石油实验地质

2024, 46(5): 封二-封二.

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2024, 46(5): .

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Discussion on the uniformity of shale oil and gas in China

GUO Xusheng, SHEN Baojian, LI Zhiming, WAN Chengxiang, LI Chuxiong, LI Qianwen

2024, 46(5): 889-905. doi: 10.11781/sysydz202405889

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Shale oil and gas are important strategic resources in China's energy sector, existing in shale formations with self-generation and self-storage characteristics. In 2012, a significant breakthrough was achieved in Fuling, China, with the discovery of marine shale gas, which led to the formulation of the "two-factor enrichment" theory. This theory proposes that the development of high-quality mud shale in deep-water continental shelves is fundamental for hydrocarbon generation and controlled storage, while favorable preservation conditions are key to reservoir formation and controlled production. Recent efficient exploration and development practices in shale oil and gas have indicated that China's continental shale oil also exhibits "two-factor enrichment" characteristics. By analyzing the characteristics of typical shale oil and gas reservoirs in China, this study incorporates shale oil and gas into a unified system of hydrocarbon formation, storage, and accumulation, further deepening the theoretical connotation of the "two-factor enrichment" theory and forming a new understanding of the uniformity in shale oil and gas enrichment. Future research trends are also explored. Results show that: (1) Sedimentary environments dominated by semi-deep to deep-water continental shelves and semi-deep to deep lakes are the basis for hydrocarbon generation and controlled storage, controlling both the abundance and type of organic matter in shales as well as the distribution of high-quality reservoirs and favorable lithofacies combinations. (2) Stable tectonic conditions, effective top and bottom seals, and self-sealing properties of shale, in conjunction with overpressure, provide good preservation conditions that are crucial for reservoir formation and controlled production, providing key guarantees for the enrichment and high production of shale oil and gas. (3) The formation and enrichment of shale oil and gas are part of a unified dynamic evolutionary system, with thermal evolution as the main driver, following the sequential formation of shale oil, condensate oil, and shale gas. (4) Future study should focus on strengthening the integrated evaluation of conventional and non-conventional resources, deepening the understanding of distribution coefficients for conventional and non-conventional oil and gas, and considering the distribution patterns of oil and gas from a holistic perspective. The research results have important scientific and practical significance for deepening the theory of shale oil and gas enrichment and guiding their exploration and development.

Geological conditions and enrichment patterns of helium reservoir in Yancheng Formation, Huangqiao area, Subei Basin

YAO Hongsheng, CHEN Xingming, ZHOU Tao

2024, 46(5): 906-915. doi: 10.11781/sysydz202405906

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The helium (He) content in the natural gas of the Neogene Yancheng Formation in the Huangqiao area of Subei Basin ranges from 1.05% to 1.40%, which is generally higher than the industrial grade, indicating a crust and mantle composite type of helium resource. However, current research on the main controlling factors of helium enrichment and the evaluation of exploration targets from this source is relatively weak. Therefore, the study systematically analyzed the helium genesis, source, and trapping characteristics of typical helium-rich gas reservoirs in the Huangqiao area. It focused on the influence of mantle-derived faults on the transport and accumulation of helium-rich gas reservoirs and the trapping conditions within the Yancheng Formation. An enrichment model for helium-rich gas reservoirs in the Yancheng Formation of the Huangqiao area was proposed. The results show that: (1) The Nanxinjie deep fault in the Huangqiao area was active during the sedimentation of the Yancheng Formation, resulting in upwelling of mantle-derived materials, accompanied by volcanic activities and migration of CO₂, N₂, and helium along the fault to shallow layers. (2) The burial depth of the Yancheng Formation in the Huangqiao area ranges from 370 to 400 m. The thickness of the bottom sandstone of the Yancheng Formation is about 40 m, capped with 10 to 40 m of mudstone. The reservoir and cap combination is favorable for enrichment, and the helium-rich layers pinch out from east to west. (3) The Yancheng Formation in the Huangqiao area exhibits a monoclinal structure as a whole, with the bottom interface displaying angular unconformity with the underlying strata. Through seismic calibration and interpretation, the lithological and stratigraphic composite trap area of the helium-rich gas layer was outlined. The helium-rich gas reservoir of the Yancheng Formation in the Huangqiao area is characterized by fault-communicated mantle transport, sandstone reservoirs, mudstone cap layers, as well as lithological and stratigraphic composite traps for enrichment. This understanding is significant for the evaluation of favorable helium exploration targets in the Huangqiao area.

Characteristics of reservoir space and sweet spot evaluation of shale oil in the second member of Paleogene Funing Formation in Subei Basin: a case study of well QY1 in Qintong Sag

