石油实验地质

2023, 45(4): .

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Abstract:

Shale dominant lithofacies and shale oil enrichment model of Lower Permian Fengcheng Formation in Hashan area, Junggar Basin

ZHANG Kuihua, SUN Zhongliang, ZHANG Guanlong, SONG Zhenxiang, YU Hongzhou, ZHOU Jian, CAO Tingting, SONG Meiyuan, WANG Bin, LI Zhiming

2023, 45(4): 593-605. doi: 10.11781/sysydz202304593

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Abstract:
Compared with the Mahu Sag in the Junggar Basin, the adjacent Hashan area has undergone multi-stage napping and complicated oil-gas formation and evolution process, making its shale oil exploration facing many challenges, such as unclear dominant lithofacies and enrichment law. In order to optimize the dominant lithofacies of the Lower Permian Fengcheng Formation shale in Hashan area and summarize the enrichment model of shale oil, by taking more than 200 samples from 8 exploration wells in the area, including Hashan 5 and Hashen X1 wells, and using methods such as core and ordinary thin section observation, a systematic classification of shale lithofacies types was carried out based on the study of sedimentary environment and facies. A comprehensive evaluation of reservoir physical properties and oil content was conducted based on lithofacies by combining experimental methods such as XRD, scanning electron microscopy, low-temperature nitrogen adsorption, and pyrolysis. The enrichment law of the Fengcheng Formation shale oil in Hashan area was preliminarily revealed based on the correlation analysis of shale mineral composition, organic matter abundance and oil content. The results show that the Fengcheng Formation shale in Hashan area can be divided into four lithofacies types: terrigenous clastic, dolomitic diamict, alkaline mineral diamict and volcanic clastic diamict. The (argillaceous) siltstone in terrigenous clastic lithofacies, the dolomitic sandstone in dolomitic diamict lithofacies, and the volcanic clastic diamict lithofacies have good physical properties and oil content, which are good shale oil reservoirs. The shale oil enrichment patterns can be divided into three types: in the terrigenous clastic lithofacies of the outer delta front, the shale oil enrichment patterns are mainly migrated from adjacent strata. In the shallow- semi-deep lake section, the dolomitic mixed-deposit lithofacies are mainly the shale oil enrichment model of the same layer fracture migration and adjacent layer migration, while the volcaniclastic mixed-deposit lithofacies are mainly the self-generated and self-stored matrix shale oil enrichment model.

Sedimentary characteristics and sedimentary model of the Upper Permian-Lower Triassic shallow braided river delta in the hinterland of the Junggar Basin

WANG Bin, QIU Qi, LU Yongchao, LIU Dezhi, WANG Jiyuan, DU Xuebin, LI Zhenming, LI Xiangquan

2023, 45(4): 606-619. doi: 10.11781/sysydz202304606

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The lower play of the Junggar Basin has huge oil and gas potential, which is the most important strategic succession field for oil and gas exploration. Large-scale delta sand bodies are developed in Permian and Triassic in the four sags in the hinterland, in which new discoveries of oil and gas have been made in succession. In order to reveal the sedimentary characteristics, sedimentary model, and distribution patterns of sand bodies in the hinterland, the studies on basin prototype, sequence framework, paleogeomorphic restoration and sedimentary system were systematically carried out based on a large number of newly drilled cores, logging and geophysical data. The results show that: the development background of large depression lake basin can be identified in the development period of the Upper Permian-Lower Triassic shallow water braided river delta in the hinterland of the basin, and the study area has the characteristics of flat terrain, small slope, sufficient material supply, extremely shallow and frequently turbulent water bodies, alternating oxidation and reduction environments, and overall oxidation environment during the sedimentation period. The shallow braided river delta is characterized by coarse grain size, low impurity content, medium texture maturity, long distance transportation, strong hydrodynamic scouring, cross bedding and parallel bedding. The advantageous water system in the sedimentation period of the Upper Wuerhe and Baikouquan formations in the hinterland mainly comes from the northwest and northeast, and extends from north to south as a whole, with three provenance systems developed, namely Wuerhe provenance, Karamay provenance and Kelameily provenance. The terrain within the basin has obvious zoning characteristics, forming four facies belts namely fan delta area, braided river delta plain area, front area and lake area, thus forming a shallow water braided river delta sedimentary pattern of "large plain, small front" in the hinterland, where plain area and front area are favorable sand body development zones.

Development characteristics and quantitative characterization of pore evolution of deep and ultra-deep clastic reservoirs in the hinterland of the Junggar Basin

ZHANG Guanlong, WANG Jiyuan, WANG Bin, LIU Dezhi, ZHENG Sheng, MU Yuqing, QIU Qi

2023, 45(4): 620-631. doi: 10.11781/sysydz202304620

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The lower play (Permian to Triassic) in the hinterland is the most important strategic succession field for oil and gas exploration in the Junggar Basin. Multiple wells have been drilled into high-quality clastic rock reservoirs below 6 000 m, greatly breaking through the deadline of buried depth of traditional clastic rock effective reservoirs. It has been made clear that the development status and pore evolution process are the key issues that determine whether oil and gas can be accumulated. Taking typical drilling wells in the hinterland as an example, this paper comprehensively analyzed the petrology, physical properties and pore structure characteristics of deep and ultra-deep clastic reservoirs in the hinterland of the Junggar Basin from a qualitative and quantitative perspective, and quantitatively restored the pore evolution process by integrating the microscopic analysis of rock thin sections, porosity and permeability tests, image analysis technology, quantitative characterization of porosity evolution, temperature measurement of inclusions, basin modeling and other methods. The results show that the clastic rock in the lower play of the hinterland is mainly developed in the Permian Upper Wuerhe Formation, Triassic Baikouquan Formation and Triassic Kelamayi Formation, of which the sand in the Triassic Baikouquan Formation is the most developed, followed by the Permian Upper Wuerhe Formation and Triassic Kalamayi Formation. There is little difference in rock types among different layers, which mainly composed of lithic sandstone with a small amount of feldspar lithic sandstone. The composition of rock debris is mainly medium-basic volcanic rock debris, with low content of feldspar and quartz, and the sum of them is generally less than 20%. The Kelamayi Formation is dominated by primary pores with the best reservoir property and the highest porosity of 13.18%. The Upper Wuerhe Formation and Baikouquan Formation are dominated by secondary corrosion pores, and the corrosion materials are mainly medium-basic volcanic debris, laumontite cement and a small amount of feldspar. The reservoir properties of them are not as good as those of the Kelamayi Formation. The pore evolution of the Kelamayi Formation has experienced weak compaction (21.08% pore reduction by compaction), weak cementation (2.88% pore reduction by cementation), and weak corrosion (1.4% pore increase by corrosion). Today's high porosity is mainly due to the large amount of preservation of primary pores under weak compaction and late weak cementation. The Baikouquan Formation and Upper Wuerhe Formation have undergone strong compaction (26.60% and 26.43% pore reduction by compaction, respectively), strong cementation (7.43% and 11% pore reduction by cementation, respectively), and strong corrosion (6.32% and 4.21% pore increase by corrosion, respectively). Secondary corrosion is the main way for them to increase porosity, but it is insufficient to compensate for the porosity reduction effect of strong compaction and cementation, resulting in lower porosity in the two formations.

