石油实验地质

2024, 46(3): .

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Main controlling factors of shale oil enrichment in second member of Paleogene Funing Formation in Gaoyou Sag of Subei Basin

DUAN Hongliang, SUN Yaxiong, YANG Baoliang

2024, 46(3): 441-450. doi: 10.11781/sysydz202403441

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The second member of the Paleogene Funing Formation in the Gaoyou Sag is a key area for shale oil exploration within the Subei Basin. The successful implementation of eight horizontal shale oil wells evidences its significant potential and promising prospects of exploration. Addressing challenges such as variations in well productivity and unclear understanding of the main controlling factors of shale oil enrichment, this study utilized core data, logging data, analysis testing data, and production dynamics to investigate the geological characteristics and main controlling factors of shale oil enrichment in the second member of the Funing Formation. The results reveal that the mudstone and shale in this member predominantly consist of felsic-argillaceous mixed rocks and felsic-calcilutite/dolomitic mixed rocks, with moderate organic matter abundance and mainly TypeⅠand TypeⅡ₁ organic matter. From bottom to top, the organic matter type gradually transitions from humus to sapropelic, with an overall increase in organic matter abundance, providing favorable conditions for shale oil formation. A comprehensive evaluation of lithofacies, oil generation potential, oil content, reservoir characteristics, and compressibility identified three favorable exploration layers in the second member of the Funing Formation: Ⅴ-4 to Ⅴ-9, Ⅳ-2 to Ⅳ-7, and Ⅱ to Ⅲ.Shale oil enrichment in the second member of the Funing Formation is characterized by the following factors: (1) Favorable lithofacies combinations, particularly mixed rocks interbedded with dolomite bands, form the material basis for shale oil enrichment, resulting in high shale oil productivity. (2) A complex pore and fracture system is central to shale oil enrichment, with laminar fractures and cracksserving as the main pathways for shale oil flow, effectively connecting matrix pores and enhancing shale oil conductivity. (3) Higher maturity and favorable preservation conditions are crucial for high and stable shale oil production, with vitrinite reflectance (R_o) between 0.8% and 0.9%, indicating relatively higher retained oil content. Wells located away from long-term active faults exhibit relatively higher free hydrocarbon (S₁) content.

Application of geothermal gradient in the study of thermal evolution of Paleozoic source rocks, Tarim Basin

DING Yong, PAN Quanyong

2024, 46(3): 451-459. doi: 10.11781/sysydz202403451

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Considerable debate has arisen regarding studies of the thermal history of Paleozoic source rocks in the Tarim Basin, particularly regarding the thermal evolution of ultra-deep, ancient source rocks. The evaluation method for the thermal evolution stages has long been a key issue in the study of source rocks' thermal history. Research findings revealed that the Cambrian paleo-geothermal gradient in the Tarim Basin varies between 2.95 and 3.6 ℃/hm. Based on the hydrocarbon generation threshold temperature of 65 ℃, the required overlying strata thickness ranges from 2 203 to 1 806 m, with a difference of 397 m, equivalent to 2.58 ℃, showing a relatively small temperature difference. Thus, it is considered that the variation in the Cambrian paleo-geothermal gradient in the Tarim Basin is minimal, allowing the differences in geothermal gradient values for each period to be ignored, and that thickness may be the main determinant of temperature. The sedimentation and residual thickness of the strata can be accurately obtained, with the error mainly depending on the restoration of the denudation thickness. The thermal evolution stages of the Cambrian Yurtus Formation source rocks in the Tarim Basin were evaluated using reliably obtained parameters such as strata thickness, paleo-geothermal gradient, denudation thickness, and hydrocarbon generation charts of source rocks. With this assessment, the effective source rocks and their distribution in the key period of the Manjiaer Depression were delineated. Moreover, the effective source rocks ofthe Yurtus Formation, their large-scale hydrocarbon generation capacity, and the favorable areas for late-stage hydrocarbon accumulation were predicted and classified. The effective source rocks at different stages and their large-scale hydrocarbon generation potential are crucial for hydrocarbon accumulation in each period. This method avoids the issue of unreliable temperature scales in maturity identification, providing an important scientific basis for deep and ultra-deep oil exploration and development in the Tarim Basin and for selecting favorable areas for late-stage hydrocarbon accumulation.

Sedimentary evolution and petroleum geological significance of Permian Maokou Formation in eastern and northern Sichuan Basin

CAO Hua, SHAN Shujiao, TIAN Chen, ZHANG Xihua, PENG Hanlin, LIU Peiyun, CHEN Cong, GAO Zhaolong, HU Luojia, XIE Jingping, LI Tianjun, HU Guang

