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30 April 2024, Volume 45 Issue 2
Petroleum Geology
Advances, challenges, and countermeasures in shale gas exploration of underexplored plays, sequences and new types in China
Caineng ZOU, Dazhong DONG, Wei XIONG, Guoyou FU, Qun ZHAO, Wen LIU, Weiliang KONG, Qin ZHANG, Guangyin CAI, Yuman WANG, Feng LIANG, Hanlin LIU, Zhen QIU
2024, 45(2):  309-326.  doi:10.11743/ogg20240201
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In recent years, China has shifted its focus of shale gas exploration to underexplored plays, sequences and new types (collectively referred to as the “three new fields”). This shift has led to intensified efforts in addressing theoretical challenges and enhanced exploration, elevating both the reserves and production of shale gas to new levels. Based on new advances in theoretical research and exploration in the three new fields, we analyze the characteristics, trends, and prospects of shale gas exploration in these fields, explore theories on the unique shale gas geology in China, and identify challenges in shale gas exploration and corresponding countermeasures. The results indicate that China has developed innovative theories on the enrichment of highly- to over-mature marine shale gas with distinct characteristics of shales in the Wufeng-Longmaxi formations within the Sichuan Basin and its surrounding areas. A total of nine shale gas fields have been discovered in China with proven geological reserves of approximately 3×1012 m3, resulting in a shale gas productivity of 450×108 m3/a, and an annual shale gas production of 250×108 m3. Furthermore, we ascertain three major characteristics of the shale gas exploration in the three new fields in China: (1) significant progress in deep and extremely shallow strata for shale gas exploration of the Wufeng-Longmaxi formations within the Sichuan Basin and its surrounding areas; (2) breakthroughs in multiple underexplored units, such as the Qiongzhusi and Wujiaping formations in the Sichuan Basin; and (3) discoveries and breakthroughs in the Wulalike and Shanxi formations located on the western and eastern margins of the Ordos Basin, respectively. Three major strategic shifts have been achieved: (1) a shift in exploration target from a single type, basin, and unit to multiple types, basins, and units; (2) a shift of target area selection from focusing on the interiors or peripheries of basins to including basins’ exterior with weak tectonic modification; (3) a shift in the exploration philosophy from pure organic-rich shales to organic-rich shale systems. Analyzing challenges in shale gas exploration in the three new fields in China leads to the conclusion that these fields both represent the direction for the sustainable development of shale gas in China and need corresponding countermeasures for their progress.

Current status, advances, and prospects of CNPC’s exploration of onshore moderately to highly mature shale oil reservoirs
Zhe ZHAO, Bin BAI, Chang LIU, Lan WANG, Haiyan ZHOU, Yuxi LIU
2024, 45(2):  327-340.  doi:10.11743/ogg20240202
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China National Petroleum Corporation (CNPC) boasts abundant continental shale oil resources in areas covered by its mineral rights. The national hydrocarbon resource evaluation of the 13th Five-Year Plan reveals that CNPC’s geological resources of onshore moderately to highly mature shale oil (hereinafter referred to as shale oil) are estimated at 201 × 108 tonnes, accounting for 71 % of the national total. Shale oil production has increased significantly in key plays such as the 7th member of the Yanchang Formation in the Ordos Basin, the Qingshankou Formation in the Songliao Basin, and the Lucaogou Formation in the Junggar Basin, rising from 2.5 × 104 tonnes in 2010 to 391.6 × 104 tonnes in 2023, suggesting enormous potential for shale oil exploration. The study results reveal that CNPC’s commercial exploration of continental shale oil is facing challenges in both geological understanding and techniques due to the highly heterogeneous geological characteristics and significantly different factors determining the enrichment and high productivity across various types of continental shale oil reservoirs. Notably, despite large-scale exploration in the 1st and 2nd submembers of the 7th member of the Yanchang Formation in the Ordos Basin, intercalated shale oil reservoirs exhibit greatly varying drilling ratio for targets under exploration, limited research on fine-grained sedimentary sequences of deep lacustrine facies, and the low accuracy of techniques for characterizing the spatial distribution of targets. Shale oil reservoirs of the mixed type exhibit great vertical thicknesses, frequent lithological variations, and multiple suites of sweet spots. Despite breakthroughs in the Qaidam and Bohai Bay basins, the exploration of these reservoirs is constrained by greatly different vertical shale oil production in geological sweet spots, ambiguous major factors contributing to high shale oil production, and imperfect techniques and methods for evaluating and selecting dominant targets. For the exploration of shale oil reservoirs of the pure shale type, breakthroughs have been achieved in the Gulong shale oil reservoirs of the Qingshankou Formation in the Songliao Basin. Nevertheless, due to greatly different hydrocarbon generation and expulsion characteristics and significantly varying in-situ hydrocarbon retention across various types of shales in continental lacustrine basins, it remains necessary to further investigate the geo-engineering integrated techniques and methods for target evaluation. Overall, CNPC’s exploration and exploitation of shale oil reservoirs are still rapidly advancing. In the future, it is necessary to intensify research on the genetic mechanisms of various sand bodies in deep parts of fresh lacustrine basins to achieve the commercial exploration of intercalated shale oil reservoirs such as thinly laminated turbidite sand bodies. For shale oil reservoirs of the mixed type, there is a need to enhance the evaluation of source rock-reservoir assemblages of these reservoirs enriched in carbonate in saline lacustrine basins. This will enable the preferential selection of primary targets for efficient exploration. Furthermore, differential evaluations of hydrocarbon generation and expulsion should be underlined for high-quality source rocks in both fresh and saline lacustrine basins to identify the optimal targets. The purpose is to achieve geo-engineering integrated, fine-scale exploration of shale oil reservoirs across various types of lacustrine basins.

