fine characterization of sedimentary microfacies in the planar view. The results indicate that the LST in the upper submember of the Sha 4 Member can be divided into three parasequence sets composed of nine parasequences， presenting six， four， and five stratigraphic superposition patterns at the parasequence， parasequence set， and systems tract levels， respectively. The LST in the study area experienced nine relative lake-level fluctuations at the parasequence level， receiving sufficient sediment supply during the relative lake level falls. This led to a planar distribution characterized by predominant basin-margin progradation transitioning to intrabasinal progradation. The LST contains a delta-beach bar sedimentary system comprising three sedimentary facies， namely the fan delta， delta， and beach bar facies， which can be further divided into seven sedimentary microfacies. Lithologic traps have been formed within the LST， with sand bodies pinching out in beach bars’ main bodies and beach ridge microfacies as reservoirs， mudstones formed by lacustrine transgression at the bottom of parasequences and parasequence sets as local seals， and mudstones in the transgressive systems tract （TST） as regional seals.

Wettability and its major determinants of shale reservoirs in the Shahejie Formation， Dongying Sag， Bohai Bay Basin

Qianwen LI

2024, 45(4):  1142-1154.  doi:10.11743/ogg20240417

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Wettability， a factor influencing the occurrence and seepage patterns of shale oil in reservoirs， is an important indicator of shale reservoir evaluation. Using contact angle measurements and spontaneous imbibition experiments， we quantitatively characterize the wettability of shale reservoirs in the Shahejie Formation， Dongying Sag， Bohai Bay Basin， while delving into the primary determinants of wettability， and selecting the optimal reservoirs for assessment. The findings suggest that the shale reservoirs in the Shahejie Formation exhibit moderate pore connectivity and fractional wettability， generally proving to be water-wet to weakly water-wet. The reservoir wettability is jointly determined by organic matter characteristics， mineral components， pore size， and shale oil composition. The impacts of organic matter and mineral composition on reservoir wettability depend on the interfacial tension of solid particles. Specifically， a higher abundance of organic matter and a higher calcium content in minerals are associated with reduced water wettability and stronger oil wettability of the reservoirs. The oil-bearing capacity and shale oil components alter the surface tension of liquids， further influencing the reservoir wettability. A higher oil-bearing capacity of reservoirs and the presence of more polar components in crude oil suggest stronger oil wettability. Pore structure influences the solid-liquid interfacial tension through capillary pressure， further affecting the reservoir wettability. A larger pore size corresponds to weaker water wettability and stronger oil wettability of the reservoirs. The wettability assessment results demonstrate that lamellar organic-rich calcareous shales exhibit the strongest lipophilicity. Shale oil tends to be enriched and accumulate in these shales under weakly water-wet conditions， creating conducive conditions for shale oil production. Therefore， these shales serve as favorable targets for shale oil exploration and production.

Characteristics and factors controlling the development of weathered crust reservoirs in buried granite hills， YA area， Songnan swell， Qiongdongnan Basin

Yuancao GUO, Jianhua GUO, Haigang LAO, Zhiyu LI, Ye YU, Guang Chen, Shiqing WU, Yanran HUANG

2024, 45(4):  1155-1167.  doi:10.11743/ogg20240418

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This study aims to reveal the developmental mechanisms and scale of hydrocarbon reservoirs in buried granite hills in the YA area， Songnan swell， Qiongdongnan Basin. Using the analytical and test data of cores， physical properties， elements， and apatite fission tracks， as well as log and seismic interpretations， we investigate the characteristics and factors controlling the development of weathered crust reservoirs in the buried granite hills， as well as the developmental history and residual thickness of the weathered crust. The results indicate that the granite series in the YA area are formed during the Early Triassic of the Indo-Chinese Epoch. The granite basinal basement underwent multiple tectonic uplifts and subsidence from the Paleocene to the Miocene， during which the weathered crust is formed and preserved in two distinct phases. The tropical monsoon paleoclimate promoted the chemical weathering of the granite series in the area. Key factors governing the development of the weathered crust of ancient buried hills in the area include regional tectonic evolution， paleoclimate， and rock types. The weathered crust exhibits significantly different developmental degrees across the area， with the weathered granite crust at paleo-structural crests exhibiting substantial residual thicknesses. Granites in the YA area possess distinct calc-alkaline to alkaline and meta-aluminous to peraluminous characteristics， which make them prone to weathering. Vertically， the weathered crust in the YA area can be categorized into five layers， namely eluvial-deluvial， sandy， weathered fractured， horizontal phreatic， and bedrock layers from top to bottom. The weathered fractured layer， among others， emerges as the most favorable reservoir， demonstrating an average porosity of 11.46 % and an average permeability of 5.98 ×10^-3 μm²， and its physical properties deteriorate with increasing burial depth. The weathered granite crust exhibits high natural gamma-ray （GR）， high resistivity， low density， and high interval transit time values， as indicated on logging curves， which are consistent with its physical property evolution. Furthermore， there exists a positive correlation between the degree of high-amplitude anomalies in seismic wave reflections and the developmental degree of fractures within the weathered crust.