2024, 46(3): 460-471. doi: 10.11781/sysydz202403460

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In recent years, the Permian Maokou Formation of the Sichuan Basin shifted focus. Previously, targeting high points and exploring along the long axis were common. Now, the strategy emphasizes finding shoal grainstone reservoirs with pores, leading to significant breakthroughs and making the Maokou Formation a hotspot for exploration. This change requires strong support from sedimentary evolution studies. The eastern and northern Sichuan regions are notable for distinct tectonic and sedimentary features within the Maokou Formation, suggesting promising exploration potential. Analysis of the logging data from 386 wells was conducted and sedimentary facies analysis was carried out using field profiles and drilling cores. Combining the logging curves with sedimentary facies, the sedimentary evolution of the Maokou Formation in the study area was analyzed. Findings reveal a gentle carbonate slope from the first member to the lower submember of the second member. The stratigraphic thickness and sedimentary facies are generally influenced by the ancient Central Sichuan Palaeouplift, with low-energy shoals developing locally. A transition to a rimmed carbonate platform occurs from the upper submember of the second member to the third member, with stratigraphic thickness and sedimentary facies showing a northwest to southeast orientation. The platform develops sequentially from platform facies to platform margin, slope, and shelf facies from west to east, with high-energy shoals developing in the platform margin. Sedimentation history indicates two distinct rise to fall processes of the relative sea level during the Maokou Formation sedimentary period, corresponding to the first member to the lower submember of the second member, and the upper submember of the second member to the third member. The formation of shoal grainstone reservoirs with karst and dolomitization in the gentle slope during the first period was controlled by regional sea level changes, tectonic activities, and the type of carbonate platform. Potential hydrocarbon source rocks developed in submarine troughs during the second period. The region holds promise for unconventional oil and gas exploration, particularly on the west side of the trough with high-energy shoals on platform margins.

Characteristics and formation stages of natural fractures in Lower Silurian Longmaxi Formation in Tiangongtang area of Sichuan Basin

LI Linhao, FAN Cunhui, ZHAO Shengxian, LIU Shaojun, XU Fei, NIE Shan, YU Yawei

2024, 46(3): 472-482. doi: 10.11781/sysydz202403472

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The Lower Silurian Longmaxi Formation on the southwestern margin of the Sichuan Basin holds significant shale gas reserves. The characteristics and formation stages of fractures play a crucial role in shale gas accumulation and productivity. Focusing on the Longmaxi Formation in the Tiangongtang area, this study employed core analysis, FMI (Formation Micro-Imager) logging, rock acoustic emission experiments, carbon-oxygen isotope analysis of fracture fillings, fluid inclusion homogenization temperature testing, and burial-thermal evolution history analysis to investigate the development characteristics and formation periods of natural fractures in the shale. The results indicate that the natural fractures in the Longmaxi Formation in the study area are characterized by the coexistence of tectonic vertical and low-angle fractures. The core fractures exhibit high development density, short extension, and high filling degree. Comparison of imaging log fracture dip angles, core fracture cross-cutting relationships, fracture filling fluid inclusion tests, and rock acoustic emission experiments suggested that the fractures in the Longmaxi Formation in the Tiangongtang area were associated with three tectonic events. Combined with burial-thermal evolution history analysis, the formation periods were confirmed as follows: the first stage involved NW-oriented and NNE-oriented planar shear fractures, and NEE-oriented cross-sectional shear fractures formed during the mid-late Yanshanian period (130-62 Ma) with tectonic stress orientation near SN (345°±5°) and inclusion homogenization temperatures of 185-206 ℃; the second stage involved NE-oriented and NW-oriented planar shear fractures, and NNW-trending cross-sectional shear fractures formed during the late Yanshanian to mid-Himalayan period (62-34 Ma) with tectonic stress orientation near EW (80°±5°) and inclusion homogenization temperatures of 165-184 ℃; the third stage involved near SN-oriented and NEE-oriented planar shear fractures, and NE-oriented cross-sectional shear fractures formed from the mid-Himalayan period to present (34 Ma to present) with tectonic stress orientation near NW (315°±5°) and inclusion homogenization temperatures of 125-162 ℃. Based on the geomechanical background, a three-stage tectonic fracture evolution model for the Longmaxi Formation in the Tiangongtang area was established.

Characteristics and genesis of fillings in fracture-cavity space in first member of Permian Maokou Formation, Sichuan Basin: a case study of well A1

MENG Xianwu, YOU Donghua, LI Rong, SONG Xiaobo, ZHANG Liyu, ZHU Lan

2024, 46(3): 483-490. doi: 10.11781/sysydz202403483

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In recent years, natural gas discoveries have been continuously made in the first member of the Permian Maokou Formation in the Sichuan Basin, bringing attention to the genesis mechanism of marlstone reservoir space. Centimeter-scale fracture-cavity type reservoir space is one of the newly discovered types in the first member of the Maokou Formation, and relevant research has not been publicly reported. Taking well A1 in the Sichuan Basin as an example, based on core observation and description, the characteristics and genesis of fracture-cavity fillings were studied through comparative analysis of microscopic petrology, carbon-oxygen isotopes, strontium isotopes, and trace elements. The similar distribution characteristics of carbon-oxygen isotopes and strontium isotopes between calcite cement and mudstone matrix in the fractures of the first member of the Maokou Formation indicated that calcite mainly came from the dissolution and redeposition of surrounding rocks. Compared with marlstone, the fracture calcite cement showed lower contents of valence elements (V, Cr, U, Mo) and rare earth elements (REE), while the content of micronutrient elements (Ni, Cu, Zn) increased, revealing the differential migration pattern of trace elements in this process. The differential variation characteristics of Mn and Sr contents between calcite and marl matrix revealed the marine affinity of diagenetic fluids, further indicating their independence from atmospheric freshwater and deep hydrothermal fluids. Since the Late Jurassic, lateral tectonic thrusting pressure has formed detachment faults and related fold systems in southeastern Sichuan, which potentially caused deformation of the Maokou Formation marlstone and the generation of centimeter-scale fracture spaces. Diagenetic fluids formed during subsequent compaction-dissolution processes (including lateral dissolution) provided material sources for quartz and calcite cement in the fractures.