Diagenesis and pore evolution of Cretaceous Qingshuihe Formation reservoir in western section of southern margin of Junggar Basin

WANG Jian, GAO Chonglong, BAI Lei, XIANG Baoli, LIU Jin, XIAN Benzhong, LIAN Lixia, LIU Ke

2023, 45(4): 632-645. doi: 10.11781/sysydz202304632

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The Qingshuihe Formation in the western section of the southern margin of the Junggar Basin has excellent oil and gas exploration prospects. The systematic study of its diagenesis characteristics and pore evolution process will provide guidance for the later fine exploration and evaluation of oil and gas. Therefore, based on the analysis of ordinary thin sections, cast thin sections, whole rock X-ray diffraction, grain size, scanning electron microscopy, carbon and oxygen isotopes of carbonate cements and fluid inclusions, the diagenesis characteristics and pore evolution process of the Qingshuihe Formation in the western section of the southern margin of the Junggar Basin were systematically studied, and the differences of reservoir pore evolution process between different diagenetic facies were further discussed. The study shows that: (1)The reservoir of the Qingshuihe Formation in the studied area is dominated by glutenite. The content of rock debris is high, with an average of 65.97%, mainly tuff rock debris. The cement is mainly calcite. The average porosity of the reservoir is 6.2%, and the average permeability is 7.45×10^-3 μm². It is generally a tight reservoir of low porosity and low permeability, but high-quality reservoirs are still developed locally; (2)The reservoir burial mode of the Qingshuihe Formation in the southern margin of the Junggar Basin is characterized by long-term shallow burial and late rapid deep burial, and can be further divided into four evolutionary stages: long-term shallow burial, tectonic uplift to near surface, normal deep burial, and rapid deep burial. The diagenetic evolution of the reservoir was in early diagenetic stage A in the long-term shallow burial, tectonic uplift to near surface, and normal deep burial stages, while in the rapid deep burial stage, the reservoir was in early diagenetic stage B to middle diagenetic stage A; (3)The reservoir of the Qingshuihe Formation can be divided into four typical diagenetic facies types, namely, strong compaction facies, calcareous/iron argillaceous strong cementation facies, tuffaceous filling weak dissolution facies, and weak compaction pore development facies. The pore evolution model of the clastic rock reservoir of the Qingshuihe Formation in the southern margin of the Junggar Basin was established based on the constraints of diagenetic facies. The weak compaction pore development facies are high-quality reservoir diagenetic facies, followed by tuffaceous filling weak dissolution facies.

Geochemical characteristics and source of crude oil from the eastern Shawan Sag, Junggar Basin

WU Xiaoqi, REN Xincheng, LIU Dezhi, CHEN Yingbin, MU Yuqing, WANG Bin, SHANG Fengkai, SUN Zhongliang, QU Yansheng, SONG Zhenxiang, QIU Qi

2023, 45(4): 646-655. doi: 10.11781/sysydz202304646

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The Shawan Sag is one of the important exploration areas in the hinterland of the Junggar Basin. In order to better clarify the source of crude oil from the Permian, Jurassic and Cretaceous reservoirs in the sag and identify hydrocarbon accumulation processes and enrichment pattern, the authors conducted a carbon isotope and biomarker analysis on the typical crude oil samples from the eastern Shawan Sag in this study, and further carried out crude oil classification and oil-source correlation based on the analysis of geochemical characteristics of crude oil. The results indicate that the crude oil from different strata in the eastern Shawan Sag can be divided into three types. The first type mainly occurs in the Permian and Jurassic reservoirs, and its whole oil δ¹³C value and Pr/Ph ratio range from -31.0‰ to -29.0‰ and from 1.0 to 2.0, respectively. The relative contents of αααR regular sterane display the characteristics of C₂₇ < C₂₈ < C₂₉, and the terpanes are mainly characterized by C₂₀ < C₂₁>C₂₃ TT and C₂₄TeT/C₂₆TT < 1, with the gammacerane index lower than 0.30. This type of crude oil is mainly derived from the source rocks in the Middle Permian Lower Wuerhe Formation. In the oil samples from the Upper Permian Upper Wuerhe Formation, Ts content is below the detection limit, the β-carotane/C₃₀ hopane ratio is greater than 1, and the tricyclic terpane distribution displays the characteristics of C₂₀>C₂₁>C₂₃TT. The distribution fraction of methyl phenanthrene reflects that the crude oil is in the stage of high-maturity evolution. All these indicate the mixing of crude oil generated in the Lower Permian source rocks. The second type occurs in the Middle Jurassic reservoirs. The whole oil δ¹³C value and individual n-alkanes δ¹³C value are higher than -29.0‰. The Pr/Ph ratio is relatively higher, ranging from 2.0 to 2.5, with C₂₄TeT/C₂₆TT>1, which indicate that this type of crude oil is mainly derived from the Jurassic source rocks. The third type occurs in the Lower Cretaceous reservoirs, and its whole oil δ¹³C value and Pr/Ph ratio are lower than -31.0‰ and 1.0, respectively. The αααR regular sterane contents display the characteristics of C₂₇≈C₂₈ <C₂₉, with the gammacerane index higher than 0.50. The individual n-alkanes δ¹³C value gradually decreases with the increase of carbon number and is commonly lower than -31.0‰. This type of oil is demonstrated to be mainly derived from the Lower Cretaceous source rocks.