Methods and Technologies

Recent advances in geological carbon dioxide storage and utilization

Guangfu WANG, Yang LI, Rui WANG, Yingbang ZHOU, Ying JIA

2024, 45(4):  1168-1179.  doi:10.11743/ogg20240419

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To promote carbon dioxide （CO₂） emission reduction and achieve carbon neutrality， we analyze recent technical advances in carbon capture， utilization， and storage （CCUS）， highlighting existing challenges and future directions. The findings indicate that the global CCUS industry is undergoing rapid growth， with the number of large-scale CCUS projects worldwide reaching up to 392 by the end of 2023， twice the number in 2022， demonstrating the preliminary commercial viability of CCUS. Significant progress have been made in the research and application of the geological storage and utilization of CO₂， including （1） the use of representative elementary volume （REV） in the characterization and modeling of geological CO₂ storage reservoirs， enabling the application of microscopic properties to macroscopic geological models； the utilization of strain tensors in the dynamic characterization and monitoring of storage reservoirs； the comprehensive application of many techniques， including geochemical imaging， micro-seismic， fiber optics， and geothermal and atmospheric monitoring for leakage detection of the CO₂ storage reservoirs； and the development of simulation techniques to simulate various CO₂ plume migration scenarios and sequestration potentials in the storage reservoirs， tailored to the various types of sedimentary reservoirs； （2） the wide application of big data technologies and artificial intelligence （AI） in CCUS， including the development of proxy models for the rapid risk assessment of CO₂ sequestration based on deep learning and coupled geomechanics and the utilization of machine learning to predict or assess the CO₂ enhanced oil recovery （EOR） and storage efficiency in residual oil zones； （3） significant progress in the new techniques for CO₂ EOR and their application in new fields. Emerging techniques， such as alternating injection of CO₂ and low mineralized water， CO₂ micro-nano bubble flooding， thickener-assisted CO₂ flooding， and CO₂ foam flooding， have shown promising results in field tests. Furthermore， the application of CO₂ flooding has expanded from medium- to low-permeability sandstone oil reservoirs and tight sandstone oil reservoirs to residual oil zones （ROZs）， and shale oil and gas reservoirs. However， there are still challenges related to the safety of the long-term sequestration of captured CO₂， economic viability， and technical uncertainties. Therefore， it is necessary to further improve existing laws and regulations while vigorously developing new techniques for the geological storage and utilization of CO₂ by conducting multidisciplinary research and technological innovation， and promoting international cooperation， with a view to ensuring the safety of the long-term storage of captured CO₂ and enhancing the economic viability of commercial operations.

Interaction mechanism between supercritical carbon dioxide and shale

Yibo LI, Yaowang CHEN, Jinzhou ZHAO, Zhiqiang WANG, Bing WEI, Kadet Valeriy

2024, 45(4):  1180-1194.  doi:10.11743/ogg20240420

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Understanding the mechanism and pattern of interactions between supercritical carbon dioxide （SC-CO₂） and shale is crucial to the exploitation of shale oil and gas. However， there is a lack of studies on the changes in shale wettability， porosity， and permeability after SC-CO₂ injection into shale reservoirs. In this study， the changes of mineral composition and microstructures of shales are quantitatively characterized before and after SC-CO₂ soaking under different soaking time， pressure and fluid type， while taking the shales in the Longmaxi area in the Sichuan Basin. Analyses and tests of the total organic carbon （TOC） content， mineral composition， surface morphology， and low-pressure N₂ and CO₂ adsorption of shales are conducted， and the impacts of SC-CO₂ on shale porosity， permeability， and wettability are explored. The results indicate that an increase in the soaking time and pressure leads to a decrease in the contents of clay and carbonate minerals （i.e.， calcite and dolomite）， while an increase in the quartz content results in a significant decrease in the organic matter content in shales. The scanning electron microscopy （SEM） images reveal that the changes in the microscopic pore structures of shales are jointly affected by extraction， dissolution， and adsorption-induced swelling and， on the other hand， further alter shale porosity and permeability. Additionally， the variation in shale permeability is influenced by the contents of clay minerals， carbonate minerals， and organic matter. The shale wettability also changes after soaking in SC-CO₂. Specifically， as the soaking time and pressure increase， the shale-water contact angle enlarges， with the shale transitioning from strong hydrophilic to weak and moderate hydrophilic type.