Development characteristics and oil-gas geological significance of slope break zone of Xujiahe Formation in Sichuan Basin

CHEN Youzhi, ZANG Dianguang, YANG Xiao, WU Furong, LIANG Hong, WANG Xiaoyang, WU Yulin, GUO Ran, XU Min, CHEN Ying, ZHANG Shuai, WANG Peng, YING Qian, ZHAO Zhenwei, CHEN Na

2024, 46(3): 491-498. doi: 10.11781/sysydz202403491

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Previous studies have delved into slope break zones in faulted basins, yet foreland basins, with their gentle slopes toward the forebulge, underdeveloped large-scale structures, and small terrain undulations, have received limited research on slope-fault belts. During the deposition periods of the 4th and 5th members of the Late Triassic Xujiahe Formation, a foreland basin developed in the Sichuan Basin. Scholars have noted the control exerted by the gentle slope break zone on the sedimentary lithofacies in the central and western Sichuan, particularly in the west of the Luzhou-Kaijiang Paleo-uplift, but related studies remain limited. By interpreting the tectonic slope break zones in seismic reflection profiles of the Sichuan Basin and incorporating existing regional geological data, this study employed particle flow numerical simulation to clarify the types of slope break zones in the central and western Sichuan regions, as well as their relationship with gravity sliding structures. It also analyzed the characte-ristics of new types of oil and gas traps associated with gravity-sliding structures. The findings are as follows: (1) The study area developed a fault slope break zone, with each side bounded by a "front squeezing and rear extension" tectonic combinations formed by gravity sliding. The tectonic deformation is weaker than those of gravity-sliding structures at passive continental margins. (2) The edge fault of the tectonic slope break zone controls the sedimentary facies and sand body types. (3) In the gentle slope zone, the stretching area of gravity-sliding structures lead to the uplift of the footwalls of normal faults, forming syndepositional anticlines with developed sandstones. These sandstones, juxtaposed with organic-rich mudstones within the contemporaneous fault depression, form "side-generated and lateral storage" hydrocarbon reservoirs. (4) In the steep slope zone, gravity sliding forms syndepositional anticlines in the 5th member of the Xujiahe Formation, which are bounded by flank mudstones and post-sliding deposited mudstones, forming in-source sand body reservoirs. (5) Syndepositional anticline hydrocarbon reservoirs related to gravity-sliding structures represent a new type of in-source hydrocarbon accumulation. The 5th member of the Xujiahe Formation in the study area likely contains such reservoirs, distributed in a NE-trending pattern parallel to the slope break zone.

Characteristics and main controlling factors of organic pore development in continental shales of the Lianggaoshan Formation in the Fuxing area, Sichuan Basin

WANG Pengwei, SHEN Baojian, LIU Zhongbao, LI Min, LI Qianwen, RONG Jia, WANG Qianru

2024, 46(3): 499-509. doi: 10.11781/sysydz202403499

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The Lianggaoshan Formation in the Fuxing area of the Sichuan Basin has developed a typical set of medium to high maturity continental shale condensate oil reservoirs. Research on the development characteristics and patterns of organic pores in shale reservoirs at the condensate oil stage is relatively sparse. Using experimental methods such as whole-rock thin section organic petrography identification, argon ion polishing-scanning electron microscopy observation, and energy spectrum measurement, this study analyzed the characteristics and main controlling factors of organic pore development in the Lianggaoshan Formation shales in the Fuxing area. The research results showed that, at the high maturity evolution stage (R_o=1.30%), organic pores developed within the primary organic matter and solid bitumen in the continental shales of the Lianggaoshan Formation. The organic pores were mainly nanopores with irregular shapes, exhibiting honeycomb-like clusters, which locally connected to form micron-sized pores or micro fractures. The type of organic maceral was the basis for organic pore development in the Lianggaoshan Formation shales. Relatively high organic matter abundance and thermal evolutiondegree were key factors controlling the development of organic pores. The inorganic mineral framework and the diagenetic-hydrocarbon generation evolution process were the ultimate guarantees for the preservation of organic pores.

Characteristics of Longwangmiao reservoirs in Penglai gas area and comparison with those in Moxi-Gaoshiti area, central Sichuan Basin

XING Fengcun, LIU Ziqi, QIAN Hongshan, LI Yong, ZHOU Gang, ZHANG Ya, HUANG Maoxuan, LI Chenglong, LONG Hongyu