A major discovery of hydrocarbon-bearing layers over 1,000-meter thick in well Shunbei 84X, Shunbei area, Tarim Basin and its implications
Zicheng CAO, Lu YUN, Lixin QI, Haiying LI, Jun HAN, Feng GENG, Bo LIN, Jingping CHEN, Cheng HUANG, Qingyan MAO
2024, 45(2):  341-356.  doi:10.11743/ogg20240203
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The NE-trending strike-slip fault zones in the central Shunbei area, Tarim Basin have long been the destination of hydrocarbon migration, accumulation, and enrichment. Dilling has revealed the occurrence of fault-controlled, fractured-vuggy hydrocarbon reservoirs along the No. 8 strike-slip fault zone in the Shunbei area. Along this fault zone, 1 088-m-thick hydrocarbon column has been discovered in well Shunbei 84X. The fault-controlled, fractured-vuggy hydrocarbon reservoirs are characterized by a great hydrocarbon column height, which is independent of the heights of current structures. To identify the primary factors controlling the large hydrocarbon column height of these reservoirs, we examine the characteristics of reservoirs, traps, and hydrocarbon accumulation in well Shunbei 84X, as well as the distribution pattern of fault-controlled, fractured-vuggy hydrocarbon reservoirs within. The results indicate that the tectonic fracturing of strike-slip structures plays a crucial role in the formation of tight carbonate reservoirs. Furthermore, the depth of these reservoirs is not limited by the burial depth of carbonate strata, with fault-controlled fractured-vuggy reservoirs even identified at a burial depth of nearly 9 000 m. The formation of fault-controlled fractured-vuggy traps is primarily influenced by the top sealing capacities of the significantly thick overlying mudstone cap rocks, the side sealing capacities of tight limestones on both sides, and the horizontal segmentation and vertical stratification of strike-slip faults. Oil-source correlation reveals that oil and gas originate from the source rocks in the Cambrian Yuertus Formation, further confirming the hydrocarbon accumulation mode consisting of multiphase hydrocarbon supply from the Cambrian source rocks, reservoir formation by tectonic disruption, in-situ vertical hydrocarbon transport, a predominance of late-stage accumulation, and strike-slip fault-controlled hydrocarbon enrichment in the east-central Shunbei area. The major discovery in well Shunbei 84X in the Shunbei area highlights the presence of strike-slip fault-controlled tight carbonate reservoirs with a large vertical depth and sufficient hydrocarbon charging in the Tarim Basin ultra-deep sequences. These findings suggest the considerable potential for ultra-deep hydrocarbon exploration in the Shunbei area.

New insights into the genetic types and characteristics of the Ordovician marine fault-karst carbonate reservoirs in the northern Tarim Basin
Debin YANG, Xinbian LU, Dian BAO, Fei CAO, Yan WANG, Ming WANG, Runcheng XIE
2024, 45(2):  357-366.  doi:10.11743/ogg20240204
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The previously coined fault-karst reservoirs have become new exploration and exploitation targets and types of marine carbonate hydrocarbon reservoirs. However, these reservoirs are significantly different from conventional weathering-crust karst reservoirs and also show diverse reservoir types and structural characteristics themselves. By delving into the differences in the dissolution and tectonic fracturing of fault-karst reservoirs, we categorize these reservoirs into three types: the over-dissolved residual type, the fractured and highly dissolved type, and the highly fractured and weakly dissolved type. Investigations into these types of fault-karst reservoirs reveal that these reservoirs significantly differ in dissolution intensity, fracture and vug sizes, cumulative oil production, formation energy, and fracture-vug connectivity. Furthermore, the distribution of over-dissolved residual fault-karst reservoirs is influenced by both weathering crust unconformities and the longitudinal dissolution of fault zones. In contrast, the formation and distribution of the remaining two types, manifesting a minimal association with unconformities and tectonic locations, are primarily governed by the fracturing and dissolution intensity of dissolved fault zones. Specifically, large-scale caves occur in the cores of dissolved fault zones, gradually transitioning to fractured-vuggy and fractured reservoirs towards their both sides.

Characteristics and origin of over-dissolution residual fault-karst reservoirs in the northern Tahe oilfield, Tarim Basin
Changjian ZHANG, Debin YANG, Lin JIANG, Yingbing JIANG, Qi CHANG, Xuejian MA
2024, 45(2):  367-383.  doi:10.11743/ogg20240205
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This study aims to investigate the characteristics of the Early Hercynian paleokarst caves in the extensively eroded area of the northern Tahe oilfield in the Tarim Basin. Using methods such as paleogeomorphic reconstruction, karst water system analysis, logging-core observation-based cave identification, and seismic attribute characterization, we identify the cave types and styles in well block YQ5, characterize fracture-cave structures in this area, and explore the origin of the caves. The results show that the well block YQ5, located in the region with flat and gentle terrain to the north of Nos.Ⅱ and Ⅲ paleokarst platforms of the Tahe oilfield, generally exhibits residual landforms after modification by multi-phase superimposed karstification. Karst peak-depression, karst hill-depression, and karst hill-plain zones of low relief are primarily observed in the well block, with peak cluster-ridge/valley zones extending in the NE direction in the south. Different from the main body and slope area of the Tahe oilfield, the well block YQ5 displays a flow direction of the underground and surface water systems inconsistent with the geomorphic trend. Furthermore, the disrupted karst water system therein by tectonism, leads to an incomplete karst water cycle of recharge, runoff, and discharge. Caves of underground river type and over-dissolution residual fault-karst reservoirs are primarily found in the well block. The caves of underground river type are characterized by significant filling, which compromises the effectiveness of reservoir spaces, thus adversely affecting oil and gas exploitation. In contrast, for the over-dissolution residual fault-karst reservoirs, the vertical erosion along strike-slip faults, resulting from a decline in regional erosion base level due to the tectonic uplift of the karst platforms, is beneficial to the continuous development and preservation of these reservoirs, thus contributing to effective oil and gas exploitation. Overall, the dominant factors for the over-dissolution residual fault-karst reservoirs encompass the development of strike-slip faults, the denudation intensity of strata, and negative landforms. Consistent with the paleokarst platforms observed in the Tahe oilfield, karst in the well block YQ5 also experienced three evolutionary stages: the deeply incised meandering river stage, the karstification-induced modification stage, and the infiltrated fault-karst stage. During these stages, caves of underground river type underwent continuous transformation and destruction, while the fault-karst reservoirs experienced ongoing construction.