Characteristics of volcanic-sedimentary formations and developmental patterns of source and reservoir rocks in an island arc environment of Shibei Sag, Junggar Basin: taking the Carboniferous Jiangbasitao Formation as an example

XIONG Wei, WANG Yue, XIONG Zhengrong, MEI Wenke, BAI Zhongcai, CAI Qianru, SONG Zhihua

2023, 45(4): 656-666. doi: 10.11781/sysydz202304656

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The Shibei Sag is located in the north of Luliang Uplift in the eastern Junggar Basin. There has been no breakthrough in the exploration of Carboniferous volcanic traps in the Shibei Sag in the past years. Recent drilling of well Zhunbei 6 reveals that the self-generating and self-preserving oil and gas reservoirs in the Carboniferous Jiangbasitao Formation have great exploration potential. However, there is scarce study on this type of reservoir. In order to study the characteristics of volcanic-sedimentary formations and developmental patterns of source and reservoir rocks in an island arc environment of Shibei Sag, the volcanic-sedimentary formations and source rock characteristics of the Jiangbasitao Formation were systematically studied based on previous study, drilling cores, seismic and test data, as well as the analysis of geochemical characteristics of source rocks, and the developmental pattern of volcanic, pyroclastic and source rocks under the control of island arc was established, with the aim of providing theory basis for oil and gas exploration in areas with the same sedimentary background. The results show that the basic volcanic rocks of the Jiangbasitao Formation in the Shibei Sag were formed in an island arc environment related to oceanic subduction. The volcanic formations are mainly composed of near-crater explosive facies, near-crater overflow facies and far-crater explosive facies. The sedimentary formations are dominated by fan delta facies tuffaceous glutenite and sandstone in the franking regions of the island arc and littoral neritic facies tuffaceous mudstone in the low-lying area of the far island arc. The tuffaceous mudstone of the Jiangbasitao Formation is a set of medium source rocks in the mature and high-maturity stages, which have a banding distribution along the northeast-southwest direction with a thickness of 100-500 m. During the sedimentary period of the Jiangbasitao Formation, the volcanic island arc erupted intermittently, and the tuff in the low-lying area of the far island arc and the littoral neritic facies tuffaceous mudstone were interbedded. The tuffaceous mudstones have a good source-reservoir configuration relationship with fan delta glutenite and island arc volcanic rocks. These two types of reservoirs are the key exploration directions in the next step.

Hydrocarbon generation and evolution characteristics of Carboniferous source rocks on the northeastern margin of the Junggar Basin and its petroleum geological significance

WANG Shengzhu, MEI Wenke, XIONG Zhengrong, BAI Zhongcai, XIONG Wei, YU Hongzhou, BAO Jun

2023, 45(4): 667-680. doi: 10.11781/sysydz202304667

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Various types of source rocks were developed in the Carboniferous trench-arc basin environment on the northeastern margin of the Junggar Basin. In order to implement the efficient hydrocarbon supply area of the main source rocks and guide the oil and gas exploration in this area, researches on the hydrocarbon generation mechanism, potential, evolution process, and hydrocarbon supply characteristics of different types of source rocks were carried out through the combination of geology and geochemistry based on the test data of drilling, organic geochemistry of outcrop source rock samples, and hydrocarbon-generating thermal simulation experiments. The results show that there are three types of source rocks, namely mudstone, tuffaceous mudstone and carbonaceous mudstone in the Carboniferous in the study area. Different source rocks have different parent material composition and activation energy distribution for hydrocarbon generation, and their hydrocarbon generation potential and evolution model have obvious differences. Mudstone generated hydrocarbon rapidly at relatively low maturity stage, tuffaceous mudstone continued to generate hydrocarbon slowly, and carbonaceous mudstone generated hydrocarbon rapidly at relatively higher maturity stage. Later structural transformation, sedimentary filling and geothermal field evolution jointly controlled the thermal evolution process and hydrocarbon supply characteristics of source rocks. Hydrocarbon generation and hydrocarbon loss of source rocks were coupled in time and space, and six hydrocarbon supply models can be divided, i.e., (1) high-efficiency hydrocarbon generation, low hydrocarbon loss, high-efficiency hydrocarbon supply, (2) high-efficiency hydrocarbon generation, relatively high hydrocarbon loss, relatively high-efficiency hydrocarbon supply, (3) relatively high-efficiency hydrocarbon generation, low hydrocarbon loss, relatively high-efficiency hydrocarbon supply, (4) relatively high-efficiency hydrocarbon generation, high hydrocarbon loss, low-efficiency hydrocarbon supply, (5) low-efficiency hydrocarbon generation, high hydrocarbon loss, relatively low-efficiency hydrocarbon supply, and (6) low-efficiency hydrocarbon generation, low hydrocarbon loss, low-efficiency hydrocarbon supply. Among them, the Shibei and Dishuiquan sags are relatively high-efficiency hydrocarbon generation, low hydrocarbon loss and relatively high-efficiency hydrocarbon supply units with material foundation for forming large and medium-sized oil and gas fields, which are the most favorable exploration targets at present.