GAO Yuqiao, CAI Xiao, XIA Wei, WU Yanyan, CHEN Yunyan

2024, 46(5): 916-926. doi: 10.11781/sysydz202405916

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The second member of the Paleogene Funing Formation in the Subei Basin is a key production layer for conventional oil and an optimal target for the exploration and development of continental shale oil in East China. The analysis and testing of core samples from well QY1 in the Qintong Sag indicate that the shale features low total organic carbon (TOC) content, relatively low vitrinite reflectance (R_o), balanced mineral composition, and a complex pore network. Using petrological and geochemical methods, the lithofacies characteristics, reservoir space characteristics, oil-bearing and mobility characteristics, brittleness index, and compressibility characteristics of this shale oil reservoir were studied to identify production sweet spots. The second member of the Funing Formation is a mixed shale layered reservoir, with mineral composition mainly consisting of clay minerals, felsic minerals, and carbonate minerals. The average TOC value is 1.32%, and R_o ranges from 0.9% to 1.1%. The average porosity is 4% in the middle and lower parts and 2.2% in the upper part. Based on the abundance of organic matter, structural characteristics, and lithology, the shale of the second member of the Funing Formation can be divided into six lithofacies, with significant differences in reservoir properties. The development characteristics of the laminae are an important reason for the different reservoir space characteristics among different lithofacies. Except for low organic matter laminated/layered shale with poor calcite and dolomite, other lithofacies have good oil content. The high organic matter layered shale with rich calcite demonstrates the highest TOC content. The number of layers correlates well with oil and gas mobility, with the average OSI value decreasing from 202.62 mg/g in medium organic matter laminae shale with poor calcite and dolomite to 77.83 mg/g in high organic matter massive mudstone. High organic matter massive mudstone, due to the presence of a large amount of plastic minerals, has the worst fracturing effect among the six types of lithofacies. Medium organic matter laminae shale with poor calcite and dolomite is the optimal lithofacies, while medium organic matter layered shale with poor calcite and dolomite and medium organic matter layered shale with rich calcite and dolomite are slightly less favorable but can still be key targets for exploration and development. Based on the vertical distribution of the dominant lithofacies, sublayers ③ to ⑤ of submember Ⅰ and sublayers ② to ④ of submember Ⅱ of the second member of the Funing Formation are selected as geological sweet spots in this area.

Prediction of fine-grained sedimentary lithofacies distribution based on astronomical cycle isochronous lattice: a case study of Triassic Chang 7 member of Fuxian area, Ordos Basin

HE Faqi, ZHU Jianhui, QI Rong, WU Yingli, MIAO Jiujun, JIANG Longyan, WANG Dongyan, CHEN Xian

2024, 46(5): 927-940. doi: 10.11781/sysydz202405927

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Predicting the thickness distribution of different types of continental lithofacies is a fundamental task for selecting and evaluating continental shale oil-rich zones. Research on oil-bearing conditions, reservoir characteristics, and mobility of different types of lithofacies plays an important role in target area selection and the deployment of horizontal well sections. Based on core observation and logging identification, spectrum analysis of logging data was carried out. Stable astronomical orbital time cycles were introduced to perform spatio-temporal tuning. A high-frequency sequence isochronous lattice for drilling well comparison was established and the planar thickness variation trends of different types of lithofacies in each sequence cycle were quantitatively calculated, providing insights into lithofacies distribution patterns. Research on the 7th member (Chang 7) of Triassic Yan-chang Formation in the Fuxian area of the southern Ordos Basin showed that the natural gamma logging curves contained several sets of astronomical cycle information, among which 6 complete stable 405 kyr long eccentricity astronomical cycles could be identified. Based on the observation of the whole core section of Chang 7 member in well R203 and logging facies characteristics analysis, a reasonable high-frequency isochronous lattice was established for well-to-well comparison. The results showed that mud shale and laminated shale mainly developed in the bottom cyclic strata from Chang 7₃ to Chang 7₂ sub-member, and the fine-grained sandstone and siltstone were mostly developed in strata of cycles Ⅳ to Ⅴ from the middle and upper parts of Chang 7₂ to the bottom of Chang 7₁. Lateral comparison between wells showed that the mud shale and laminated shale lithofacies in the early cycles were widely distributed. During cycle Ⅰ period, these facies were mainly distributed in the southwest of the study area, and during cycle Ⅱ period, they were distributed in the west and east-northeast, with thicker storage in the central area. The fine-grained sandstone thickness distribution in strata of cycles Ⅳ to Ⅴ was controlled by a northeast-southwest sedimentary system, with a planar distribution from the north-northeast to the south-southwest, further extending to the southwest along wells ZF 27 to ZF 32. Three types of source and reservoir combinations were formed in Chang 7 member. The combination of laminated shale and fine-grained sandstone lithofacies occurred from the middle and upper parts of Chang 7₃ and Chang 7₂ sub-members to the lower part of Chang 7₁ sub-member, primarily distributed in the central-north, north, and northeast parts of the Fuxian area. The shale lithofacies thickness was well developed in Chang 7₃ sub-member, mainly distributed in the northeast, east, and southwest regions of the Fuxian area.

Characteristics and main controlling factors of Chang 7 shale oil in Triassic Yanchang Formation, Fuxian area, Ordos Basin

JIANG Longyan, QIAN Menhui, HE Faqi, QI Rong, YIN Chao, ZHANG Yi, ZHAN Xiaogang

2024, 46(5): 941-953. doi: 10.11781/sysydz202405941

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The shale in the 7th member (Chang 7) of Triassic Yanchang Formation on the southeastern margin of the Ordos Basin is characterized by shallow burial depth, light oil quality, large variability in oil well production capacity, and significant resource potential. Identifying the main controlling factors of reservoir enrichment is key to efficient exploration. Based on analysis results of cast thin sections, physical properties, and scanning electron microscope (SEM) tests of the Chang 7 shale member in the Fuxian area, combined with core, well logging, and seismic data, its layer characteristics are described and the main controlling factors are discussed. The results show that the Chang 7 shale in the research area extensively develops gray, dark gray, and gray black source rocks. The lithology is mainly mudstone and mud shale, with organic matter types mainly classified as type Ⅰ-Ⅱ₂. The vitrinite reflectance (R_o) values of source rocks range from 0.81% to 1.10%, indicating strong hydrocarbon generation potential. The sandstone reservoirs are mainly fine-grained feldspathic sandstone, with pore types primarily consisting of intragranular pores, residual intergranular pores, dissolution pores, and primary intergranular pores. Porosity ranges from 2.0% to 16.0%, and permeability ranges from 0.01×10^-3 to 1.20×10^-3 μm², indicating tight reservoirs. The oil-bearing properties of the reservoir are impacted by the physical properties of the sandstone interlayers and proximity to faults: coarser-grained reservoirs with better physical properties exhibit better oil and gas bearing potential. Reservoir properties are controlled by two factors, sedimentary microfacies and diagenesis. Subaqueous distributary channel microfacies have the best properties, followed by mouth bar microfacies. Strong early diagenetic chlorite cementation and weak calcite cementation contribute to the formation of sweet spots in the physical properties. The development and nature of faults play a crucial role in the Chang 7 shale oil enrichment. Statistical analysis shows that it is difficult to obtain industrial oil flow when the fault displacement exceeds 10 m and the wellbore is within 1 km of the fault. However, when the fault displacement is less than 7 m or when the wellbore is more than 1 km away from a large fault, industrial oil flow is more easily obtained.