Geochemical characteristics and enrichment factors of helium-bearing natural gas in the Ordos Basin
Chenglin LIU, Zhengang DING, Liyong FAN, Rui KANG, Sijie HONG, Yuxin ZHU, Jianfa CHEN, Haidong WANG, Nuo XU
2024, 45(2):  384-392.  doi:10.11743/ogg20240206
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The Ordos Basin is renowned for its rich natural gas resources, which exhibit a high helium content in some areas. Therefore, there is an urgent need to thoroughly investigate the geochemical characteristics and enrichment factors of helium-bearing natural gas. Based on the experiments, analysis, and tests of the compositions and isotopes of natural gas samples, along with geological conditions, we examine the distribution, geochemical characteristics, and controlling factors of helium-bearing natural gas in the Ordos Basin. Key findings are as follows: (1) The natural gas in the basin is dominated by hydrocarbon gases, with a helium content ranging from 0.016 % to 0.487 % (average: 0.060 %); (2) The carbon isotope values of methane in the helium-bearing natural gas within the basin range from -53.88 ‰ to -29.23 ‰, and those of methane, ethane, propane, and butane indicate an organic origin of the hydrocarbon gases; (3) The helium-bearing natural gas in the Ordos Basin exhibits 3He/4He ratios ranging from 20.10×10-9 to 120.00×10-9, with an average of 42.00×10-9, and R/Ra ratios varying between 0.014 and 0.085, with an average of 0.030. These ratios represent crust-derived helium characteristics, which are unaffected by the genetic type and maturity of natural gas; (4) The natural gas with a high helium content is primarily distributed in the Carboniferous-Permian strata of the Upper Paleozoic of Dongsheng gas field (north of the basin), Qingyang gas field (southwest of the basin) and Huanglong gas field (southeast of the basin). This distribution is closely associated with factors like ancient and modern tectonic locations, basement faults, and the intensities of helium and hydrocarbon generation. Based on the geochemical characteristics of helium-bearing natural gas, we identify helium-rich-to-moderate, low-helium, and helium-deficient areas in the Ordos Basin.

Geobiological evaluation of hydrocarbon-generating organisms and source rocks in the Ordovician Majiagou Formation, east-central Ordos Basin
Junyu WAN, Jianhui ZHU, Suping YAO, Yi ZHANG, Chuntang LI, Wei ZHANG, Haijian JIANG, Jie WANG
2024, 45(2):  393-405.  doi:10.11743/ogg20240207
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Over recent years, breakthroughs have been achieved in the pre-salt natural gas exploration in the Ordovician Majiagou Formation, east-central Ordos Basin. Given the generally low total organic carbon (TOC) content in the carbonate-evaporite assemblages in the formation, there is an urgent need to seek high-quality source rocks and investigate their formation conditions. Using core samples from the Majiagou Formation in the east-central Ordos Basin, we analyze the formation’s paleoecology, paleoenvironment, and hydrocarbon-generating organisms, delving into the characteristics of hydrocarbon-generating organism assemblages and their changes with the paleoenvironment. Furthermore, we perform geobiological grading evaluation using habitat types and biogenic Ba as biological indices, alongside the V/(V+Ni) ratio and mineral types in evaporites as geological indices. Key findings are as follows: (1) The hydrocarbon-generating organisms in the Majiagou Formation encompass planktonic algae, benthic red algae, benthic brown algae, and benthic blue-green algae. (2) During the deposition of the Majiagou Formation, water bodies with high biological productivity created conditions for the formation of source rocks. Specifically, the high-frequency sea-level fluctuations and the alternating dry and wet climates induced frequent changes in the salinity and redox conditions of water bodies. Therefore, the favorable conditions for organic matter preservation serve as the key to the formation of source rocks in the study area. (3) Geobiological facies favorable to source rock formation primarily include the marginal facies of gypsum-dolomite lagoons with halophilic algae. The mud-dolomite flat facies and gypsum-mud lagoon facies found in the shallow subtidal zones of planktonic algae, are to follow. (4) Compared with the results of residual organic carbon abundance evaluation, those of source rock geobiology are more optimistic. The effective sources rocks mainly include are gypsiferous argillaceous dolomites, argillaceous dolomites, gypsum mudstones, and dolomitic mudstones, all present as dark shaly laminae or bands.