2024, 46(3): 510-521. doi: 10.11781/sysydz202403510

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The Lower Cambrian Longwangmiao Formation in the Penglai gas area has promising carbonate reservoirs and exhibit strong gas indications, making itself a pivotal exploration zone following the Anyue gas field in the central Sichuan region. However, the lack of clarity regarding reservoir development patterns has constrained exploration deployment. Through comprehensive analysis of the most recent drilling and testing data, this study systematically examines the reservoir characteristics and primary controlling factors of the Longwangmiao Formation in Penglai gas area. Results reveal a mixed sedimentary background of terrigenous debris and carbonate, with reservoirs predominantly situated in the middle and upper strata of the Longwangmiao Formation. The reservoir rock types are predominantly (residual) granular dolomite and crystalline dolomite. Main types of reservoir space include intergranular dissolved pores, intragranular dissolved pores, intercrystalline dissolved pores, and micro-fractures. The reservoir is characterized by low porosity and permeability, with thickness typically ranging between 10-42 m. Reservoir development is controlled by sequence stratigraphy, lithology and diagenesis, particularly evident in the granular dolomite and crystalline dolomite within the middle and upper sections of the progradational parasequence set. Key constructive diagenetic processes include atmospheric freshwater dissolution, oil and gas dissolution and fracture. A comparison with the Moxi-Gaoshiti area in the main area of Anyue gas field suggests similar controlling factors, primarily revolving around granular dolomite, dissolution and fracturing. Nonetheless, the Longwangmiao Formation reservoir in Penglai gas area exhibit distinctive traits such as high ash content, elevated terrigenous clastic content and limited penecontemporaneous exposure. Consequently, identifying high-energy granular dolomite and fine-grained dolomite exposed during the penecontemporaneous period, as well as dolomite modified by supergene karst, emerges as imperative in targeting reservoirs within the Penglai gas area.

Sedimentary microfacies and environment of Paleogene carbonate-rich shale in Dongying Sag, Bohai Bay Basin

WANG Weiqing, LI Pengbo, LI Bo, FANG Zhengwei, WANG Yuhuan

2024, 46(3): 522-531. doi: 10.11781/sysydz202403522

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The identification, classification, and integration of microfacies characteristics of carbonate-rich shale in the Dongying Sag of the Bohai Bay Basin are fundamental for understanding the sedimentary origin and spatial structure of related sediments. Leveraging core and rock thin section data, along with analytical techniques such as X-ray diffraction and scanning electron microscopy, high-resolution core sampling and testing were conducted to analyze the rock mineralogy and paleontology of the carbonate-rich shale in the slope zone of the Dongying Sag. The research findings identified the presence of 10 types of microfacies within the carbonate-rich shale, including algal mat microfacies and shell shale microfacies. These microfacies combined in various ways to form a spectrum of microfacies combinations, exhibiting shale phase transition characteristics on a meter scale. Corresponding to the different stages of saline lake evolution in the Dongying Sag, three types of rock microfacies combinations emerged: shallow water evaporite microfacies combination, oscillatory semi-deep water shale microfacies combination, and oscillatory deep water shale microfacies combination. These combinations were typically controlled by the cyclical rise and fall of lake levels against a backdrop of high-frequency oscillations. In the upper submember of the fourth member of the Shahejie Formation, from bottom to top, as the climate became more humid and hot, weathering intensified, lake levels rose and lake salinity decreased, the proportion of oscillatory deep water shale microfacies combinations gradually increased, while that of shallow water evaporite microfacies combinations decreased. This series of upward-deepening depositional cycles recorded the continuous subsidence and co-evolution of biology and environment during the middle Eocene in the Dongying Sag.

Critical dynamic conditions for gas migration in tight sandstone

WANG Ruogu, QIAO Xiangyang, ZHOU Jinsong, LEI Yuhong, CAO Jun, YIN Xiao, ZHUGENG Bolun

2024, 46(3): 532-541. doi: 10.11781/sysydz202403532

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Physical simulation serves as a crucial method for understanding the mechanisms of underground oil and gas migration and accumulation. To gain a deeper understanding of gas migration mechanisms in tight reservoirs under deep geological conditions, experimental models and boundary conditions were designed using the tight sandstone gas reservoirs of the Upper Paleozoic Shanxi Formation in the Yan'an Gas Field as a case study. Based on ultra-low permeability rock multiphase flow nuclear magnetic resonance online simulation experiments, the study investigated the critical pressure and dynamic conditions governing gas migration in tight sandstone, while also analyzing the factors influencing gas migration and accumulation. Different types of sandstones from the Shanxi Formation were selected, including quartz clean sandstone, quartz-rich low-plasticity particle detrital quartz sandstone, plastic particle-rich detrital sandstone, and tuffaceous matrix-rich quartz sandstone samples, representing reservoir rock facies with different porosity and permeability distributions. Experiments with constant low injection flow rates, different flow velocities (flow rates), and different pressure differences were conducted. The findings indicate that the critical charging pressure of tight sandstone reservoirs is primarily influenced by rock facies and permeability. Dominant rock facies with higher permeability exhibit lower critical charging pressures. For instance, the critical injection pressure of pure quartz sandstone gas typically falls below 1.2 MPa, while it generally remains below 1.5 MPa even for plastic-rich granular lithic sandstones and tuff-rich hybridquartz sandstones with inferior physical properties. Furthermore, there exists no absolute lower limit for the gas charging physical properties of tight sandstone. However, the charging efficiency and gas saturation of tight sandstone are positively correlated with reservoir physical properties, particularly permeability. The more developed the dominant rock facies and the higher the permeability, the higher the charging efficiency and gas saturation.

