The Qiongdongnan Basin at the northern margin of the South China Sea shows distinct lateral variations in trends, deformational styles, and structural complexities from the western to the eastern zones. It is widely accepted that the western zone undergoes orthogonal stretching, whereas the eastern zone undergoes oblique stretching under the control of preexisting structures with changed orientation. In addition, the weak lower crust may affect the structural segmentation of the Qiongdongnan Basin. This study considers factors related to crustal strength, such as brittle-to-viscous thickness ratios and extensional velocities to explore the structural segmentation between the western and eastern zones using physical analogue modeling. The results show that the control of preexisting velocity discontinuity (VD) in the segmentation of the overlying structure is strongly associated with these two factors. In the case of a thinner lower crust or fast extension, deformation was concentrated along the VD, showing an apparent segmentation between the orthogonal and oblique zones. Conversely, when there was a thicker weak lower crust or slow velocity, the rift basin discrete development due to the control of preexisting VD weakened, and the segmentation was indistinct. A model with a thinner lower crust and faster stretching velocity successfully accounted for the observed segmentation characteristics of the Qiongdongnan Basin. Based on the experimental results, we explain the differential tectonic evolution between the eastern and western zones and their impact on the structurally formed reservoirs in the Qiongdongnan Basin.
{"title":"Structural segmentation in the Qiongdongnan Basin, South China Sea: Insights from analogue models and implications for hydrocarbon exploration","authors":"Gengxiong Yang, Hongwei Yin, Jun Gan, Wei Wang, Jitian Zhu, Dong Jia, Xiaofeng Xiong, Wenqiao Xu","doi":"10.1306/01162422069","DOIUrl":"https://doi.org/10.1306/01162422069","url":null,"abstract":"The Qiongdongnan Basin at the northern margin of the South China Sea shows distinct lateral variations in trends, deformational styles, and structural complexities from the western to the eastern zones. It is widely accepted that the western zone undergoes orthogonal stretching, whereas the eastern zone undergoes oblique stretching under the control of preexisting structures with changed orientation. In addition, the weak lower crust may affect the structural segmentation of the Qiongdongnan Basin. This study considers factors related to crustal strength, such as brittle-to-viscous thickness ratios and extensional velocities to explore the structural segmentation between the western and eastern zones using physical analogue modeling. The results show that the control of preexisting velocity discontinuity (VD) in the segmentation of the overlying structure is strongly associated with these two factors. In the case of a thinner lower crust or fast extension, deformation was concentrated along the VD, showing an apparent segmentation between the orthogonal and oblique zones. Conversely, when there was a thicker weak lower crust or slow velocity, the rift basin discrete development due to the control of preexisting VD weakened, and the segmentation was indistinct. A model with a thinner lower crust and faster stretching velocity successfully accounted for the observed segmentation characteristics of the Qiongdongnan Basin. Based on the experimental results, we explain the differential tectonic evolution between the eastern and western zones and their impact on the structurally formed reservoirs in the Qiongdongnan Basin.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140623000","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shugen Liu, Bin Deng, Zeqi Li, Wei Sun, Juan Wu, Chao Luo, Yong Zhong, Xiao Liang, Zhiwu Li, Jinming Song, Pengda Lu, Tengzeng Tian, Luba Jansa
In the Sichuan Basin there is abundant evidence in the lower Cambrian Qiongzhusi Formation and Ediacaran (upper Sinian) Dengying Formation for the existence of the oldest petroleum system in China. Here, we discuss the essential elements of the petroleum system—source rock in the Qiongzhusi Formation and reservoir rock in the Dengying Formation. The source rock in the Qiongzhusi Formation was deposited in a shelf-like marine environment. More than 100 m (328 ft) of black shale was deposited in the north-south–striking Mianyang-Changning intracratonic sag. The reservoir rock is composed of dolomitic algal mound-facies in the Dengying Formation. In the outcrop, the presence of dissolution features (vugs and caverns) and geochemical results indicates freshwater karstification during early diagenesis with subsequent hydrocarbon charge. Generated hydrocarbons underwent two distinct phases of evolution from oil generation and migration during the Permian to thermal cracking to gas beginning in the Late Triassic. Thus, the oldest petroleum system in the Sichuan Basin is characterized by paleo-oil and paleogas fields and present-day gas fields, all closely controlled by the tectonic evolution of the Sichuan Basin. The development of the intracratonic sag in the basin center controlled deposition and preservation of the high-quality source rock and highly efficient hydrocarbon transformation and expulsion. The development of the Ordovician–Jurassic Leshan-Longnvsi paleouplift in the basin center focused hydrocarbon migration to charge the paleo-oil and paleogas fields. Lateral and vertical migration of hydrocarbons was facilitated along unconformities and faults in upper Sinian and lower Cambrian strata across the Sichuan Basin—in particular, the Weiyuan gas field.