Quantitative characterization and main controlling factors of shale oil occurrence in Permian Fengcheng Formation, Mahu Sag, Junggar Basin

LI Jiarui, YANG Zhi, WANG Zhaoyun, TANG Yong, ZHANG Hong, JIANG Wenqi, WANG Xiaoni, WEI Qizhao

2023, 45(4): 681-692. doi: 10.11781/sysydz202304681

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The characteristics and controlling factors of shale oil occurrence in Permian Fengcheng Formation of the Mahu Sag, Junggar Basin are complex, making occurrence state identification and quantitative characterization difficult. It is of great significance to clarify the occurrence characteristics and controlling factors of shale oil for selecting sweet spots. In order to characterize the content of shale oil in different occurrence states, some shale samples in the central and slope areas of the sag were extracted step by step, and a quantitative characte-rization experiment method of shale oil in different occurrence states was established, obtaining the contents of free light hydrocarbon, free heavy hydrocarbon and adsorbed hydrocarbon, respectively. Based on the study of organic geochemistry and reservoir micro-characteristics, the following conclusions are obtained. Due to the low TOC and clay contents in the study area, the shale oil in the Fengcheng Formation mainly occurs in dissociative state and has the least adsorbed hydrocarbon content. Shale oil occurs mostly on mineral surface and in kerogen in oil film state, heavy hydrocarbons usually occur in shale with large micropore specific surface area, and macropores are the main occurrence space of free oil. With the increase of organic matter abundance and pore size, the shale oil content in different occurrence states shows an increasing trend, indicating that the higher organic matter abundance and larger pore size are conducive to shale oil enrichment. Maturity can greatly affect the adsorption capacity of fluid in shale, and the higher the maturity of organic matter, the higher the proportion of free hydrocarbons and the lower the proportion of adsorbed hydrocarbons. The increase of specific surface area promotes the enrichment of adsorbed oil and free heavy hydrocarbons, and restricts the enrichment of free light hydrocarbons, indicating that the specific surface area of mesoporous pores has a controlling effect on the adsorption capacity of shale oil, i.e., the larger the specific surface area, the stronger the adsorption capacity of shale oil. The relevant research and recognition can provide a basis for selecting sweet spots and evaluating the benefits of shale oil exploitation in the study area.

Fine-grained sedimentary characteristics and evolution model of Permian Fengcheng Formation in Hashan area, Junggar Basin

LI Zhenming, XIONG Wei, WANG Bin, SONG Zhenxiang, SONG Meiyuan, SUN Zhongliang, YU Hongzhou, ZHOU Jian, WU Xiaoqi

2023, 45(4): 693-704. doi: 10.11781/sysydz202304693

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The geological conditions of Hashan area on the northwestern margin of the Junggar Basin are complicated and it is difficult to explore. It is of great significance to clarify the sedimentary and evolutionary characte-ristics of source rocks in the Permian Fengcheng Formation in this area for expanding oil and gas exploration on the basin margin. Based on the analysis of whole-rock XRD, elemental geochemistry, organic matter abundance, thin section identification, and lithofacies association characteristics, this paper conducted a comparative analysis of the sedimentary characteristics, lithology, and lithofacies association characteristics of the Fengcheng Formation in the Mahu Sag and Hashan area, restored the ancient sedimentary environment evolution sequence in the study area, and established a model of ancient sedimentary evolution. The research results show that the lithofacies association characteristics and ancient sedimentary environment evolution sequence of the Fengcheng Formation in the Hashan area are highly similar to those in the Mahu Sag, which are generally fine-grained sediments mixed from multiple sources in an alkaline lake with a volcanic background, and various lithofacies associations are developed. The sedimentary paleoenvironment has phased evolution characteristics. The large number of typical alkaline minerals in the second member of Fengcheng Formation in Hashan area reveals the development of another lake basin center in addition to the Mahu Sag. During the deposition of the first member of Fengcheng Formation (P₁f¹), the lake level was relatively higher, the water salinity was low, the climate was semi-arid, and volcanic sedimentation was developed, with lithofacies mainly composed of organic-rich blocky tuffaceous limestone. In the lower part of the second member of Fengcheng Formation (P₁f²), the basin began to shrink, the climate became relatively drier, the water became saltier, the environment became more limited, and the lithofacies were mainly organic-rich layered dolomitic mudstone. In the top of the P₁f² and the lower part of the third member of Fengcheng Formation (P₁f³), the environment was relatively closed, the water salinity was higher, a large number of alkaline minerals were developed, and the lithofacies were mainly organic-rich layered alkaline dolomitic mudstone and organic-rich layered mixed shale. In the upper part of P₁f³, the input of terrigenous debris increased, salinization weakened, a fan-delta system was developed, and the lithofacies were mainly organic-rich blocky fine sandstone. The sedimentary environment of the Fengcheng Formation has a controlling effect on organic matter enrichment. Overall, a deep-water environment with less input of debris, warm and humid conditions, and relatively lower salinity is more conducive to organic matter enrichment.

Experimental study on hydrocarbon generation and expulsion characteristics of shale with different source-reservoir structures in Lucaogou Formation, Jimsar Sag, Junggar Basin

LI Erting, PAN Yueyang, YANG Guangqing, BAI Haifeng, MA Wanyun, ZENG Jianhui, ZHANG Yu