Characteristics and formation mechanism of stratified deformation of Lower Paleozoic faults in Gaojiapu area, eastern Ordos Basin

CHEN Ping, LI Mingrui, LI Wei, QIANG Min, LU Pengcheng, YU Xiaowei, HAN Wei

2024, 46(3): 542-552. doi: 10.11781/sysydz202403542

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In recent years, exploration breakthroughs have been successively achieved in the strata deeper than the fifth member of the Lower Ordovician Majiagou Formation in the Ordos Basin, revealing its tremendous exploration potential. With the deployment of high-precision 3D seismic data and the deepening of oil and gas exploration, the control exerted by faults on the gas reservoirs in the deeper layers of the fifth member has become increasingly prominent. Based on high-precision 3D seismic data, this study systematically characterized the geometric features of faults in the Gaojiabao area, dissected typical fault structural patterns, established fault formation and evolution models, and, in conjunction with drilling and testing data, discussed the control of faults on the differential enrichment of gas reservoirs in the deeper layers of the Majiagou Formation. The study yielded the following insights: Faults in the Lower Paleozoic of the Gaojiabao area in the Ordos Basin exhibit distinct stratified deformation characteristics, with the two sets of gypsum-salt rocks in the third and fifth members being major contributors to fault stratification. The Lower Paleozoic in the Gaojiabao area mainly develops strike-slip faults with compressional and torsional properties and thrust faults. Through studying the structural morphology and fault patterns of the Gaojiabao area, it is inferred that the Yanshan tectonic movement was the most significant phase of reformation affecting the faults formed during the Caledonian tectonic movement. The coupling of the structural uplift period with the oil-gas charging period in the Gaojiabao area means that faults play multiple roles, including improving reservoirs, connecting source rocks, and controlling traps.

Reservoir limits and grading evaluation criteria of tight glutenite: a case study of Cretaceous Shahezi Formation in Xujiaweizi Fault Depression, Songliao Basin

WANG Junjie, LU Shuangfang, LIN Zizhi, ZHOU Nengwu, ZHANG Pengfei, HUANG Hongsheng, ZHI Qi, LI Baizhi

2024, 46(3): 553-564. doi: 10.11781/sysydz202403553

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The Lower Cretaceous Shahezi Formation glutenite reservoirs in the Xujiaweizi Fault Depression are important tight gas reservoirs in the deep strata of the Songliao Basin. Their complex porosity and permeability relationships pose challenges to determining reservoir boundaries and evaluating reservoir grades. For the Shahezi Formation glutenite reservoirs, the water film thickness method, charge dynamics method, gas testing productivity method, and buoyancy balance method were used to determine theoretical lower limits, gas accumulation lower limits, effective flow lower limits, and reservoir-forming upper limits. The petrophysical values of the reservoir boundaries were determined based on the porosity and permeability relationships under different diagenetic controlling factors. On this basis, reservoir types were classified according to differences in microscopic pore structures, and a grading evaluation standard for tight reservoirs was established. This standard was then applied using logging data to provide a basis for selecting sweet spots in the tight gas exploration areas. The Shahezi Formation glutenite was divided into conventional reservoirs, Class Ⅰ-Ⅳ tight glutenite reservoirs, and non-reservoirs. The reservoir boundaries and classification evaluation results were well matched. Conventional reservoirs had porosity greater than 9% and permeability greater than 0.05×10^-3 μm². Class Ⅰ tight reservoirs had porosity of 8%-9% and permeability of (0.01-0.05)×10^-3 μm². Class Ⅱ tight reservoirs had porosity of 5%-8% and permeability of (0.001-0.01)×10^-3 μm². Class Ⅲ tight reservoirs had porosity of 3.5%-5% and permeability of (0.2-1)×10^-3 μm². Class Ⅳ tight reservoirs had porosity of 2%-3.5% and permeability of (0.05-0.2)×10^-6 μm². Non-reservoirs had porosity less than 2% and permeability less than 0.05×10^-6 μm². The gas production of tight glutenite was controlled by the reservoir type. Class Ⅰ and Class Ⅱ tight reservoirs were favorable high-yield layers. The thickness of favorable reservoirs in the Anda-Songzhan area of the northern Xujiaweizi Fault Depression was large, making it a sweet spot for tight gas exploration and development.

Control mechanism of tectonic action on continuous accumulation and coupling of conventional-unconventional oil and gas reservoirs: a case study of Pingqiao area, southeastern Sichuan Basin

GAO Lingyu, CHEN Kongquan, LU Jianlin, TANG Jiguang, TUO Xiusong, ZHANG Douzhong, YAN Chunming, PANG Yizhen

2024, 46(3): 565-575. doi: 10.11781/sysydz202403565

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This study explored the dynamic control and differences of tectonic action on the formation of conventional and unconventional gas reservoirs in Pingqiao area, southeastern Sichuan Basin. Based on seismic, geolo-gical, inclusion, and other relevant data, together with fault-related fold theory, this study systematically analyzed thestructural characteristics and evolution processes of the area, as well as the dynamic accumulation processes of conventional and unconventional gas reservoirs and the differences in structural impacts on both. A coupled accumulation model of typical conventional and unconventional oil and gas continuous aggregation was established. The Pingqiao area, located in the SE-NW foreland progressive deformation zone of southeastern Sichuan, is controlled by multiple detachment layers and the Jiangnan-Xuefeng orogenic belt, developing fault extension structures and back-thrust structures. The Pingqiao anticline structure was formed during the Yanshanian period. During the middle Yanshanian period, influenced by the foreland expansion of the Jiangnan-Xuefeng tectonic system, the study area experienced intense NE-directed fault-folding. From the late Yanshanian to the Himalayan period, the uplift of central Sichuan and the rise of the Qinghai-Tibet Plateau caused the Pingqiao anticline to continuously uplift. The Cambrian Qiongzhusi Formation and Ordovician Wufeng Formation to Silurian Longmaxi Formation source rocks mainly experienced long-term burial and hydrocarbon generation in the early Yanshanian period and before. In the middle Yanshanian period, tectonic deformation extended to the study area, affecting the conventional gas reservoir (Xixiangchi Group), cap rocks, hydrocarbon traps, and migration, resulting in poor preservation conditions of gas reservoirs. Unconventional gas layers were transformed into anticline structures, with shale gas accumulating towards the core of the anticline, resulting in better overall preservation conditions. From the late Yanshanian to the Himalayan period, strata uplift and depressurization continued to deteriorate the preservation conditions of both types of gas reservoirs. Therefore, this study suggests that the difference in tectonic control on conventional and unconventional gas reservoirs is reflected in the control methods and transformation timing: the lateral hydrocarbon supply during the middle Yanshanian period is the key for conventional gas reservoir formation; tectonic activity in the Late Cretaceous and tectonic uplift from the late Yanshanian to the Himalayan period affect the preservation of shale gas.