{"title":"The Qiongzhusi-Dengying petroleum system in the Sichuan Basin, China","authors":"Shugen Liu, Bin Deng, Zeqi Li, Wei Sun, Juan Wu, Chao Luo, Yong Zhong, Xiao Liang, Zhiwu Li, Jinming Song, Pengda Lu, Tengzeng Tian, Luba Jansa","doi":"10.1306/12052321155","DOIUrl":"https://doi.org/10.1306/12052321155","url":null,"abstract":"In the Sichuan Basin there is abundant evidence in the lower Cambrian Qiongzhusi Formation and Ediacaran (upper Sinian) Dengying Formation for the existence of the oldest petroleum system in China. Here, we discuss the essential elements of the petroleum system—source rock in the Qiongzhusi Formation and reservoir rock in the Dengying Formation. The source rock in the Qiongzhusi Formation was deposited in a shelf-like marine environment. More than 100 m (328 ft) of black shale was deposited in the north-south–striking Mianyang-Changning intracratonic sag. The reservoir rock is composed of dolomitic algal mound-facies in the Dengying Formation. In the outcrop, the presence of dissolution features (vugs and caverns) and geochemical results indicates freshwater karstification during early diagenesis with subsequent hydrocarbon charge. Generated hydrocarbons underwent two distinct phases of evolution from oil generation and migration during the Permian to thermal cracking to gas beginning in the Late Triassic. Thus, the oldest petroleum system in the Sichuan Basin is characterized by paleo-oil and paleogas fields and present-day gas fields, all closely controlled by the tectonic evolution of the Sichuan Basin. The development of the intracratonic sag in the basin center controlled deposition and preservation of the high-quality source rock and highly efficient hydrocarbon transformation and expulsion. The development of the Ordovician–Jurassic Leshan-Longnvsi paleouplift in the basin center focused hydrocarbon migration to charge the paleo-oil and paleogas fields. Lateral and vertical migration of hydrocarbons was facilitated along unconformities and faults in upper Sinian and lower Cambrian strata across the Sichuan Basin—in particular, the Weiyuan gas field.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140169080","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Di Xiao, Yu Yang, Long Wen, Benjian Zhang, Ran Liu, Ya Li, Xiucheng Tan, Jian Cao
Large-scale hydrocarbon accumulations have rarely been found in volcanic reservoirs around the world. This study documents large gas accumulations in Permian reservoirs in two areas of the Sichuan Basin, southwestern China, that include the deepest (>5000 m) volcanic reservoirs yet identified worldwide. Petroleum system elements differ in these deep volcanic accumulations between the Jianyang and Zhougongshan areas within the basin. In the Jianyang area, natural gas was derived mainly by the cracking of oil from Cambrian source rocks. Accumulations are overpressured stratigraphic traps spatially controlled by the distribution of a welded tuff reservoir with high porosity and high permeability. In contrast, low-porosity and low-permeability welded lapilli tuff and welded breccia reservoirs have lower gas saturations and are not productive. In the shallower Zhougongshan area, gas was generated by the cracking of kerogen in middle Permian source rocks. Regional tectonism formed normally pressured structural traps in fractured basaltic reservoirs. Multistage tectonism likely breached seals and allowed oil and gas to escape, reducing the scale of the accumulations in this area. Key factors influencing the large-scale accumulation and preservation of natural gas in the study area include development and preservation of adequate reservoir quality as well as tectonic history favorable to maintain seal integrity in brittle rocks. Our results provide guidance for the exploration for similar reservoirs in other areas.