Characteristics and occurrence states of shale biomarker compounds in Fengcheng Formation, Mahu Sag, Junggar Basin

ZHI Dongming, LENG Junying, XIE An, TANG Yong, HE Jinyi, HE Wenjun, LI Zhiming, ZOU Yang, ZHU Tao

2024, 46(5): 954-964. doi: 10.11781/sysydz202405954

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The characteristics of biomarker compounds and their occurrence states in different layers of the Permian Fengcheng Formation shale in Mahu Sag, Junggar Basin are poorly understood. By using experimental techniques such as rock pyrolysis, gas chromatography-mass spectrometry, fluorescence thin sections, and argon ion polishing electron microscopy, the material basis of hydrocarbon source rocks in different intervals, the distribution characteristics and significance of biomarker compounds, and different occurrence states of shale oil are clarified. This is of great significance for the next step in exploration and deployment in the Mahu Sag. The shale of the Fengcheng Formation in the Mahu Sag is mainly medium to good hydrocarbon source rocks, with type Ⅱ organic matter and in a mature evolutionary stage. The composition characteristics of biomarker compounds show high abundance of Pr and Ph, β-carotane, and C₂₉ rearranged steranes. The C₂₇-C₂₈-C₂₉ regular steranes exhibit an inverted "L" distribution, indicating that the organic matter is mainly contributed by lower aquatic organisms such as algae. Lower Pr/Ph ratios and higher gammacerane indices reflect a saline reducing sedimentary environment. Maturity parameters such as C₃₁αβ22S/(22S+22R), C₂₉M/C₂₉H, and C₂₉ββ/(ββ+αα) for hopanes and steranes indicate that the hydrocarbon source rocks are in the mature stage. In addition, the shale of the second member of the Fengcheng Formation has greater hydrocarbon generation potential and better source rock material basis than that in the first and third members. Meanwhile, biomarker compound parameters such as C₂₀/C₂₃TT, C₂₁/C₂₃TT, and Ga/C₃₀H indicate that the second member has more contributions from algae and other organisms, and a more reducing and saline environment. The hydrocarbons in the second member are mainly in a free occurrence state, residing in intergranular and intragranular pores. The study shows that the second member of the Fengcheng Formation is more favorable for shale oil enrichment and preservation, showing a better prospect for shale oil exploration and development.

Glutenite reservoir characteristics and development model of Permian Upper Wuerhe Formation in Fukang Sag, Junggar Basin

TANG Yong, YUAN Yunfeng, LI Hui, WANG Yafei, LÜ Zhengxiang, QING Yuanhua, LI Shubo, CHEN Hong, QIN Zhijun, WANG Qiuyu, XIE Zhiyi

2024, 46(5): 965-978. doi: 10.11781/sysydz202405965

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The glutenites in the Permian Upper Wuerhe Formation in the Fukang Sag of the Junggar Basin possess great potential for oil and gas exploration. However, uncertainties in the reservoir characteristics and formation mechanisms of these glutenites seriously restrict their effective exploration. The study provides a compre- hensive analysis on the characteristics, main controlling factors, and development models of glutenite reservoirs of the Upper Wuerhe Formation in the Fukang Sag of the Junggar Basin using microscopic thin sections, scanning electron microscopy (SEM), and X-ray diffraction (XRD). The results show that: (1) Two types of interstitial materials are observed in the glutenites of the Upper Wuerhe Formation, where the spaces between gravels are primarily interstitially filled with coarser sandy components, and the cementation mainly occurs between these sandy components. (2) The glutenites generally exhibit low porosity, with minimal pore development within gravels, while the pores in sandy interstitial materials are more developed. The reservoir space is mainly composed of intercrystalline and secondary dissolution pores. (3) Diagenetic processes related to reservoir formation mainly occur within the coarse sandy interstitial materials between gravels, mainly involving aluminosilicate dissolution, which results in abundant dissolution pores. (4) In high-energy sedimentary microfacies, such as estuary bars and underwater distributary channels, reservoirs are more favorably developed, where the reservoir space is mainly associated with feldspar dissolution. Fractures and unconformities are the main channels for acidic fluid migration. (5) During the eodiagenesis, acidic fluids, mainly atmospheric water, infiltrated along unconformities, with more significant dissolution near the Beisantai arch. During the middle diagenetic period, dissolution was mainly attributed to organic acid. (6) Three types of reservoirs are developed in the glutenites: atmospheric acid dissolution reservoirs, organic acid dissolution reservoirs, and dual-source acid superimposed dissolution reservoirs. The distribution of these reservoir types determines the exploration strategies for oil and gas reservoirs of glutenites of the Upper Wuerhe Formation in the Fukang Sag of the Junggar Basin. Glutenites in the slope and sag areas and zones of superimposed fault development are the key objectives for oil and gas exploration of glutenite reservoirs of the Upper Wuerhe Formation in Fukang Sag.