Geochemical characteristics and geological significance of noble gases in natural gas from Songliao Basin, China

LI Wei, CHEN Jianfa, WANG Jie, WANG Xiaobo, HE Daxiang, WANG Dongliang, LIU Kaixuan, YOU Bing, CHEN Cong, FU Rao, TANG Shuaiqi, ZHANG Jiaqi

2024, 46(3): 576-589. doi: 10.11781/sysydz202403576

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Geochemistry of noble gases has been applied to the study of deep Earth materials and celestial meteorites. With advancements in measurement technology, it is also increasingly being used in natural gas research. Using the most advanced noble gas mass spectrometer, a systematic analysis was conducted on the abundance and isotopes of noble gas samples collected from the middle and deep Songliao Basin in eastern China to elucidate the compositional characteristics of noble gases in a faulted basin. The findings reveal that the abundance of noble gases in natural gas decreases from light noble gases to heavy noble gases in a left-to-right reversed L-shaped pattern. Specifically, the isotopic ratios of noble gases are: ³He/⁴He at 2.64×10^-6, ²⁰Ne/²²Ne at 9.94, ²¹Ne/²²Ne at 0.029 22, and ⁴⁰Ar/³⁶Ar at 743.7, all of which are higher than atmospheric values. The isotopes ⁸⁰Kr, ⁸⁴Kr, ⁸⁶Kr, and ^131-136Xe show relative excess compared to atmospheric levels, indicating the mixing of mantle-derived gases in the natural gas. Based on the compositional characteristics of noble gases, this study suggests that the natural gas in the middle and deep Songliao Basin originated from inorganic crust and mantle mixing. Additionally, certain differences exist in the contribution of mantle-derived components across different tectonic blocks and categories of natural gas within the basin. Comparison between noble gas compositions and the types of natural gas demonstrates that light noble gases distinguish effectively between different types of natural gas, whereas the composition of heavy noble gases shows no significant differences among various types of natural gas. Noble gas isotopes, in addition to tracing the source of natural gas, can also be used to determine natural gas genesis, distinguish natural gas types and characterize tectonic settings.

Aromatic hydrocarbon evolution patterns and maturity indication significance of marine shale: a comparative study of naturally evolved and thermally simulated samples from the Second White Specks Formation of Cretaceous Colorado Group, Western Canada Basin

GE Zhushi, ZUO Zhaoxi, XIAO Qilin, ZHENG Lunju, HUANG Haiping

2024, 46(3): 590-600. doi: 10.11781/sysydz202403590

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A pyrolysis hydrocarbon generation experiment was conducted on low-maturity marine shale from the Second White Specks (2WS) Formation of the Cretaceous Colorado Group in the Western Canada Basin. Using GC-MS, quantitative analysis of aromatics in naturally evolved and thermally simulated samples was performed to systematically compare the geochemical characteristics of aromatics in both sets of samples. The results indicated that: (1) In the naturally evolved series of 2WS shale, the absolute contents of trimethylnaphthalene (TMN), tetramethylnaphthalene (TeMN), phenanthrene (P) and methylphenanthrene (MP) were relatively higher andincreased with the degree of evolution. In the thermally simulated series, the absolute contents and trends of P and MP remained consistent with those of naturally evolved series at higher thermal evolution levels, whereas the absolute contents of TMN and TeMN were relatively lower and showed different trends, increasing initially and then decreasing with maturity. (2) The trimethylnaphthalene ratio (TMNR) values of the naturally evolved series increased gradually with burial depth, while the TMNR values of the thermally simulated series decreased initially and then increased. The tetramethylnaphthalene ratio (TeMNR) and methylphenanthrene index (MPI) values of both series showed a consistent pattern: TeMNR values decreased initially and then increased with maturity, while MPI values increased with maturity, suggesting that phenanthrene series compounds effectively indicated shale maturity under both thermal simulation and natural evolution conditions. (3) The thermal simulation experiment was capable of effectively replicating the thermal evolution process of aromatics within a certain temperature range. Specifically, TMNR values of the simulated shale deviated from the naturally evolved shale before 350 ℃ but became consistent after 350 ℃. Similarly, alkyl phenanthrenes-related parameters aligned with those of the naturally evolved shale before 425 ℃ but diverged significantly beyond 425 ℃. This divergence was primarily influenced by the change in aromatic evolution mechanisms when the temperature reached a critical value, as well as by factors such as heating rate and the state of organic matter.