{"title":"Petroleum system evaluation of the world’s deepest (>5000 m) volcanic reservoirs, Sichuan Basin, China","authors":"Di Xiao, Yu Yang, Long Wen, Benjian Zhang, Ran Liu, Ya Li, Xiucheng Tan, Jian Cao","doi":"10.1306/12152322045","DOIUrl":"https://doi.org/10.1306/12152322045","url":null,"abstract":"Large-scale hydrocarbon accumulations have rarely been found in volcanic reservoirs around the world. This study documents large gas accumulations in Permian reservoirs in two areas of the Sichuan Basin, southwestern China, that include the deepest (>5000 m) volcanic reservoirs yet identified worldwide. Petroleum system elements differ in these deep volcanic accumulations between the Jianyang and Zhougongshan areas within the basin. In the Jianyang area, natural gas was derived mainly by the cracking of oil from Cambrian source rocks. Accumulations are overpressured stratigraphic traps spatially controlled by the distribution of a welded tuff reservoir with high porosity and high permeability. In contrast, low-porosity and low-permeability welded lapilli tuff and welded breccia reservoirs have lower gas saturations and are not productive. In the shallower Zhougongshan area, gas was generated by the cracking of kerogen in middle Permian source rocks. Regional tectonism formed normally pressured structural traps in fractured basaltic reservoirs. Multistage tectonism likely breached seals and allowed oil and gas to escape, reducing the scale of the accumulations in this area. Key factors influencing the large-scale accumulation and preservation of natural gas in the study area include development and preservation of adequate reservoir quality as well as tectonic history favorable to maintain seal integrity in brittle rocks. Our results provide guidance for the exploration for similar reservoirs in other areas.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140205732","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The adjustment of organic matter (OM) molecular structure due to graphitization should be of great significance to the evolution and preservation of OM pores at an extremely high maturity stage. In this study, the lower Paleozoic Silurian Longmaxi contact metamorphic shales from the north section of the Xuefeng Mountain tectonic zone of the South China block were taken as an example and the molecular structure of kerogen in these postmature Longmaxi shales was analyzed using laser Raman microprobe, transmission electron microscopy, and Fourier transform infrared spectroscopy techniques. The OM pore structures of shale samples with different thermal maturity were compared using CO2/N2 adsorption and field emission scanning electron microscopy analysis. The results indicate that postmature kerogens have entered the transition stage from amorphous carbon to crystallized graphite. The orderliness and crystallinity of carbon atom layers in these postmature samples continuously increase with maturity, accompanied by decreased disordered graphite lattice. The minimum d (Å) value of carbon layers is close to 0.335 nm, indicating that the kerogens have partially reached the ideal graphite state. Around or between clay platelets, OM develops numerous bubble pores that have diameters of 50 to 200 nm, displaying high plane porosity and multilayer superposition. This OM type has morphological characteristics resembling artificial porous graphite. The OM porosity contributes significantly to the total porosity, and decreases with progressing graphitization. The thermodynamic stability of OM allows homogenization of pores after graphitization, as heterogeneity decreases and orderliness increases. However, graphitization could reduce the compressive capacity of pores, which is not conducive to OM pore preservation.