Characteristics and geological significance of escaping gas rich in natural hydrogen from pilot well BYP5 cores of lower sub-member of third member of Shahejie Formation in Zhanhua Sag, Bohai Bay Basin

LI Zhiming, LIU Huimin, LIU Peng, QIAN Menhui, CAO Tingting, DU Zhenjing, LI Zheng, BAO Youshu, JIANG Qigui, XU Ershe, SUN Zhongliang, LIU Yahui

2024, 46(5): 979-988. doi: 10.11781/sysydz202405979

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The pilot well BYP5 is a cored well drilled to explore the oil and gas bearing properties of the highly thermally evolved lower sub-member of the third member of the Paleogene Shahejie Formation in the Bonan deep sag of the Zhanhua Sag, Bohai Bay Basin. The coring interval depth ranges from 4 267.0 to 4 338.1 m. To reveal the oil and gas bearing properties of the cored interval, pyrolysis of frozen, sealed fragments was conducted on typical samples and the escaping gas from the core was collected and quantified for composition analysis. The results show that the cored interval is a high-quality hydrocarbon source rock rich in organic matter and carbonates, with a maturity (R_o) of about 1.2%_. Efficient hydrocarbon generation and expulsion likely occurred during thermal evolution, causing the current low free hydrocarbon (S₁) and hydrogen index (I_H) values. The content of the hydrocarbon gas from the core was generally low, ranging from 0.001 to 0.01 cm³/g, with an average of 0.005 cm³/g. Segments with relatively high levels of escaping hydrocarbon gas corresponded to those with relatively high pyrolysis S₁ values. The escaping gas was mainly composed of CH₄, CO₂, H₂, and C₂H₆, with mole percentages of H₂ ranging from 1.08% to 19.23%, with an average of 7.09%, indicating hydrogen-rich characteristics. H₂ showed a significant positive correlation with CO₂ and a negative correlation with CH₄. The escaping gas from the core was likely trapped in-situ, and the formation of H₂ might be related to the cleavage of hetero-bonds and demethylation during the pyrolysis of organic matter. Further research is suggested on the formation mechanism, geological exploration, and evaluation of natural hydrogen released during organic matter pyrolysis, so as to provide a basis for the decision-making in the exploration and development of this type of natural hydrogen resource.

Reassessment of exploration directions of continental shale oil in Lower Jurassic Da'anzhai Member in northern Sichuan Basin

XIONG Liang, DONG Xiaoxia, WANG Tong, WEI Limin, OUYANG Jiasui, WANG Baobao, FENG Shaoke

2024, 46(5): 989-1001. doi: 10.11781/sysydz202405989

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The Da'anzhai Member of the Lower Jurassic in northern Sichuan Basin is one of the major oil-bearing formations in the basin. In recent years, with the development of unconventional exploration theories, exploration efforts have shifted towards the shale reservoirs in the Da'anzhai Member, enhancing the understanding of the exploration directions for continental shale oil in northern Sichuan. Based on the data from shale oil exploration wells LY1 and YY2, including core samples, experiments, drilling, and fracturing data, a reassessment of the oil and gas formation conditions, resource potential, and engineering geological conditions was conducted. The results indicate that: (1) The second submember of the Da'anzhai Member in Langzhong has a good resource base and formation conditions, indicating great exploration potential. The second submember mainly develops three lithologies: shale, shell limestone, and shale interbedded with shell limestone. The shale exhibits good hydro- carbon source quality and is generally in a middle to high-mature stage. Its hydrocarbon production intensity is (20-90)×10⁴ t/km², and the retained hydrocarbon accounts for 66% to 78% of the total hydrocarbon production, with a shale oil resource amounting to 3.26×10⁸ t. (2) The shale samples from the second submember in the study area have poorly developed fracture networks, characterized by poor permeability conditions, difficult drilling and compressibility conditions. The matrix-type shale oil has high crude oil viscosity and high wax content. The coupling configuration relationship between the permeability of the shale samples and the fluidity of the shale oil is key to achieving high production in target layers. (3) Given the current poor production results in matrix-type shale exploration, it is recommended to adopt a combined conventional and unconventional exploration method to study the formation system of the shale and limestone interlayer reservoirs in the research area, considering high-quality shale and fracture-porosity type limestone as favorable exploration targets. Through the integration of geological and engineering research methods, efforts should be made to tackle technical challenges related to drillability, compressibility, and production, thereby improving engineering and technological levels.

Analysis and significance of shale reservoir differences between Wujiaping Formation in Hongxing area and Longmaxi Formation in Jiaoshiba area, eastern Sichuan Basin