Geochemical evidence of paleo-depositional environment of Triassic Adula Formation source rocks of eastern Qiangtang Basin

LIU Xu, LIU Zhongrong, ZHUANG Xinbing, FAN Zhiwei, MA Zeliang, PENG Jinning, LI Fengxun, LI Jipeng, LI Xingqiang

2024, 46(3): 601-613. doi: 10.11781/sysydz202403601

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Abstract:
The mudstone within the Upper Triassic Adula Formation constitutes a crucial hydrocarbon source rock reservoir in the Qiangtang Basin, yet there is considerable debate regarding its paleo-depositional environment. Through systematic studies, including petrology, organic geochemistry, and elemental geochemistry analyses of the Adula Formation at the Eertuolongba section in the Quemocuo area of the eastern Qiangtang Basin, this study investigated the paleo-depositional environment of the Adula Formation source rocks and its impact on hydrocarbonsource rock development. The total organic carbon (TOC) content of the Adula Formation mudstone ranges from 0.27% to 3.46%, with an average of 1.60%, indicating overall favorable source rocks with locally deve-loped high-quality source rocks. The shelf facies mudstone in the lower section of the Adula Formation was formed during a phase of sea-level rise, characterized by deeper, oxygen-poor water, a semi-arid to semi-humid paleoclimate, moderate chemical weathering, minimal terrigenous input, and higher salinity. The deposition of the upper section occurred during a phase of basin contraction and demise, suggesting a transition from shelf facies to delta facies. This period was marked by relatively shallower, oxygen-rich water and a shift from arid to semi-arid to semi-humid paleoclimate, with increased terrigenous input and a saline to semi-saline water environment influenced by freshwater input. The source rocks of the Adula Formation are felsic volcanic rocks, primarily from a continental island arc tectonic setting, likely sourced from the island arc source domain in the Jinsha River suture zone during the Early to Middle Triassic. In the lower section of the Adula Formation, the TOC content of shelf facies mudstone shows a robust positive correlation with redox condition indicators, suggesting that source rock development was mainly controlled by oxygen-poor water conditions during sea-level rise period. In contrast, no significant correlation was observed between TOC content and paleo-environmental parameters in the upper shelf delta facies mudstones. Mudstones with TOC content greater than 2% were likely deposited during periods of high terrigenous input and relatively humid paleoclimate, indicating that source rock development was influenced by multiple factors such as paleoclimate and terrigenous input.

Solid-liquid organic matter interaction mechanism between kerogen and aromatic compounds

LIN Xiaohui, LIANG Tian, ZOU Yanrong, TAO Cheng, WANG Yuan

2024, 46(3): 614-620. doi: 10.11781/sysydz202403614

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Under geological conditions, the initial generation of oil and gas in source rocks reaches saturation before being expelled and migrating, with the adsorption of hydrocarbons by kerogen being a key factor influencing oil saturation. The hydrocarbons produced by pyrolysis interact with kerogen macromolecules. Understanding the solvency and adsorption capacities of solid kerogen organic matter for liquid hydrocarbons can clarify the selective retention of hydrocarbons by source rocks and their characteristics in hydrocarbon generation and expulsion. Aromatic hydrocarbons are crucial components of petroleum hydrocarbons. Based on a three-dimensional model of kerogen, this study employed Autodock software to perform semi-flexible docking calculations between different types of aromatic hydrocarbon molecules (including benzene, polycyclic aromatic hydrocarbons, and their derivatives) and kerogen molecules of varying maturities. The Gibbs free energy required for their binding was calculated to study the characte-risticsof the interaction between aromatic hydrocarbons and kerogen. This study investigated the mechanism of kerogen adsorption of aromatic hydrocarbons at the molecular level, revealing the nature of solid and liquid organic matter interactions. When binding with kerogen of the same maturity, the larger the molecular weight of the polycyclic aromatic hydrocarbons, the greater the number of methyl groups in the compound, and the higher the degree of molecular condensation, the lower the Gibbs free energy required for binding with kerogen molecules. The interaction between aromatic hydrocarbons and kerogen molecules was influenced by three factors: the molecular mass of the aromatic hydrocarbons, the degree of molecular condensation, and the number of methyl groups in the system. After reaching the peak of hydrocarbon generation, kerogen with higher content of aromatic carbon methyl groups showed a stronger adsorption capacity for aromatic hydrocarbons. Polycyclic aromatic hydrocarbons and their derivatives with larger molecular mass and higher degrees of condensation demonstrated stronger binding abilities with kerogen. Conversely, smaller aromatic molecules with conventional connectivity exhibited weaker retention capacities in kerogen, making them more prone to hydrocarbon expulsion, migration, and accumulation into reservoirs.