石墨化引起的有机质（OM）分子结构的调整，对OM孔隙在极高成熟阶段的演化和保存具有重要意义。本研究以华南地块雪峰山构造带北段下古生界志留系龙马溪接触变质页岩为例，采用激光拉曼微探针、透射电镜和傅立叶变换红外光谱技术分析了这些后成熟龙马溪页岩中的角质分子结构。利用 CO2/N2 吸附和场发射扫描电子显微镜分析比较了不同热成熟度页岩样品的 OM 孔隙结构。结果表明，后成熟角砾岩已进入从无定形碳到结晶石墨的过渡阶段。这些成熟后样品中碳原子层的有序度和结晶度随着成熟度的提高而不断提高，同时石墨晶格的无序度也在降低。碳原子层的最小 d (Å) 值接近 0.335 nm，表明角砾岩已部分达到理想的石墨状态。在粘土小板周围或之间，OM 形成了许多直径为 50 至 200 nm 的气泡孔，显示出高平面孔隙率和多层叠加。这种 OM 具有类似人造多孔石墨的形态特征。OM 孔隙率在总孔隙率中占很大比例，并随着石墨化的进展而降低。OM 的热力学稳定性使其在石墨化后孔隙趋于均匀，异质性降低，有序性提高。然而，石墨化会降低孔隙的抗压能力，不利于 OM 孔隙的保存。
{"title":"Molecular structure characterization of kerogen in contact metamorphic shales: Insights into the effect of graphitization on organic matter pores","authors":"Yuguang Hou, Rui Yu, Junjie Li, Zhenhong Chen, Cheng Wang, Xianglin Chen, Rui Yang, Sheng He","doi":"10.1306/11152322157","DOIUrl":"https://doi.org/10.1306/11152322157","url":null,"abstract":"The adjustment of organic matter (OM) molecular structure due to graphitization should be of great significance to the evolution and preservation of OM pores at an extremely high maturity stage. In this study, the lower Paleozoic Silurian Longmaxi contact metamorphic shales from the north section of the Xuefeng Mountain tectonic zone of the South China block were taken as an example and the molecular structure of kerogen in these postmature Longmaxi shales was analyzed using laser Raman microprobe, transmission electron microscopy, and Fourier transform infrared spectroscopy techniques. The OM pore structures of shale samples with different thermal maturity were compared using CO2/N2 adsorption and field emission scanning electron microscopy analysis. The results indicate that postmature kerogens have entered the transition stage from amorphous carbon to crystallized graphite. The orderliness and crystallinity of carbon atom layers in these postmature samples continuously increase with maturity, accompanied by decreased disordered graphite lattice. The minimum d (Å) value of carbon layers is close to 0.335 nm, indicating that the kerogens have partially reached the ideal graphite state. Around or between clay platelets, OM develops numerous bubble pores that have diameters of 50 to 200 nm, displaying high plane porosity and multilayer superposition. This OM type has morphological characteristics resembling artificial porous graphite. The OM porosity contributes significantly to the total porosity, and decreases with progressing graphitization. The thermodynamic stability of OM allows homogenization of pores after graphitization, as heterogeneity decreases and orderliness increases. However, graphitization could reduce the compressive capacity of pores, which is not conducive to OM pore preservation.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140169032","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Considerable progress has been made in shale gas exploration and development in China. However, apart from the Wufeng–Longmaxi Formation shales in the Sichuan Basin, large-scale commercial exploitation of shale gas has not yet been achieved. Permian marine shales in the Lower Yangtze region have long been considered prospective targets for unconventional reservoirs, but few detailed evaluations of their source rock characteristics have been undertaken. Based on a geological survey of shale gas in this region, we used geological and geochemical data to undertake a comprehensive assessment of the source rock characteristics of the Permian shales in the Gufeng and Dalong Formations, and then evaluated their shale gas potential by comparing them with the world’s prolific shale gas plays. Both Gufeng and Dalong shales have good thicknesses (average = 43.50 m [143 ft] and 30.80 m [101 ft], respectively), high quartz contents (average = 51.42 and 31.96 vol. %), low clay contents (average = 32.16 and 36.23 vol. %), high organic matter contents (average = 4.07 and 3.27 wt. %), favorable kerogen types (II1 and II2), and suitable maturity (average = 1.61% and 1.52%). Both shales exhibit similar geological and geochemical characteristics to those of commercially developed shale gas systems. The calculated total gas in the shales is ∼93 BCF/section (1013 m3/m3) and 47 BCF/section (512 m3/m3), respectively. Therefore, the shales are good source rocks, with the Gufeng Formation having the better shale gas potential. In addition, lateral intrabasinal comparisons suggest the southern Anhui Province has better shale gas-prone source rock potential than the southern Jiangsu Province.