Composition of generated and expelled hydrocarbons and phase evolution of shale oil in the 1st member of Qingshankou Formation, Songliao Basin
Bo LIU, Qi’an MENG, Xiaofei FU, Tiefeng LIN, Yunfeng BAI, Shansi TIAN, Jinyou ZHANG, Yao YAO, Xinyang CHENG, Zhao LIU
2024, 45(2):  406-419.  doi:10.11743/ogg20240208
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Shales in the first member of the Qingshankou Formation (the Qing 1 Member) in the Songliao Basin exhibit a large variation of organic matter maturity and strong heterogeneity of hydrocarbon mobility. How to analyze the shale oil phase and physical properties has posed a major challenge for efficient shale oil exploitation and production. We investigate the characteristics of shale oil composition evolution by carrying out closed and semi-closed organic matter pyrolysis experiments on low-maturity shale samples, in which compensation correction for light hydrocarbon loss of retained hydrocarbons is performed based on the composition of generated and expelled hydrocarbons. By integrating the burial and thermal evolution histories of typical wells in main source kitchens in the Central Depression, we explore the phase evolution pattern of shale oil. Furthermore, we identify play fairways for light shale oil exploration and outline protection conditions for maintaining production pressure. The results reveal that under geological conditions, light components’ proportions and gaseous hydrocarbon content in shale oil increase progressively with the maturity of organic matter. Concurrently, the phase envelopes evolve from high dew point temperature (DPT) and low bubble point pressure (BPP) toward low DPT and then to high BPP with an increase in the organic matter maturity. In the Qijia-Gulong Sag, the shale oil reservoirs of the Qing 1 Member evolved into light oil reservoirs in the middle stage of the Nenjiang Formation deposition. In the Changling Sag, these reservoirs began to evolve into light oil reservoirs at the end of the Nenjiang Formation deposition. In contrast, these reservoirs in the Sanzhao Sag have been consistently present as black oil reservoirs. Shale oil within both black and volatile oil reservoirs remains in a single liquid phase. In the Central Depression of the Songliao Basin, the light shale oil reservoirs of the Qing 1 Member are primarily distributed at the center of the Qijia-Gulong Sag and in the northern Changling Sag, with maturity of organic matter (Ro) varying from 1.3 % to 1.6 % and formation pressure from 12.2 to 22.4 MPa.

Characteristics and differential origin of Qiongzhusi Formation shale reservoirs under the “aulacogen-uplift” tectonic setting, Sichuan Basin
Xiao HE, Maja ZHENG, Yong LIU, Qun ZHAO, Xuewen Shi, Zhenxue Jiang, Wei WU, Ya WU, Shitan NING, Xianglu TANG, Dadong LIU
2024, 45(2):  420-439.  doi:10.11743/ogg20240209
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The Qiongzhusi Formation, following the Wufeng-Longmaxi formations, has been recognized as a promising target for future shale gas exploration and exploitation in the Sichuan Basin. Presently, notable achievements have been made in shale gas exploration in wells Z201 and WY1, drilled at the center and margin of the Deyang-Anyue aulacogen, respectively. However, there is a lack of clear understanding of the Qiongzhusi Formation shale reservoirs occurring in the aulacogen. Focusing on wells Z201 and WY1, coupled with other data on shale gas exploration and exploitation, we systematically analyze the mineral and organic geochemical characteristics, reservoir and storage space characteristics, and gas-bearing properties of each shale in the Qiongzhusi Formationin the study area. Key findings are outlined as follows. (1) The Qiongzhusi Formation shales in the study area can be divided into eight layers, predominantly composed of brittle minerals overall. This formation generally exhibits total organic carbon (TOC) content exceeding 1 %, suggesting high-quality source rocks. Furthermore, the TOC content is higher within the aulacogen than on its margin, indicating favorable gas generation conditions.aulacogen (2) Both organic and inorganic pores are found in the Qiongzhusi Formation shales, more prevalent within the aulacogen, contributing to extremely high gas content. Black shale reservoirs in layers 1, 3, 5, and 7 exhibit high quality, especially the layer 5. (3) The quality of shale reservoirs in the Qiongzhusi Formation is governed by the Deyang-Anyue aulacogen. Specifically, reservoirs encountered in drilling well Z201, situated within the aulacogen, exhibit superior characteristics compared to those in well WY1 located at the margin. (4) The degree of organic matter evolution in the Qiongzhusi Formation shales is significantly influenced by the Leshan-Longnvsi paleo-uplift. The organic matter generally tends to be less mature within than outside. The moderate-degree organic matter evolution within the paleo-uplift creates conditions favorable to large-scale gas enrichment. Therefore, high-quality Qiongzhusi Formation shale reservoirs are identified as a major successor play for future shale gas exploration and exploitation.

Sedimentary microfacies characteristics and organic matter enrichment pattern of the 1st member of the Middle Permian Maokou Formation, southwestern Sichuan Basin
Changbo ZHAI, Liangbiao LIN, Donghua YOU, Fengbin LIU, Siyu LIU
2024, 45(2):  440-456.  doi:10.11743/ogg20240210
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This study aims to investigate the sedimentary microfacies and organic matter enrichment pattern of the 1st member of the Middle Permian Maokou Formation (hereafter referred to as the Mao 1 Member) in the Sichuan Basin. Based on petrological and sedimentary microfacies analyses, we summarize eight sedimentary microfacies (MF1-MF8) in the Mao 1 Member on the Shawan outcrop in Leshan, southwestern Sichuan Basin, encompassing bioclastic calcareous mudstone (MF1), bioclastic marl (MF2), bioclastic argillaceous limestone (MF3), marly limestone (MF4), bioclastic wackestone (MF5), calcareous algal wackestone (MF6), bioclastic packstone (MF7), and calcareous algal packstone (MF8). The sedimentary paleoenvironment and geochemical analyses result in the following conclusions. (1) In the early to middle stages of the Mao 1 Member’s deposition, MF2 was predominantly formed, followed by MF7 and MF8. This period was characterized by a transgressive and anoxic environment overall, marked by the presence of upwelling ocean currents and high primary productivity. The middle to late stages of the Mao 1 Member’s formation primarily witnessed the occurrence of MF6, MF7, and MF8. This period featured relative regression, with slightly increased oxygen content, weakened upwelling ocean currents, and decreased primary productivity. In the final stage of its deposition, the Mao 1 Member was dominated by MF2, with slightly increased oxygen content and enhanced primary productivity. (2) The organic matter enrichment in the member was predominantly influenced by marine primary productivity and anoxic environment, while under the indirect influence of upwelling ocean currents. Specifically, a setting of higher primary productivity and lower oxygen content is conducive to the enrichment and preservation of organic matter. Furthermore, upwelling ocean currents facilitate the transport of nutrients from deeper parts, thus enhancing the marine primary productivity. (3) MF2 and MF7, characterized by stable regional distributions and depositional environments with higher primary productivity and lower oxygen content, represent favorable sedimentary microfacies for organic matter enrichment in the Mao 1 Member.