Chromatography-vacuum low temperature method of methane enrichment and isotopic fractionation in gas samples

LIU Qingmei, LI Jiacheng, JIANG Wenmin, XIONG Yongqiang

2024, 46(3): 621-629. doi: 10.11781/sysydz202403621

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Methane (CH₄) clumped isotope analysis plays a crucial role in the fields of climate change, energy exploration, and planetary research. The purity of CH₄ in samples directly affects the precision and accuracy of high-resolution mass spectrometry in clumped isotope analysis. Addressing the challenge associated with enriching and purifying CH₄ components in gas samples, this study optimized conditions such as carrier gas line speed and sample injection volume based on the principles of gas chromatography (GC) component separation, with real-time monitoring of component peak shapes. Additionally, the recovery rate was quantified using an external standard method and purity was verified through GC component analysis to ensure the effectiveness of the purification process. By optimizing the chromatography-vacuum low-temperature enrichment preparation method, the optimal carrier gas line speed for the IBEX system was determined to be 12 mL/min, with a CH₄ injection volume less than 12 mL. This facilitated visualization of GC peak shapes, thus ensured that the CH₄ peak was essentially separated from the adjacent N₂ interference peak, achieving high-purity enrichment of the CH₄ single component. When the CH₄ content in gas samples was less than 70% and the air content was high, secondary purification was required to improve CH₄ purity. The causes of CH₄ isotopic fractionation during purification using adsorbents like 5Å molecular sieves were discussed, and extending the CH₄ collection time was proposed to eliminate the interference from the 5Å molecular sieve. Currently, this method requires approximately 90 min for a single purification process, with CH₄ recovery and purity ranging from 90.1% to 95.7% and 97.3% to 98.9%, respectively. The differences in isotopic composition (δ¹³C_VPDB and δD_VSMOW, Δ¹³CH₃D, and Δ¹²CH₂D₂) are all less than the analytical error of the mass spectrometer, making them almost negligible.

Safety and accelerated drilling technologies for deep shale gas in Weirong of Sichuan Basin

HE Xinxing, YAN Yancheng, ZHU Liping, WANG Xiyong, ZHU Huashu, WANG Zhiguo

2024, 46(3): 630-637. doi: 10.11781/sysydz202403630

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The Weirong shale gas in the Sichuan Basin, buried at depths of 3 600-3 850 m, represents a prototypical deep shale gas reservoir. Drilling operations face challenges such as a complex pressure system, developed fault-dissolved bodies in certain areas of the Maokou Formation, poor drillability of formations, and high strata temperatures in the Longmaxi Formation. To address these complex geological conditions, this study focused on the safe and accelerated drilling. By combining mature technologies with pilot testing, continuous efforts were made to advance drilling engineering techniques. Through deepening the understanding of the geology of the passing strata sections, targeted solutions for each section were implemented to enhance the precision of engineering techniques. The Weirong shale gas field had gone through three stages: exploration and evaluation, development phaseⅠ, and Ⅱ. This led to the development of safe drilling technologies that emphasize optimization of well structure, track designs avoiding fault-dissolved bodies, wellbore pressure control, and synchronized drilling andfracturing to prevent interference between wells. Additionally, accelerated drilling technologies were cultivated, focusing on a "2D + small 3D" three-dimensional track profile, integrated geological guidance, optimal rock-breaking tools, and enhanced drilling parameters. Applied to over 150 well drillings in the Weirong shale gas field, these technologies increased the rate of penetration from 6.32 m/h at the start of development to 9.12 m/h, reduced the drilling cycle from 106.68 days to 68.75 days (a reduction of 35.56%), achieving the goal of acce-lerated and cost-effective deep shale gas drilling in Weirong area. These technologies provide significant reference value for the development of similar gas reservoirs.

Microscopic characteristics of ultra-low permeability reservoirs in the Shigang Oilfield of the Subei Basin and strategies for enhancing oil recovery

CHEN Hongcai, LI Zhe, JIN Zhongkang, SUN Yongpeng, CHEN Jun, ZHAO Guang

2024, 46(3): 638-646. doi: 10.11781/sysydz202403638

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The Shigang Oilfield in the Subei Basin is characterized by low-porosity and ultra-low permeability sandstone reservoirs. The natural productivity of the oil wells is low, but hydraulic fracturing followed by water injection can improve oil production capacity. However, during the development of the oilfield, problems such as low oil recovery rates, low recovery factors, and poor development effectiveness have become apparent, exacerbating development challenges. Therefore, it is necessary to identify the reasons for inefficient development and explore strategies to enhance recovery, providing a theoretical basis for improving the development effectiveness of the Shigang Oilfield. Using methods such as whole-rock mineral composition analysis, gas-measured core porosity and permeability parameters, and core sensitivity evaluation, the micro characteristics of the reservoir were analyzed in terms of rock mineral composition, pore-throat structure, and rock sensitivity. Numerical reservoir simulations and laboratory core experiments were conducted to study the distribution characteristics of residual oil after fracturing water flooding. Strategies to enhance oil recovery were investigated through nuclear magnetic resonance online displacement experiments. The results showed that the reservoir cores exhibited typical low-porosity and ultra-low permeability characteristics, with certain velocity sensitivity and water sensitivity during development. After fracturing water flooding, residual oil in the cores was mainly distributed in pore channels with diameters ranging from 0.01 to 1 μm. The use of surfactant flooding and secondary water flooding increased the recovery rate of residual oil in the cores by 14.81%. The main reasons for inefficient development included ultra-low reservoir permeability, the development of micro pores and micro fractures, and sensitivity to velocity and water. Water injection development could cause rock mineral swelling and migration, increasing flow resistance. Therefore, after fracturing water flooding, only the recovery of residual oil along the main flow paths was significantly improved, with the overall utilization degree remaining low, and a considerable amount of residual oil still concentrated in the reservoir. It is recommended to use chemical flooding and multiple rounds of displacement to enhance the utilization of oil in medium and small pore channels, further improving the development effectiveness of the oilfield.

2024, 46(3): 647-647.

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Abstract:

2024 Vol. 46, No. 3

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