MENG Zhiyong, BAO Hanyong, LI Kai, YI Yuhao, SHU Zhiheng, MENG Fulin

2024, 46(5): 1002-1014. doi: 10.11781/sysydz2024051002

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In the Hongxing area of the eastern Sichuan Basin, the Permian Wujiaping Formation developed a set of black, silicon-rich, and carbon-rich shale reservoirs, which are currently pivotal for enhancing shale gas reserves and production in the region. These shale reservoirs show strong similarities with the lower sections (layers ① to ③) of the gas-bearing shale in the Longmaxi Formation of the Jiaoshiba area in terms of sedimentary environment, shale quality, and gas content. Both formations are characterized by high carbon, silicon, and gas contents. However, in later stages of development, the shale gas reservoirs of the Wujiaping Formation were significantly less productive compared to those in the Longmaxi Formation in the Jiaoshiba area. To address this, the study analyzes the differences in reservoir quality and gas content between the two shale sets and their primary controlling factors. The results reveal that the shale reservoir in the Wujiaping Formation is characterized by a low silica mineral content and a high carbonate mineral content. Although it has a high organic carbon content, the kerogen types and organic matter are relatively poorer. The pore structure is marked by less developed organic matter pores and lamellar fractures, with smaller pore sizes. Overall, its reservoir physical properties and gas content are slightly inferior to those of the Longmaxi Formation shale in the Jiaoshiba area. Comparative analysis suggests that differences in sedimentary backgrounds and processes lead to primary quality differences in mineral and lithological composition, lamellation, and kerogen types between the two shale reservoirs. These differences form the material basis for variations in physical properties and gas content. Furthermore, differences in subsequent structural preservation conditions and other macro-geological factors lead to significant disparities between the two reservoirs in terms of pore types, sizes, porosity, and gas content. In addition, the study explores the impact of these distinctive characte-ristics on the development effectiveness of the two reservoirs and proposes corresponding engineering and technological strategies tailored to the differences in the development of these reservoirs.

Oil and gas exploration potential of continental shale of Lianggaoshan Formation of Middle Jurassic in Qijiang area of southeastern Sichuan

CHEN Chao, LIU Xiaojing, LIU Miaomiao, CHEN Huixia, XIE Jiatong

2024, 46(5): 1015-1027. doi: 10.11781/sysydz2024051015

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Advancements in evaluation and development technologies have established continental shale oil and gas as vital future alternative energy sources for China. Recently, exploratory wells drilled in the Lianggaoshan Formation shale segment of the Middle Jurassic in the Qijiang area, southeastern Sichuan, have shown promising oil and gas indications. To clarify the basic geological characteristics of shale oil and gas in this area, the organic-rich shale of the Lianggaoshan Formation in the southeastern Qijiang area was chosen as the subject of study. Based on core observations and laboratory analyses, an evaluation of the basic geological conditions for shale oil and gas in the second section of the Lianggaoshan Formation in the Qijiang area was conducted. This was combined with high-quality shale seismic prediction and structural preservation condition assessments to identify exploration potential and direct future exploration efforts. Using typical wells in the Qijiang area as case studies, resource potential analysis was performed by integrating organic geochemical characteristics, thermal maturity, reservoir physical properties, and oil and gas bearing characteristics. Results indicate that the high-quality shale in the lower subsection of the second member of the Lianggaoshan Formation spans an extensive area of 4 569 km², with thickness ranging from 20 to 39 m. Controlled by semi-deep lacustrine facies, this shale exhibits an average organic carbon content of 1.3% to 1.6%, with organic matter types predominantly Ⅱ₁ to Ⅱ₂, and vitrinite reflectance values between 1.00% and 1.29%. These characteristics suggest significant hydrocarbon generation potential and promising measured oil and gas content. The high-quality shale is characterized by high gamma-ray (GR) readings, high acoustic time difference, and low density. Seismic waveform classification and acoustic impedance inversion techniques identified the Dingshan, Dongxi, and Guanshengchang areas as regions of concentrated shale thickness. These areas feature large, broad, and gentle synclines with favorable drilling results, indicating good overall preservation conditions. The main burial depths ranges from 1 000 to 3 500 m, with uniform structural stress and good compressibility. In summary, the analysis indicates that the continental shale in the Lianggaoshan Formation of the Qijiang area possesses favorable preservation conditions and substantial shale oil resources exceeding 500×10⁶ t, offering significant exploration potential. This evaluation provides a strategic framework for expanding exploration efforts in continental shale oil and gas within the Sichuan Basin.

Characteristics and main controlling factors of the marlstone reservoirs of the first member of Permian Maokou Formatin in Weiyuan area, southern Sichuan Basin

LI Rong, SONG Xiaobo, SU Chengpeng, LI Suhua, ZHAO Qianrong, ZHU Lan, LIN Hui

2024, 46(5): 1028-1038. doi: 10.11781/sysydz2024051028

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The exploration of the first member of Permian Maokou Formation (Maokou 1) in the Weiyuan area of southern Sichuan Basin has been limited. Previous analyses of cast thin sections and argon ion electron microscopy based on earlier drilling data suggested that talc pores were the primary reservoir spaces, with talc formation significantly contributing to the reservoir. However, the latest drilling data shows substantial differences in the types of reservoir spaces and the genesis of the Maokou 1 marlstone reservoirs compared to earlier understanding. It is necessary to further clarify the main controlling factors for the development of these reservoirs in the Maokou 1 member. Through core observation, thin section identification, physical property analysis, nitrogen adsorption, argon ion polishing scanning electron microscopy, and quantitative pore characterization, the primary reservoir spaces and types of the Maokou 1 marlstone were analyzed from both qualitative and quantitative perspectives. The main controlling factors for the development of these reservoirs were identified by combining total organic carbon (TOC) content determination, rare earth element analysis, and whole rock X-ray diffraction. High-quality reservoirs in the Maokou 1 member of the Weiyuan area are developed in marlstone, characterized by low porosity and permeability fractures and pore-type reservoirs, predominantly Type Ⅲ with some Type Ⅱ reservoirs. The main reservoir spaces include corroded pores, organic matter pores, and talc pores and fractures, with pore development closely related to TOC content. Talc formation, dolomitization, and silicification did not significantly contribute to secondary reservoir spaces, and their contribution to porosity is minimal. The development of marlstone reservoirs is jointly controlled by early dissolution, sedimentary facies, and organic matter abundance. Early dissolution is the key to the formation of corroded pores and fractures, while high primary productivity and high organic matter settling rate of the inner gentle slope shallow water environment provided the material basis for the formation of organic matter pores. This understanding provides theoretical support for the exploration of similar oil and gas reservoirs in the basin.