Sedimentary microfacies and environmental evolution of the Middle Permian Maokou Formation in the eastern Sichuan Basin: A case study of the Yangjiao section in Wulong District, Chongqing, China
Heyi ZHANG, Shuai YANG, Xihua ZHANG, Hanlin PENG, Qian LI, Cong CHEN, Zhaolong GAO, Anqing CHEN
2024, 45(2):  457-470.  doi:10.11743/ogg20240211
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In recent years, industrial gas flow has been obtained in the Permian Maokou Formation in the eastern Sichuan Basin, underscoring the great significance of exploring the sedimentary microfacies and environmental evolution of the formation for oil and gas exploration. This study focuses on the Yangjiao section in Wulong District, Chongqing, China. Based on the field observations of sedimentary characteristics, coupled with thin section observation and geochemical analysis, we delve into the sedimentary microfacies and sedimentary environmental evolution characteristics of the Maokou Formation. The results reveal the predominant distribution of five sedimentary microfacies. Bioclast-bearing micrites and micrites, deposits in a deep-water, low-energy environment, prevail in the lower formation. The middle formation exhibits the primary distribution of sparry bioclastic limestones, micritic bioclastic limestones, bioclastic micrites, and bioclastic micrites, and the presence of sparry bioclastic limestones suggests a shallow-water, high-energy sedimentary environment. The upper formation predominantly contains micritic bioclastic limestones, bioclastic micrites, and bioclast-bearing micrites, and the water becomes deeper again. Geochemical analysis reveals that the lower Maokou Formation exhibits low δ13Ccarb values with an average of 3.00 ‰, while its middle and upper portions show δ13Ccarb values mostly exceeding 4.00 ‰. These findings suggest that the formation’s first member was deposited in an anoxic environment, which converted into a dysoxic environment with an increase in oxidation and then recovered to an anoxic environment in the late depositional stage. The sedimentary microfacies characteristics and the sea-level changes in the Maokou Formation in the eastern Sichuan Basin were affected by glacial periods, with the global sea-level drop serving as the dominant factor in the sedimentary environment transitions. The shallow-water sedimentary environment created favorable geological conditions for the emergence of high-energy grainstone shoals, which is, in turn, the main cause of the formation of high-quality reservoirs in the middle and upper Maokou Formation in the basin.

Evaluation of geological sweet spots in fluvial tight sandstone gas: A case study of the first submember of the second member of the Jurassic Shaximiao Formation, central Sichuan Basin
Hui PAN, Yuqiang JIANG, Xun ZHU, Haibo DENG, Linke SONG, Zhanlei WANG, Miao LI, Yadong ZHOU, Linjie FENG, Yongliang YUAN, Meng WANG
2024, 45(2):  471-485.  doi:10.11743/ogg20240212
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Reservoirs of the Jurassic Shaximiao Formation in the Sichuan Basin feature low porosity and permeability, strong heterogeneity, and complex sand body superposition. These characteristics complicate the identification and accurate prediction of geological sweet spots. To achieve efficient exploitation of the gas reservoirs, we establish the criteria for evaluating geological sweet spots in tight sandstone gas in the 1st submember of the 2nd member of the Shaximiao Formation (the Sha 21 submember) in the study area by delving into the effects of the sedimentation, diagenesis, and source rock-reservoir configuration on the formation and hydrocarbon accumulation of these gas reservoirs. Key findings are as follows. (1) The sand body scale and reservoir physical properties are governed by sedimentary microfacies and channel types. Notably, sand bodies located within the point bars of straight or low-sinuosity meandering rivers exhibit large thicknesses and favorable physical properties, standing as high-quality reservoirs. (2) Reservoir quality discrepancy primarily results from differences in lithic content in magmatic rocks and diagenetic facies. Specifically, the chlorite-cemented facies exhibits the most favorable physical properties. (3) Natural gas charging in the reservoirs is dictated by the source rock-reservoir configuration. Most especially, sand bodies in contact with or in proximity to source rock-rooted faults boast the most favorable gas-bearing properties. (4) The single-well natural gas production is jointly determined by reservoir quality and gas-bearing properties. Based on the evaluation criteria established in this study, the geological sweet spots in the study area are categorized into three types: types Ⅰ, Ⅱ, and Ⅲ. Type Ⅰ sweet spots primarily encompass sand bodies in the point bars of straight or low-sinuosity meandering rivers, with porosity exceeding 12 % and permeability surpassing 0.30×10-3 μm2, and chlorite-cemented facies dominating. They are situated near source rock-rooted faults, exhibiting favorable gas-bearing properties with water saturation below 30 %, Poisson’s ratio less than 0.24, and single-well gas production rate over 0.10×104 m3/(d∙m). Type Ⅱ sweet spots are dominated by sand bodies in middle-sinuosity meandering rivers, with porosity ranging from 10 % to 12 % and permeability from 0.15×10-3 to 0.30×10-3 μm2. Their diagenetic facies are dominated by illite- or mixed-layer montmorillonite-illite-cemented facies. They are positioned comparatively far from source rock-rooted faults, with water saturation ranging from 30 % to 40 %, Poisson’s ratio from 0.24 to 0.25, and single-well gas production rate from 0.05×104 to 0.10×104 m3/(d∙m). Type Ⅲ sweet spots primarily comprise sand bodies in the point bars of small-scale, medium-sinuosity meandering rivers, characterized by low porosity and permeability. Their diagenetic facies mainly include illite- or mixed-layer montmorillonite-illite-cemented facies sitting far from source rock-rooted faults and with poor gas-bearing properties.