2023, 45(4): 705-713. doi: 10.11781/sysydz202304705

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The Permian Lucaogou Formation in the Jimusar Sag in the east of the Junggar Basin is a typical continental shale oil series in China. Employing the semi-closed thermal simulation system, an experimental study on hydrocarbon generation and expulsion of shale with different source-reservoir structures was carried out to explore the efficiency and composition characteristics of hydrocarbon generation and expulsion of shale in the Permian Lucaogou Formation with different source-reservoir structures so as to provide reference for the enrichment rule of shale hydrocarbon and the fine evaluation of "sweet spots". The experimental results show that thick reservoir interbedded with thin source rock is more conducive to hydrocarbon expulsion and features the highest hydrocarbon expulsion efficiency, while thin source rock interbedded with thin reservoir features slightly lower hydrocarbon expulsion efficiency, and thick source rock interbedded with thin reservoir features the lowest hydrocarbon expulsion efficiency. When reservoir lithology is clastic rock, the hydrocarbon expulsion efficiency of thick reservoir interbedded with thin source rock, thin source rock interbedded with thin reservoir, and thick source rock interbedded with thin reservoir are 35.6%, 30.7%, and 25.6%, respectively. When reservoir lithology is carbonate rock, the hydrocarbon expulsion efficiency of these three combinations are 27.4%, 27.5%, and 12.3%, respectively. Combined with composition of expelled hydrocarbon, received hydrocarbon in reservoir, and retained hydrocarbon in source rock, it is found that received hydrocarbon in reservoir rock is mainly supplied by neighboring sources, and the farther away from source-reservoir interface, the less relevant relationship between source rock and hydrocarbon in reservoir. Hydrocarbon in reservoir is supplied by lower adjacent source rock in thick reservoir interbedded with thin source rock, and the received hydrocarbon in upper clastic reservoir is 10.7 mg/g, while received hydrocarbon in lower clastic reservoir is only 1.4 mg/g. The thick source rock interbedded with thin reservoir is mainly self-generated and self-stored, and the content of retained hydrocarbon in source rock is high, the received hydrocarbon in upper clastic reservoir is 6.0 mg/g, while retained hydrocarbon in source rock is 21.1 mg/g. Hydrocarbon in reservoir is mainly supplied by lower adjacent source rock and partly from its own source rock in thin source rock interbedded with thin reservoir. There is no significant difference between source rock and reservoir rock in the extraction family, with the content of saturated hydrocarbon in the range of 22.8%-33.0%, aromatics in the range of 6.2%-15.1%, and non-hydrocarbon and asphaltene in the range of 28.5%-41.1% and 21.0%-30.0%. Moreover, different reservoir lithology has relatively weak influence on hydrocarbon generation and expulsion efficiency, and the hydrocarbon-bearing heterogeneity is weak in thin source rock interbedded with thin reservoir. From the perspective of hydrocarbon generation and expulsion efficiency of shale with different source-reservoir structures, thick reservoir interbedded with thin source rock and thin source rock interbedded with thin reservoir are the favorable combinations for hydrocarbon exploration in the shale of the Lucaogou Formation.

Characteristics and main controlling factors of the limy source rock gas reservoir in the first member of the Middle Permian Maokou Formation in the southern Sichuan and western Chongqing area: a case study of well DB 1

LIANG Xing, XU Zhengyu, LI Weimin, MA Liqiao, JI Yubing, LUO Yufeng, DING Bangchun

2023, 45(4): 714-725. doi: 10.11781/sysydz202304714

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The Middle Permian Maokou Formation in the Sichuan Basin is an important natural gas payzone. Recently, Zhejiang Oilfield Company of CNPC obtained industrial gas flow of vertical well test 42×10³ m³/d and horizontal well (well DB 1H) test 556×10³ m³/d in the limy source rock gas reservoir of eyelid and eyeball- shaped limestone in the first member of the Maokou Formation in well DB 1, Da'an exploration area, western Chongqing. A breakthrough has been made in the unconventional gas exploration of argillaceous limestone in the southern Sichuan and western Chongqing area, showing good exploration prospects in this area. The eyelid and eyeball-shaped limestone in the first member of the Maokou Formation in the Sichuan Basin has the characteristics of self-generation and self-storage, continuous and stable distribution and high thermal maturity. The limestone of central gentle slope facies shows no water sensitivity or acid sensitivity, and is dominated by carbonate brittle minerals, which is ideal for acid-fracturing development. It is of great significance to study the characteristics and main controlling factors of the organic rich limestone reservoir. Taking well DB 1 as an example, this paper carried out a study on the petrology, sedimentology and reservoir characteristics of the first member of the Maokou Formation, and it is found that, deposited on the central gentle slope with frequent water activity and abundant organism, the dark gray to black micrite with high organic matter content has good physical properties. In general, submember c has better physical properties than submember a. The development degree of macropores in eyelid-shaped limestone is higher than that in eyeball-shaped limestone, and the development degree of micropores is not much different. The main pore types of the first member of the Maokou Formation include dissolution pores, fractures, clay mineral apertures and organic pores. The pores in clay minerals (mainly talc) and organic matters are mainly distributed in the eyelid-shaped limestone. Depositional process and diagenesis are the main factors controlling the development of the eyelid and eyeball-shaped limestone reservoirs. The central gentle slope facies controls the development and distribution features of the organic-rich micrites. Diagenesis as well as fracture and dissolution effects improve the reservoir capacity of limestone, which is critical for hydrocarbon accumulation. Stable and high yield commercial gas flow was obtained in the vertical wells and horizontal wells in the first member of the Maokou Formation which has high organic matter content in well DB 1 block in the western Chongqing area, indicating that the accumulation and occurrence conditions of limestone source rock gas are good in the first member of the Maokou Formation. It has two kinds of accumulation modes with self-generation and self-storage dominance and short distance aggregation of local structural bands, and has the characteristics of continuous distribution of gas reservoir and large resource scale. The "continuous gas reservoir: in the limestone source rock in the first member of the Maokou Formation has great exploration potential, which will become an important exploration target with good potential in the Sichuan Basin.

Paleotemperature evolution and its driving mechanism during the formation of limestone-marl alternations in first member of Middle Permian Maokou Formation in Sichuan Basin

FAN Jianping, SONG Jinmin, LIU Shugen, JIANG Qingchun, LI Zhiwu, YANG Di, JIN Xin, SU Wang, YE Yuehao, HUANG Shipeng, WANG Jiarui, JIANG Hua, LUO Ping