Occurrence characteristics and genesis mechanism of pyrobitumen in Sinian Dengying to Cambrian Longwangmiao reservoirs in central Sichuan Basin

NIU Siqi, LIU Guangdi, WANG Yunlong, SONG Zezhang, ZHU Lianqiang, ZHAO Wenzhi, TIAN Xingwang, YANG Dailin, LI Yishu

2024, 46(5): 1039-1049. doi: 10.11781/sysydz2024051039

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Reservoirs in the Sinian Dengying (DY) to Lower Cambrian Longwangmiao (LWM) formations in the central Sichuan Basin exhibit evident hydrothermal activities with pyrobitumen showing signs of alterations caused by hydrothermal fluids. However, few studies have explored the relationship between hydrothermal fluid activity and the evolution of natural gas accumulation, resulting in a significant lack of understanding of oil and gas accumulation history in the DY Formation. The impact of hydrothermal fluids on oil and gas accumulation in the DY Formation is substantial, and a correct understanding of the natural gas accumulation process and the identification of favorable exploration areas in the DY Formation require further research into hydrothermal cracking gas accumulation. By examining the filling features, optical textures, and structural characteristics of pyrobitumen and conducting geochemical studies on fluid inclusions trapped by hydrothermal minerals, this study explored the genesis of pyrobitumen in the DY to LWM formations. The relationship between hydrothermal fluid activity and oil cracking was also analyzed. The the pyrobitumen in the DY to LWM formations in the central Sichuan Basin were formed during hydrothermal fluid activity, exhibiting the same optical anisotropy characteristics as the mesophase pyrobitumen. Pyrobitumen can be divided into four types: fine-grained mosaic, medium-grained mosaic, coarse-grained mosaic, and streamline types. Its formation temperature exceeded 300 ℃, far surpassing the maximum burial temperature of the strata, indicating its hydrothermal fluid-driven genesis. The hydrothermal fluid activity occurred during the Late Permian and was related to the Emeishan mantle plume. The temperature of the hydrothermal fluids exceeded 300 ℃, leading to crude oil cracking in reservoirs of the DY to LWM formations. This study found that hydrothermal fluid activity advanced the cracking time of crude oil in the paleo reservoirs of the DY to LWM formations to the Late Permian, disrupting the existing accumulation model and helping us re-understand the evolution process of gas reservoirs and identify favorable accumulation areas.

Main controlling factors and exploration direction of gas reservoir in Jialingjiang Formation, Sichuan Basin

LI Longlong, TAO Guoliang, DU Chongjiao, PENG Jinning, LUO Kaiping, CHEN Yongfeng, ZUO Zongxin, JIANG Xiaoqiong, WANG Yuanzheng, LU Yongde

2024, 46(5): 1050-1062. doi: 10.11781/sysydz2024051050

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Abstract:
The Jialingjiang Formation is a traditional stratum for natural gas exploration in the Sichuan Basin, and in recent years it has been continuously discovered in northern and southwestern Sichuan, but there are still large areas of exploration blanks in the basin, which urgently needs to deepen the understanding of the natural gas accumulation law of this formation, clarify the main controlling factors of the accumulation, and then point out the exploration direction in the future. By using natural gas geochemistry and other analytical tests, combined with structural restoration, basin simulation and other technologies, based on gas source analysis, with typical gas reservoir anatomy as the core, combined with the understanding of the reservoir conditions of the Jialingjiang Formation, the main controlling factors of reservoir formation were discussed through the analysis of reservoir formation process, and the reservoir formation model was established. The results show that the natural gas of the Jialingjiang Formation is mainly cracked gas from crude oil in the lower part. The Jialingjiang Formation has good reservoir formation conditions such as multiple sets of high-quality source rocks supplying hydrocarbons, developing multiple types of carbonate reservoirs, and source-connected faults that effectively communicate gas sources. The paleostructures of the main oil generation period, the structures of the adjustment period, the source-connected faults, and the favorable reservoir types are the main controlling factors of the natural gas accumulation in the Jialingjiang Formation in the Sichuan Basin. The Jialingjiang Formation has an accumulation model of "multi-source charging to form ancient oil reservoirs, ancient oil reservoir cracking and supply gas, source-connected faults transport, and late adjustment accumulation". Based on this, it is proposed that the structural and litholo-gical composite gas reservoirs distributed in the piedmont belts of western and northern Sichuan, which are at relatively high positions during the main oil generation period and gas reservoir adjustment and accumulation period, have developed source-connecting faults, and have good preservation conditions, are the preferred exploration directions. The porous lithological gas reservoirs distributed in the structurally stable areas and syncline areas of the high and steep structural belts in eastern Sichuan are the main exploration directions in the future.