Architectural characteristics of beach-bar reservoirs in the lower submember of the 2nd member of the Paleogene Dongying Formation in block SC7, Huanghekou Sag, Bohai Bay Basin
Changyin SHAO, Fan SONG, Shiqi ZHANG, Qiuyue WANG
2024, 45(2):  486-501.  doi:10.11743/ogg20240213
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Beach bars in block SC7 of the Huanghekou Sag, Bohai Bay Basin are identified as important reservoirs in the shore-shallow lacustrine area. Figuring out the internal structural characteristics of the beach-bar sand bodies can offer significant guidance for hydrocarbon exploitation. Based on the examination of modern analogs and data on cores and logs, we carry out architectural dissection for sand bodies in the lower submember of the 2nd member of the Dongying Formation (the Dong 2 lower submember) in block SC7, segmenting the beach-bar facies featuring thick mudstones and thin sandstones to five sedimentary microfacies: bar center, bar lateral margin, inner marginal beach, outer marginal beach, and lacustrine mud. By analyzing the origin and internal structural characteristics of the thick-mudstone and thin-sandstone beach bars, we investigate the sedimentary characteristics and pattern and growth process of the beach bars. Consequently, the beach-bar architectures are categorized into three levels, namely composite sand bar, single bar, and accretionary body, along with the exploration of the spatial distributions of these architectural units of beach bars. To identify single bars, we propose four indicators: inter-bar mudstone, logging curve characteristics, relative elevation difference, and lateral phase change of a single bar. Using these indicators, we identify single bars in the area with a dense well pattern, analyzing their scales, evolution process, and interconnectivity. Furthermore, four phases of accretionary bodies within single bars are determined, finally ascertaining the effects of 4th-level architectural interfaces, single-bar lateral phase change, and accretionary bodies within single bars on hydrocarbon distribution.

Rock mechanical properties and controlling factors for shale oil reservoirs in the second member of the Paleogene Funing Formation, Subei Basin
Hequn GAO, Yuqiao GAO, Xipeng HE, Jun NIE
2024, 45(2):  502-515.  doi:10.11743/ogg20240214
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The study aims to determine the fracturability of shale oil reservoirs and post-fracturing variations in pores and fractures in the Subei Basin. The 2nd member of the Paleogene Funing Formation (also referred to as the Fu 2 Member) is taken as an example to investigate the rock mechanics and fracturing performance and the relevant influencing factors. This process involves three steps: a. Three-dimensional (3D) reconstruction of rock samples using high-resolution computed tomography (i.e., multi-scale CT scanning) to extract structural parameters of pores and fractures; b. Triaxial mechanical experiments under the confining pressure of the formation to obtain rock mechanical parameters; c. Multi-scale CT scanning of fractured rock samples at the same position and along the same direction to obtain an image of the post-fracturing 3D structures of pores and fractures. Based on the characteristics of stress-strain curves, shales in the study area are categorized into three types. Type 1 is characterized by rupture curves with a wavy downward trend, indicative of intricate post-fracturing reticular fractures. Type 2 shows various rupture curves with both wavy and vertical downward trends, indicating well-developed fracture networks after fracturing. Type 3 exhibits rupture curves with a vertical downward trend, suggesting relative intactness after fracturing with the formation of longitudinal splitting fractures rather than fracture networks. Post-fracturing changes in pores within the three types of shales are as follows. For the first and second types, pores with diameters ranging from 10 to 50 μm represent a decreased proportion, those with diameters between 50 and 100 μm show an increased proportion, and those larger than 300 μm in diameter make a greater contribution to the overall pore volume. In contrast, for the third type, pores with varying diameters demonstrate insignificant changes in proportion and contribution to the overall pore volume after fracturing. The study results reveal that the compressive strength positively correlates with the elastic and shear modulus and exhibits V-shaped relationship with Poisson’s ratio. The mechanical properties of shales in the study area are primarily governed by their carbonate and clay mineral contents, followed by their quartz and organic carbon contents. Furthermore, porosity and lamina development characteristics emerge as significant factors influencing the fracturability of shale reservoirs.