2023, 45(4): 726-738. doi: 10.11781/sysydz202304726

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From the Late Carboniferous to the end of Middle Permian, the most intense glacial event in history of Phanerozoic occurred and it is also the last transition period from icehouse stage to greenhouse stage in geological history. In this paper, the paleotemperature and paleoclimate in the first member of the Middle Permian Maokou Formation (Mao-1) were restored by means of thin section identification, scanning electron microscope, major elements, trace elements, carbon isotopes, oxygen isotopes and strontium isotopes, and the major climate evolution process and its driving mechanism in the Middle Permian were discussed. The results show that the biological assemblage type (mainly composed of foraminifera, brachiopods and molluscs, without reef-building organisms or calcareous green algae) and rock structure characteristics (supported by bioclastic and plaster, without oolitic or other non-skeletal particles) of the limestone-marl alternations in the Mao-1 member are similar to those of the international typical cool-water carbonate. During the limestone sedimentary period, the paleotemperature of seawater was 3.72 to 12.38 ℃ (8.15 ℃ in average, δ¹⁸O standard) or 13.79 to 14.28 ℃ (13.90 ℃ in average, ω(Mg)/ ω(Ca) standard), while during the marl sedimentary period, the paleotemperature of seawater was 7.00 to 14.24 ℃ (10.97 ℃ in average, δ¹⁸O standard) and 13.82 to 15.41 ℃ (14.27 ℃ in average, ω(Mg)/ω(Ca) standard). The paleotemperature changes in the sedimentary period of Mao-1 Member was mainly driven by the short eccentricity cycle of Milankovitch. The cyclical change of the short eccentricity was the driving mechanism of paleotemperature and paleoclimate cycle changes.

Pressure evolution of shale gas reservoirs in Wufeng-Longmaxi formations, Lintanchang area, southeast Sichuan Basin and its geological significance

TANG Jianming, HE Jianhua, WEI Limin, LI Yong, DENG Hucheng, LI Ruixue, ZHAO Shuang

2023, 45(4): 739-750. doi: 10.11781/sysydz202304739

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The Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation in Lintanchang area of the southeastern Sichuan Basin has good exploration and development conditions, and clarifying the paleo-fluid pressure evolution is of great significance for revealing the process of shale gas accumulation and fugitive emission. Taking the shale tectonic fractures and fluid overpressure fracture veins of the Wufeng-Longmaxi formations in Lintanchang area as the research object, the paleo-fluid pressure evolution process in this area and its controlling impact were investigated using cathodoluminescence, inclusion temperature measurement, laser Raman analysis, and basin simulation. The study shows that: (1) Lintanchang area has experienced four stages: normal pressure, mild overpressure to normal pressure, overpressure, and pressure relief. Overpressure is mainly due to hydrocarbon generation. Pressure relief is mainly caused by shale gas fugitive emission. The gas reservoir pressure relief reaches 54% of the initial pressure during the pressure relief stage. (2) There are two stages of vein filling in the fractures at the bottom of the black shale in the Wufeng-Longmaxi formations. The first stage is formed in the sedimentation and burial stage at 131-118 Ma, the temperature is 178-205 ℃, and the trapping pressure of methane inclusions is 105.6-119.8 MPa. The second stage is formed in the tectonic uplift stage at 25-18 Ma, the temperature is 150-175 ℃, the methane inclusions have relatively low salinity and its trapping pressure is 80.8-92.1 MPa. The low pressure coefficient (1.37-1.49) indicates that mass fugitive emission has occurred. (3) The late tectonic movement, especially the rapid uplift in the late Himalayan period, is the root cause of the fugitive emission and pressure relief of the gas reservoirs. The decrease of the roundness and pore size of the organic pores indicates the deterioration of reservoir physical properties. However, due to the long formation and preservation time of the gas reservoirs, the shale in the Wufeng-Longmaxi formations in Lintanchang area still has good exploration potential. This study is helpful to deepen the understanding of the accumulation mechanism of the normal-pressure shale gas reservoirs in Lintanchang area and can provide theoretical guidance for optimal selection of favorable shale gas exploration areas.

Characteristics of the deep and ultra-deep shale reservoirs of the Wufeng-Longmaxi formations in the southeastern Sichuan Basin and the significance of shale gas exploration

WEI Fubin, LIU Zhujiang, CHEN Feiran, YUAN Tao, LI Fei

2023, 45(4): 751-760. doi: 10.11781/sysydz202304751

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Fruitful achievements have been made in shale gas exploration in the middle and deep areas from the Upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation in the southeastern Sichuan Basin, and in the research on shale reservoir characteristics and main controlling factors. As the key direction of current shale exploration, the deep and ultra-deep areas are limited by drilling and other factors, and the research on reservoir development characteristics and differences with the middle and deep shale reservoirs is insufficient. In order to clarify the characteristics of the deep and ultra-deep shale reservoirs of the Wufeng-Longmaxi formatiosns, four typical shale gas wells at the depth of 2 000-6 000 m in the southeastern Sichuan exploration area were selected to systematically carry out a comparative study of deep and ultra-deep shale reservoir development characteristics and differences, and the causes of pore development were discussed. The results show that: (1) With a burial depth of less than 6 000 m, the shale reservoirs of the Wufeng-Longmaxi formations are effective reservoirs with high porosity, and the porosity has no obvious change with the change of burial depth. However, there are certain differences in the morphology, structure and connectivity of organic matter pores, that is, with the increase of burial depth, the size of organic matter pores relatively decreases, and the pore connectivity deteriorates; (2) It has been clarified that biogenic silica is the foundation of pore development, and fluid overpressure is the key to maintaining reservoir pores. Under the combined action of biogenic silica and biogenic silica, the deep and ultra-deep shale reservoirs with high porosity and high quality can be developed and maintained; (3) Based on the research of reservoir development, shale gas exploration will be extended to 6 000 m, which provides a clear direction for shale gas exploration in the next step. It is preliminarily assessed that the deep and ultra-deep shale gas (buried depth of 4 000-5 000 m) resources in the Wufeng-Longmaxi formations in the Sichuan Basin and its surrounding areas exceed 2×10¹² m³.