Sedimentary environment and oil-bearing characteristics of shale in Cretaceous Qingshankou Formation in Songliao Basin

BAI Xin, CHEN Ruiqian, SHANG Fei, ZHANG Nan

2024, 46(5): 1063-1074. doi: 10.11781/sysydz2024051063

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Abstract:
The Upper Cretaceous Qingshankou Formation in the Songliao Basin contains thick, widespread, and organic matter-rich shale layers, offering abundant shale oil resources. Studying the sedimentary environment during shale formation and exploring the oil-bearing characteristics of shale oil enrichment intervals provide a theoretical basis for the prediction of the intervals and sweet spots. Based on previous research, the study compared organic carbon content, pyrolysis data, types of organic macerals, and major and trace elements of samples from two typical wells of different sags, well GY8HC in the Gulong Sag and well ZY1 in the Sanzhao Sag, in the central depression zone of the Songliao Basin. The analysis delved into the differences in oil-bearing characteristics and sedimentary environment of the Qingshankou Formation shales in two different sags, further analyzing the factors influencing these differences. The oil-bearing indicators of shales from the two wells in the Qingshankou Formation of the Songliao Basin showed that the total organic carbon (TOC) content in well ZY1 was significantly higher than that in well GY8HC. However, the free hydrocarbon content (S₁) and oil saturation index (OSI) in well ZY1 were lower than those in well GY8HC. The geochemical environment during shale formation controlled organic matter enrichment. Comparing major and trace elements in samples from both wells, it was found that the climate in well ZY1 was more humid during its sedimentary period, the water body had stronger reducing conditions, and its paleoproductivity and paleo-water depth were significantly higher than those in well GY8HC. These conditions were favorable for the preservation of organic matter, thereby forming a higher organic matter abundance in the shale of well ZY1. In addition, it was found that the organic matter type in well GY8HC is mainly Type Ⅰ, sapropelic kerogen, at a mature to highly mature stage, whereas well ZY1 contains mainly Type Ⅱ₁ kerogen, with less Type Ⅰ, at a low to mature stage. Therefore, the shale in well GY8HC possesses better oil generation potential.

Preservation mechanism of pores in middle and deep sandstone reservoirs of Cretaceous Bashijiqike Formation in Yingmaili area, Kuqa Depression, Tarim Basin

ZHANG Liang, ZHU Yixiu, ZHOU Lu, QIN Kaixuan, JIANG Jun, XIONG Rongkun, LI Zezhou

2024, 46(5): 1075-1087. doi: 10.11781/sysydz2024051075

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Abstract:
The sandstone reservoirs of the Cretaceous Bashijiqike Formation in the Yingmaili area on the southern slope of the Kuqa Depression within the Tarim Basin demonstrate favorable physical properties and considerable potential for oil and gas exploration. However, they are characterized by strong heterogeneity and unclear patterns of oil and gas distribution. In this study, the lithology and physical properties of the middle and deep reservoirs of the Bashijiqike Formation in the Yingmaili area were analyzed using core observation, a series of thin section analyses(standard, casting, cathodoluminescence, and inclusion thin sections), scanning electron microscopy(SEM), physical property testing, X-ray diffraction, and diagenesis reconstruction and physical property recovery techniques. It aims to explore the pore characteristics and preservation mechanisms, classify reservoir types, and clarify the distribution patterns and controlling factors of favorable reservoirs.The results show that the sandstone is mainly composed of feldspathic lithic sandstone and lithic feldspathic sandstone with low matrix content and medium maturity in both composition and structure. The primary pore type of the reservoir is residual primary pores, followed by secondary pores, including intergranular and intragranular dissolution pores, classifying the reservoir as a medium-to-high porosity and permeability type. The preservation of the primary pores in the middle and deep sandstones of the Bashijiqike Formation was mainly attributed to the depositional environment and subsequent diagenetic and reservoir evolution. The sandstone was initially formed in the microfacies of distributary channels at the front edge of a braided river delta with high hydrodynamics. The constantly overlapping channels formed thick and stable composite sand bodies. The strong hydrodynamics in the area led to high concentration and good sorting of sandstone clastic particles, providing the material basis for the formation of primary pores. The burial evolution process involved early long-term shallow burial and late-stage rapid deep burial, resulting in weak compaction transformation of the sandstone. Meanwhile, late-stage deep overpressure greatly enhanced the sand body's resistance to compaction, allowing for the preservation of residual primary pores. The continuously decreasing paleogeothermal gradient in the depression further contributed to the effective preservation of residual primary pores.

Pressure prediction and genesis analysis of Huangliu Formation reservoir in DF block of Yinggehai Basin based on neural networks

NING Weike, JU Wei, XIANG Ru

2024, 46(5): 1088-1097. doi: 10.11781/sysydz2024051088

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Abstract:
In the process of oil and gas exploration, development and production, reservoir pressure plays a crucial role in the accumulation, distribution and migration of oil and gas. Abnormally high-pressure reservoirs can lead to drilling accidents such as wellbore collapse, kicks and blowouts. Traditional methods for predicting reservoir pressure, mainly based on well logging calculations using empirical formula and effective stress methods, suffer from drawbacks including complex parameter identification and significant subjectivity. Consequently, the paper uses the DF block in the Yinggehai Basin as a case study, building a reservoir pressure prediction model based on real-time pressure data using both the BP neural network and convolutional neural network. This process established an implicit direct relationship between logging curves and real-time reservoir pressure, allowing for the prediction of reservoir pressure and an analysis of the causes of overpressure. The results of the study indicate that: (1) The established convolutional neural network model demonstrates high accuracy in predicting reservoir pressure, with a root mean square error of 0.27 MPa for the optimal model. (2) The predicted reservoir pressure range for the Huangliu Formation in the DF block of the Yinggehai Basin is 53.26-55.60 MPa, with an average pressure coefficient of 1.66-1.95, consistent with overpressure. (3) The mechanism behind the overpressure in the Huangliu Formation, DF block, is mainly due to fluid expansion, supplemented by undercompaction.