Types and distribution patterns of complex turbidite sandstone reservoirs in the upper reaches of deep-water canyons—A case study of the Lingshui gas field in the Central Canyon of Qiongdongnan Basin
Chao FU, Yuhong XIE, Yuchu ZHAO, Hui WANG, Zhiwang YUAN, Wei XU, Guoning CHEN
2024, 45(2):  516-529.  doi:10.11743/ogg20240215
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The Lingshui gas field, located in the upper reach of the Central Canyon in the Qiongdongnan Basin, shows the occurrence of turbidite sandstones. However, the turbidite sandstone reservoirs of diverse types, jointly affected by both sedimentation and diagenesis, present challenges in characterization. This study aims to forecast the distribution of favorable reservoirs in the deep-water areas of the Lingshui gas field. Based on the morphologies and burial depths of the Central Canyon, we categorize the upper reach of the canyon head into the adjustment section, the low-tortuosity section, and the curved section. This division allows for a detailed examination of the reservoirs’ fracture and filling types in the reservoirs. Furthermore, we analyze the deposition and origin of the reservoir rocks based on the quantitative relationships between rock fabric and physical properties. The results indicate that the adjustment section is dominated by coarse-grained gravity flow deposits, with reservoir physical properties gradually improving downstream as the intergranular matrix content declines. The low-tortuosity section is primarily composed of fine-grained to silty turbidite sand bodies, with grain sizes marginally varying along the canyon and cementation emerging as a factor affecting the quality of reservoirs consisting of alternating thin- and thick-bedded sandstone. The curved section principally comprises silty turbidite sand bodies, with reservoir physical properties gradually deteriorating downstream with an increase in the burial depth. Therefore, it can be inferred that the reservoir quality is governed by the sedimentary process in the adjustment section and the diagenesis in the low-tortuosity and curved sections.

A novel sedimentary pattern of wave-induced sandbars under high-angle wave incidence
Rui LI, Jiao YANG, Yukun CHAI, Hua WANG, Jianwen DAI, Yonghui DENG, Shuang SUN, Xiaolin MA, Tengfei TIAN
2024, 45(2):  530-541.  doi:10.11743/ogg20240216
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Wave-induced sandbars, wave-reworked deposits, are considered to resemble bands parallel to shorelines as reflected by the traditional depositional model, which, however, ignore the fact that varying angles between wave incidence direction and shoreline orientation can lead to significant differences in sedimentary patterns. In combination with the sedimentary characteristics of modern wave-induced sandbars in both the Huizhou Sag, Pearl River Mouth Basin (PRMB), and Qinghai Lake, we investigate and summarize differential sedimentary patterns of wave-induced sandbars under high-angle wave incidence. Key findings are as follows: (1) Constrained by the Dongsha Uplift, local areas on the southern margin of the Huizhou Sag manifest significant “canyon effect”, leading to high-angle wave incidence. Moreover, due to the different hydrodynamic environments at varying occurrence positions during deposition, the sand bodies of two neighboring oilfields in the Huizhou Sag exhibit significantly distinct morphologies and scales post-wave reworking; (2) Based on the dynamic sediment transport mechanism for shorelines, along with field geological survey results, wave-induced sandbars are categorized into three types: the totally closed shore-oblique type, the shore-parallel type, and the semi-open shore-oblique type. Moreover, a novel sedimentary pattern of wave-induced sandbars under high-angle wave incidence is developed; (3) Drilling results corroborate that under the novel sedimentary pattern, wave-induced sandbars on windward and leeward flanks differ enormously in morphology, scale, and superimposed style. Furthermore, lithologic hydrocarbon reservoirs with poor connectivity are prone to form between the sand bodies. The novel sedimentary pattern holds critical theoretical and practical significance for guiding the exploration and exploitation of reservoirs of wave-induced sandbars.

Methods and Technologies
Storage space types and water-flooding efficiency for fault-controlled fractured oil reservoirs in Fuman oilfield, Tarim Basin
Tongwen JIANG, Xingliang DENG, Peng CAO, Shaoying CHANG
2024, 45(2):  542-552.  doi:10.11743/ogg20240217
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Ultra-deep hydrocarbon reservoirs in the Tarim Basin, governed by strike-slip faults, have become a pivotal target in China’s hydrocarbon exploration and exploitation efforts in recent years. However, the storage space types of these reservoirs, as well as their relationships with water-flooding efficiency, are yet to be clarified, presenting a significant challenge to the efficient development of the Fuman oilfield. Based on thorough analyses of outcrops, core samples, formation micro-imaging (FMI) logs, and dynamic monitoring data, we introduce the concept of fault-controlled fractured reservoir to refer to the those in the Fuman oilfield, and systematically explore the three major storage space types and their relationships with the water-flooding efficiency. Key findings are as follows: (1) Fault cavity-type reservoirs, predominantly found in the core of the fault zones, feature hollow cavities created by adjustments of internal special volume after multi-stage structural activities on the faults’ sliding surfaces. The storage spaces of these reservoirs, relatively enclosed under burial conditions, are characterized by large pore volumes. This structural configuration enhances oil-water displacement efficiency, with some oil wells yielding a waterflooding recovery factor up to 93 % of the petroleum reserves in development; (2) Inter-breccia pore-type reservoirs, also primarily distributed in the fault zones’ core, feature inter-breccia irregular storage spaces formed by the mutual support of adjacent breccias. These reservoirs exhibit a relatively uniform distribution, moderate porosity, and high liquid yield per unit pressure drop. However, the poor internal connectivity for the storage spaces leads to a low oil replacement rate by water injection. Therefore, it is necessary to explore the construction of a three-dimensional well pattern to improve development efficiency. (3) Structural fracture-type reservoirs are primarily distributed in the damage and process zones of the fault zones, with fracture zones with certain widths developing along the fault zones’ both sides and ends. In addition, a small number of pores are present around these fracture zones, with dominant seepage channels formed locally. This leads to a significant loss of injected water and, accordingly, lower oil displacement efficiency compared to the fault cavity-type. The study results can serve to support the production of 350×104 tonnes in the Fuman oilfield. Furthermore, they prompt the optimization of schemes for waterflooding and enhanced oil recovery (EOR), having a significant referential value for the efficient exploitation of similar oil reservoirs.