Characteristics of NE strike-slip fault system in the eastern section of Bachu-Maigaiti area, Tarim Basin and its oil-gas geological significance

ZHANG Zhongpei, XU Qinqi, LIU Shilin, ZHOU Yushuang, QIU Huabiao, LU Hongmei, WANG Hanzhou, QI Yukai

2023, 45(4): 761-769. doi: 10.11781/sysydz202304761

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Many Ordovician reservoirs discovered in the eastern section of Bachu-Maigaiti area ("Bamai area" for short) in the Tarim Basin are closely related to multi-stage active faults, making it the key to find oil and gas reservoirs in this area by identifying the source faults that cut through Cambrian gypsum-salt layers. Combined with the analysis of fault structure based on a large number of new seismic data and previous studies, the fault system in the eastern section of the Bamai area, especially the distribution and activity characteristics of strike slip faults are reunderstood. The results show that along with the migration and evolution of palaeo-uplift and the activities of large thrust fault zones in Bamai area, a series of high-angle and small-distance NE strike-slip faults that play a role of deformation and regulation are also developed, which together constitute the deformation tectonic system in the area. Two types of strike slip faults are developed in this area. One is superimposed and developed simultaneously or later with the NE and nearly EW Cambrian post-salt decollement zone of bruchfalten, with its strike consistent with that of the thrust fault belt, which is mainly distributed in the boundary and interior of the Hetian paleo-uplift. The other is developed in the compression-shortening zone confined by the large thrust fault belt, intersected with the nearly EW thrust fault belt at a large angle, and mainly distributed in the Hetian palaeo-uplift and Bachu faulted uplift. The former mainly formed in the late Hercynian period with weak local activities in the late Himalayan period, and the latter mainly formed in the late Himalayan period. The strike-slip faults superimposed with the Ordovician carbonate rocks that has experienced karst transformation in the middle and late Caledonian and early Hercynian are more conducive to the formation of effective fracture-karst vug reservoirs. They connect the upper and lower strata of the gypsum-salt layers, and their active period is consistent with the main hydrocarbon generation period of the deep subsalt source rocks, which is more conducive to transporting hydrocarbon source upward to the Ordovician system for accumulation. The large-scale reservoir located above the source and connected with two types of high-angle strike-slip faults is the favorable exploration direction of Ordovician.

Hydrothermal dissolution of deep-buried carbonate rocks and its significance for hydrocarbon exploration in Shunnan area, the Tarim Basin: taking well Peng-1 in Shunnan area as a case

HAN Jun, DONG Shaofeng, YOU Donghua, ZHANG Sheng, XIAO Chongyang, WANG Yingming

2023, 45(4): 770-779. doi: 10.11781/sysydz202304770

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In order to reveal the genetic mechanism of deep-buried carbonate reservoirs, a study was made based on well Peng-1 in Shunnan area of the Tarim Basin. The core section of well Peng-1 revealed that a large number of fractures and dissolution pores were developed in the carbonate rocks with buried depth of over 7 500 m. Based on detailed core observation and description, it was found that the dissolution pores were mainly distributed in the Upper Cambrian dolomites in the lower part of the core section and few in the Lower Ordovician carbonates in the upper part of the core section. The diameter of pores increases gradually with the increase of burial depth, which indicated that the pores were formed by infiltration of deep-seated hydrothermal fluids rather than meteoric water. The similar δ¹³C values and ⁸⁷Sr/⁸⁶Sr ratios of different types of minerals (including dolomite and calcite) with host rocks indicated that the diagenetic fluids inherited the geochemical characteristics of original sequestered pore water through intense water-rock action with the original carbonate rocks. However, the significantly negative δ¹⁸O values (with an average of -13.26 ‰) suggested that they were precipitated from fluids with high temperatures. This inference was verified by the results of fluid inclusion microthermometry, which confirmed that dolomite recrystallization and subsequent calcite precipitation were closely associated with fault-related deep-seated hydrothermal fluids. In addition, whole diameter CT scanning revealed that fractures can significantly improve the reservoir property and permeability of the dolomite formed by hydrothermal dolomitization. The permeability can be improved by at least one order of magnitude, i.e. from 0.02×10^-3 μm² to 0.39×10^-3 μm². Hydrothermal-related dolomite reservoirs may be extensively developed in the deep/ultra-deep buried carbonates in the Tarim Basin in view of the occurrence of such phenomenon in the well TS1 and Gucheng area. Thus, in the future hydrocarbon exploration in the Tarim Basin and elsewhere, hydrothermal-altered dolomite reservoirs deserve more attention.

Reservoir characteristics and main controlling factors of the fourth member of Ordovician Majiagou Formation in the central and eastern Ordos Basin

MOU Chunguo, XU Jie, GU Yonghong, JIA Jianpeng, WANG Wenxiong, TAN Xiucheng

2023, 45(4): 780-790. doi: 10.11781/sysydz202304780

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Recent exploration practice shows that the leopard porphyry dolomite reservoir in the fourth member of Ordovician Majiagou Formation in the central and eastern Ordos Basin has good exploration and development potential. Therefore, based on drilling cores, rock slices and analysis and laboratory data, the reservoir characteristics and main controlling factors of this section were analyzed. The results show that: (1) The reservoir rocks of the fourth member of Majiagou Formation mainly include leopard porphyry dolomitic limestone, leopard porphyry limy dolomite, crystalline dolomite and clotted dolomite, and the reservoir space types mainly consist of intergranular (dissolution) pores, with a small amount of lattice pores and microcracks. (2) The reservoir in the study area is generally characte-rized by low porosity and medium-low permeability pore type reservoir, in which leopard porphyry limestone dolomite and crystalline dolomite are the best reservoir rocks with wide distribution range. However, leopard porphyry dolomitic limestone is developed on a large scale, with poor reservoir performance as a whole, while clotted dolomite has good reservoir performance, but its development frequency is low. The reservoir development in the fourth member of Majiagou Formation in the central and eastern Ordos Basin is mainly controlled by sedimentary microfacies, bioturbation, dolomitization and early diagenetic karstification: as the material basis for reservoir formation, favorable sedimentary microfacies control the horizontal distribution of reservoirs; bioturbation is for dolomitization; dolomitization is the key to reservoir formation, which is conducive to the preservation of reservoir pores; early diagenetic karstification has an important contribution to the improvement of reservoir quality. In the longitudinal, the favorable reservoirs in the fourth member of Majiagou Formation are mainly located in the middle-upper part of the high-frequency upward shallowing sequence; on the plane, the favorable reservoirs are mainly concentrated in the line of Wushen Banner-Jingbian-Zhidan in the west and the two relatively independent areas of Shenmu and Mizhi in the east of the study area.