Preparation of molecularly imprinted polymer microspheres and their adsorption performance for 5α-cholestane

YUAN Longmiao, MA Rong, CHEN Jianzhen, SHAO Yuanyuan, WU Yingqin

2024, 46(5): 1098-1109. doi: 10.11781/sysydz2024051098

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Abstract:
Steroidal molecularly imprinted polymers (MIPs) and non-imprinted polymer (NIP) were prepared by precipitation polymerization method using cholesterol, deoxycholic acid, and β-sitosterol as the virtual templates, acrylic acid (AA) as the functional monomer, azobisisobutyronitrile (AIBN) as the initiator, and ethylene glycol dimethacrylate (EGDMA) as the cross-linking agent. The morphology and structure of the polymers were characterized using scanning electron microscopy (SEM), X-ray spectroscopy (XRD), Fourier-transform infrared spectroscopy (FT-IR), and Brunauer-Emmett-Teller (BET) specific surface area analysis. The adsorption performance for steroidal substances was also investigated. The results showed that the steroidal MIPs were uniformly-sized and well-dispersed spherical nanoparticles with porous surface. Adsorption performance results showed that MIPs had significantly stronger adsorption capacities for 5α-cholestane compared to NIP. Among the three MIPs, deoxycholic acid and β-sitosterol MIPs demonstrated stronger adsorption capacities for 5α-cholestane than that of cholesterol. The adsorption kinetics studies showed that the adsorption process of MIPs for 5α-cholestane was in accordance with the pseudo-second-order kinetic model, which was mainly controlled by chemisorption. The isothermal adsorption of both MIPs and NIP conformed to the Langmuir isothermal adsorption model and the Scatchard model, indicating that MIPs exhibited specific selective adsorption for 5α-cholestane and that the adsorption process was monolayer adsorption, with a maximum adsorption capacity of 0.735 mg/g. The study suggests that MIPs prepared with cholesterol, deoxycholic acid, and β-sitosterol as virtual templates have high molecular recognition and selectivity for 5α-cholestane.

Application of visual 3D physical simulation experiment technology in oil and gas accumulation research: a case study of well S53-2 in Shunbei area of Tarim Basin

LONG Hui, ZENG Jianhui, LIU Yazhou, YANG Jining, GENG Feng

2024, 46(5): 1110-1122. doi: 10.11781/sysydz2024051110

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Abstract:
The physical simulation experiment technology for oil and gas reservoir formation is an important technical means to study the process of oil and gas migration and accumulation. Under laboratory conditions, dynamic, visual, and quantitative research on oil and gas migration and reservoir formation can be achieved. However, traditional two-dimensional physics simulation experimental techniques have shortcomings such as a lack of subtle phenomena, difficulty in measuring oil content, and a single observation surface. To address these issues, and to reveal the characteristics of ultra-deep oil and gas accumulation, a visual 3D physical simulation experiment technology of oil and gas accumulation was developed, and the accumulation process of well S53-2 in Shunbei area of Tarim Basin was successfully simulated. The influencing factors of oil and gas accumulation in ultra-deep fault controlled oil and gas reservoirs have been clarified, revealing that faults and fracture network systems play a dual role in the formation process of fault controlled oil and gas reservoirs, serving as both oil and gas migration channels and important oil and gas storage spaces. It has been proposed that the main fault, fracture network, and the graben fault on one side of the fracture network are advantageous areas for oil and gas accumulation, and a "buoyancy vertical migration, first fault core and then damage zone, first main trunk and then graben, fracture network integrated transportation and storage, and different main and secondary faults" oil and gas accumulation model has been established. The new technology makes the experimental process clearer, the experimental parameters more accurate, and the experimental phenomena more three-dimensional, providing new support for laboratory oil and gas reservoir simulation work.

Machine learning-based prediction of low oil saturation sandstone reservoir parameters: a case study of Lower Karamay Formation in Xia 77 well block of Xiazijie Oilfield, Junggar Basin

LIU Jun, ZHONG Jie, NI Zhen, WANG Qingguo, FENG Renwei, JIA Jiang, LIANG Yueli

2024, 46(5): 1123-1134. doi: 10.11781/sysydz2024051123

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Abstract:
The Lower Karamay Formation in the Xia 77 well block of the Xiazijie Oilfield in the Junggar Basin features a complex oil and water relationship in its ultra-low porosity and ultra-low permeability reservoirs. These reservoirs are characterized by low production, high water content, low oil saturation, poor correlation between porosity and permeability, unclear relationship between reservoir parameters and logging responses and difficult identification of oil and water layers. Conventional methods for evaluating and predicting reservoir parameters are poorly suited for this block. Through the analysis of lithology, physical properties and oil-bearing characteristics, it was determined that the reservoir lithology of the Lower Karamay Formation is dominated by glutenite and gravelly sandstones, with mixed-layers of illite and smectite as the dominant clay mineral. The reservoirs are characterized by low porosity and ultra-low permeability with primary intergranular and residual intergranular pores as the main storage space. By establishing an oil saturation interpretation model, it was confirmed that the reservoirs in this area are low oil saturation reservoirs, with oil saturation generally ranging between 36%-55%. The physical properties and oil content of glutenite reservoirs are superior to those of medium to fine sandstones, with reservoir physical properties controlling oil content and exhibiting low saturation characteristics. Electrical properties are influenced by both oil content and lithology. Through studying the formation mechanism of low oil saturation oil reservoirs, it was found that the microscopic pore structure of the reservoirs is the main cause of low oil saturation. By selecting sensitive parameters and utilizing data from natural gamma, resistivity, and acoustic time difference logging, BP neural network technology based on machine learning was introduced to calculate and predict porosity, permeability, and water saturation for the Lower Karamay Formation in Xia 77 well block. The prediction accuracy of reservoir parameters exceeded 80%. The conclusions and methods derived from this study can provide a basis and reference for the prediction of physical parameters in low oil saturation tight sandstone reservoirs.

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