Advances in research on CO2 replacement for natural gas hydrate exploitation
Mingxing BAI, Zhichao ZHANG, Qiaozhen CHEN, Long XU, Siyu DU, Yexin LIU
2024, 45(2):  553-564.  doi:10.11743/ogg20240218
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The application of CO2 replacement method to develop natural gas hydrates (NGHs) is considered a highly promising technology for enhancing both CH4 recovery and CO2 sequestration. This study presents a review of the replacement mechanisms with CO2 and its mixed gas for NGH exploitation, as well as technological advances in the replacement with CO2 mixed with N2/H2 and geothermal-assisted CO2 replacement for enhancing CH4 recovery from NGHs. Key findings are as follows: (1) To replace NGHs with pure CO2 yields a low CH4 recovery. In contrast, injecting CO2 mixed with N2/H2 at varying ratios into NGH reservoirs proves effective in enhancing CH4 recovery. (2) Injecting CO2 mixed with N2 or H2 into NGH reservoirs can reduce the Van der Waals’ forces between CH4 molecules and NGHs’ molecular cages through the competitive adsorption among various gas molecules. Furthermore, it can decrease the partial pressure on the CO2 phase in the mixed gas, resulting in an upward shift in the phase equilibrium curve of NGHs. Such shift can inhibit the generation rate of CO2 hydrates during the replacement process and mitigate the adverse effects of hydrate encapsulation, thus enhancing CH4 recovery. (3) Injecting CO2 mixed with N2 for NGH exploitation can reduce the adverse effects of hydrate encapsulation. However, the newly formed N2 hydrates can block the pathways through which CO2 molecules enter the molecular cages of NGHs, thus leading to limited performance in enhancing CH4 recovery. (4) Unlike CO2 and N2, H2 does not form new hydrates under the conditions of hydrate reservoirs. Furthermore, competitive adsorption will occur between H2 and N2 when a minor amount of H2 is injected, further curbing the formation of N2 hydrates. Therefore, introducing H2 of low concentration to mixed CO2-N2 gas can further increase the displacement rate of CH4 in NGHs, thus boosting the CH4 recovery, establishing it as a crucial method to enhance the performance of CO2 replacement for NGH exploitation. (5) Cyclic injection of mixed gas can significantly enhance both the CH4 recovery from NGHs and the sequestration rate of CO2 hydrates. (6) Geothermal-assisted CO2 replacement for NGH exploitation can not only reduce the encapsulation effect of newly formed CO2 hydrates but also facilitate CO2 sequestration in geothermal and hydrate reservoirs, thereby markedly increasing subsurface CO2 sequestration rate while simultaneously enhancing CH4 recovery.

Advances in the application of comprehensive two-dimensional gas chromatography in petroleum geochemistry
Jiakai HOU, Zhiyao ZHANG, Shengbao SHI, Guangyou ZHU
2024, 45(2):  565-580.  doi:10.11743/ogg20240219
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Petroleum, a complex multi-component organic mixture, is susceptible to various physical, chemical, and biological transformations during its formation and migration. Consequently, it is difficult to identify compounds of extremely low concentrations or special compounds in petroleum using conventional one-dimensional gas chromatography (1DGC). In contrast, comprehensive two-dimensional gas chromatography (GC×GC), enjoying ultra-high resolution and sensitivity, high peak capacity, and accurate qualitative and quantitative detection results, allows for the separation and identification of complex mixtures, thus meeting the challenge of performing accurate, quantitative analyses of complex petroleum components. Key findings of this study include: (1) Coupled with various detectors such as a sulfur chemiluminescence detector (SCD), electron capture detector (ECD), flame ionization detector (FID), or a time-of-flight mass spectrometer (TOFMS), the GC×GC exhibits wide application and notable efficiency in analyzing and detecting the hydrocarbon compositions and heteroatomic compounds of crude oil fractions; (2) GC×GC can be employed to analyze unresolved complex mixtures (UCMs) in heavy oil, assess the cracking degree of crude oil, determine the preservation threshold of ultra-deep liquid hydrocarbon, quantitatively assess the intensity of thermochemical sulfate reduction (TSR), and identify potential trace molecular compounds in crude oil and their structures; (3) GC×GC, which has exhibited unique advantages in the field of petroleum geochemistry, is expected to play a significant role in shale oil and gas exploration and research on the migration, accumulation, preservation, and modification of liquid crude oil in deep to ultra-deep reservoirs.

Key technologies and development trends for intelligent construction of underground gas storage facilities
Lidong MI, Daqian ZENG, Hua LIU, Yandong GUO, Yanfeng LI, Zunzhao LI, Xudong SUN, Guangquan ZHANG, Chunhua LU, Peixian WANG
2024, 45(2):  581-592.  doi:10.11743/ogg20240220
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Remarkable achievements have been attained in the digital transformation and intelligent construction of China’s underground gas storage (UGS) facilities, shown as follows. (1) Key technologies, including the hydrocarbon reservoir-wellbore-pipeline network integrated coupling simulation and digital twins, have been developed for the intelligent construction of UGS facilities. (2) An intelligent cloud platform framework for UGS facilities has been established in the mode of data + platform + application. This platform fully utilizes new-type infrastructure like data center (DC), Internet of Things (IoT), and Industrial Internet of Things (IIoT), aiming to meet the demand for the management, research, production, and services of various business segments. (3) The intelligent construction of UGS facilities has led to the R&D of a UGS information management platform, UGS integrated management platform, decision support system using digital twin-based integrated simulation, and a digital platform covering the entire lifecycle of UGS facilities. The future intelligent construction of UGS facilities will focus on the development of new technologies, encompassing digital twin technologies for geological bodies, high-precision modeling, dynamic visual representations, intelligent operation, real-time intelligent risk warning, industrial software localization, and technologies based on the Beidou Navigation Satellite System (BDS) and satellite internet.

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