Determination of geological evaluation parameters for profitable development of Chang 8 tight oil reservoir in Honghe oil field, Ordos Basin

HE Chenyu, LIU Liqiong, XIAO Yuru, HUANG Xuebin, LI Shu

2023, 45(4): 791-796. doi: 10.11781/sysydz202304791

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Due to the high cost for exploration and development of tight oil reservoirs, it is an urgent problem to achieve profitable development of tight oil. According to the characteristics of tight oil reservoir in the eighth member of Triassic Yanchang Formation (Chang 8) in Honghe oil field, Ordos Basin, this paper highlighted single well information, started with the key parameters affecting the economic benefit of tight reservoir-single well economically recoverable reserves, and established a series of determination methods and process of geological evaluation parameters for profitable development of tight oil reservoirs based on single well economically recoverable reserves. Considering the particularity that the single well recoverable reserves of Chang 8 tight oil reservoir in Honghe oil field was controlled by fractures, the fracture development degree was added in the study of determination of the geological evaluation parameters. Five parameters, including single well technically recoverable reserves, net pay thickness, effective porosity, oil saturation and fracture development degree, were selected for classification and subdivided into six types. By compiling the intersection diagram of single well technically recoverable reserves and net pay thickness, the cutoffs of geological parameters were determined comprehensively by comparing the economic cutoffs and the classification of reservoir geological parameters under two scenarios. The method was applied to Chang 8 reservoir in Honghe oil field, and its feasibility was verified. The practical application shows that this method can provide effective technical support for sweet spot screening and development and deployment optimization in tight reservoirs.

Hydrocarbon charging stage and accumulation mode of forward fault step zone in fault basin: taking the Chengbei fault step zone in Qikou Sag, Bohai Bay Basin as an example

WEN Fan, LUO Qun, DONG Xiongying, QIU Zhaoxuan, HE Xiaobiao, WANG Shichen, ZHANG Hongli, ZHANG Zeyuan

2023, 45(4): 797-808. doi: 10.11781/sysydz202304797

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Fault step zones are well developed in faulted lake basins in the eastern part of China, among which, forward fault step zones account for a large proportion, and their spatiotemporal configuration relationship, oil and gas accumulation periods and accumulation conditions, which play a key role in the geological evaluation of regional oil and gas exploration, are difficult to study. In order to further clarify its hydrocarbon accumulation mode and filling period, the authors, by taking the Paleogene Dongying and Shahejie formations in the study area as the main target layers, and selecting wells Qidong 3-1, Zhang 10 and Chenghai 16 to represent the low, medium and high fault levels of the fault area, respectively, conducted in-depth research on the oil and gas properties and distribution laws of different charging stages in various districts of Chengbei through reservoir microlithography observation, fluid inclusion identification, salt water inclusion homogenization temperature and salinity test, GOI statistical analysis and other technologies; applied laser Raman test to effectively identify the gas composition of single inclusions in wells Zhang-10 and Qidong 3-1, determined the specific oil and gas accumulation time in Chengbei fault step zone in combination with the single well burial history, paleogeothermal history and autoclastic illite K-Ar isotopic dating technology of well Qidong 3-1, and summarized the four accumulation elements of source rocks, reservoirs, preservation and transportation in Chengbei area. There are two charging stages in the reservoir, the specific accumulation time of the first stage is from the end of Dongying to the early stage of Guantao, about 16 Ma ±, while that of the second stage is in the early stage of Minghua Town, starting from 6 Ma ± and continuing to the present. Multiple sets of reservoir layers are developed in the study area, and the special fault step structure plays a controlling role in channeling the source rocks and reservoirs, the sealing and preservation of oil and gas, and the transportation and accumulation of reservoirs. The regional accumulation conditions are relatively mature, and the lateral migration-accumulation mode of dual-source hydrocarbon supply and multi-stage accumulation and the longitudinal migration-accumulation mode of fault-sand coupling and relay climbing are reflected in the process of oil and gas accumulation.

Geochemical characteristics and genesis of Paleozoic natural gas in the Ordos Basin

LI Furong, LIU Wenhui, WANG Xiaofeng, ZHANG Dongdong, LUO Houyong, CHEN Xiaoyan, LI Fuqi, ZHANG Wen

2023, 45(4): 809-820. doi: 10.11781/sysydz202304809

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The geochemical characteristics and genesis of Paleozoic natural gas in the Ordos Basin are complex, with some disputes on the gas source of Lower Paleozoic. In order to better grasp the overall geochemical characteristics and variation laws of Paleozoic natural gas in the basin, the geochemical data of more than 700 natural gas samples from the whole basin are comprehensively analyzed based on the systematic collection, collation and analysis of previous data, and the genesis of natural gas is explored by combining the analysis of key elements such as natural gas formation, hydrocarbon formation and reservoir formation. The results show that the main body of Upper Paleozoic natural gas is coal-based gas controlled by maturity, with maturity increasing from northeast to southwest, and the southern part of the basin has a mixture of Upper and Lower Paleozoic gas. The Lower Paleozoic gas is dominated by oil-type gas from marine carbonate formations, of which the upper combination is characterized by a two-source composite reservoir of Upper Paleozoic coal-type gas and Lower Paleozoic oil-type gas; the middle-lower combination is a relatively independent oil-type gas reservoir, subject to different degrees of secondary transformation based on geological conditions and the degree of thermal evolution of organic matter, resulting in significant anomalies in its carbon isotope composition. The research has proved that marine hydrocarbon sources including carbonate rocks exist in the Lower Paleozoic of the basin, and the natural gas in the Upper and Lower Paleozoic has mixed to varying degrees in different locations of the basin.

Nuclear magnetic resonance core analysis technology

2023, 45(4): 821-821.

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2023 Vol. 45, No. 4

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