{"title":"Hydrocarbon source rock characteristics and shale gas potential of Permian marine shales in the Lower Yangtze region of South China","authors":"Bolin Zhang, Suping Yao, Wenxuan Hu, Yuyuan Wu, Wenduan Yu, Hao Yu","doi":"10.1306/12152322141","DOIUrl":"https://doi.org/10.1306/12152322141","url":null,"abstract":"Considerable progress has been made in shale gas exploration and development in China. However, apart from the Wufeng–Longmaxi Formation shales in the Sichuan Basin, large-scale commercial exploitation of shale gas has not yet been achieved. Permian marine shales in the Lower Yangtze region have long been considered prospective targets for unconventional reservoirs, but few detailed evaluations of their source rock characteristics have been undertaken. Based on a geological survey of shale gas in this region, we used geological and geochemical data to undertake a comprehensive assessment of the source rock characteristics of the Permian shales in the Gufeng and Dalong Formations, and then evaluated their shale gas potential by comparing them with the world’s prolific shale gas plays. Both Gufeng and Dalong shales have good thicknesses (average = 43.50 m [143 ft] and 30.80 m [101 ft], respectively), high quartz contents (average = 51.42 and 31.96 vol. %), low clay contents (average = 32.16 and 36.23 vol. %), high organic matter contents (average = 4.07 and 3.27 wt. %), favorable kerogen types (II1 and II2), and suitable maturity (average = 1.61% and 1.52%). Both shales exhibit similar geological and geochemical characteristics to those of commercially developed shale gas systems. The calculated total gas in the shales is ∼93 BCF/section (1013 m3/m3) and 47 BCF/section (512 m3/m3), respectively. Therefore, the shales are good source rocks, with the Gufeng Formation having the better shale gas potential. In addition, lateral intrabasinal comparisons suggest the southern Anhui Province has better shale gas-prone source rock potential than the southern Jiangsu Province.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140196466","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Tight sandstone oil is currently one of the most important unconventional hydrocarbon resources in China. The coupling relationship between porosity evolution and oil emplacement determines the reservoir effectiveness and oil exploration potential in tight sandstones. Complex diagenetic alterations, however, make research on porosity evolution much more difficult than that on conventional sandstone reservoirs. This study examines the typical lacustrine tight sandstones from western to eastern China. The reservoir lithologies, characteristics, and paragenetic sequences of the diagenesis are reviewed, and an integrated analysis of diagenesis, porosity evolution, and oil emplacement is proposed.Results demonstrate that diagenesis is influenced by rock composition and lithological associations. For example, calcite cementation is primarily controlled by the distance to the sandstone–mudstone interface, whereas zeolite cements are related to volcanic rock fragments. Furthermore, we established a porosity evolution recovery method with respect to the paleoburial depth (or time) of major diagenetic events, including the evaluation of the relationship between the thin section and helium porosity and oil emplacement. We clarified the formation time and the underlying mechanisms. Three typical examples from the major oil-bearing basins in China were chosen to analyze the integration process of diagenesis, the porosity evolution of tight sandstones, as well as the coupling relationship between porosity evolution and oil emplacement. Tight sandstones characterized by different diagenetic alterations exhibit different coupling relationships between porosity evolution and oil emplacement. Our study can provide important guidance for reservoir quality prediction and oil exploration potential evaluation.
{"title":"Integration of diagenesis, porosity evolution, and oil emplacement in lacustrine tight sandstone reservoirs: A review with illustrative cases from the major oil-bearing basins in China","authors":"Kelai Xi, Yingchang Cao, Rukai Zhu, Honggang Xin, Weidong Dan, Helge Hellevang","doi":"10.1306/12212322063","DOIUrl":"https://doi.org/10.1306/12212322063","url":null,"abstract":"Tight sandstone oil is currently one of the most important unconventional hydrocarbon resources in China. The coupling relationship between porosity evolution and oil emplacement determines the reservoir effectiveness and oil exploration potential in tight sandstones. Complex diagenetic alterations, however, make research on porosity evolution much more difficult than that on conventional sandstone reservoirs. This study examines the typical lacustrine tight sandstones from western to eastern China. The reservoir lithologies, characteristics, and paragenetic sequences of the diagenesis are reviewed, and an integrated analysis of diagenesis, porosity evolution, and oil emplacement is proposed.Results demonstrate that diagenesis is influenced by rock composition and lithological associations. For example, calcite cementation is primarily controlled by the distance to the sandstone–mudstone interface, whereas zeolite cements are related to volcanic rock fragments. Furthermore, we established a porosity evolution recovery method with respect to the paleoburial depth (or time) of major diagenetic events, including the evaluation of the relationship between the thin section and helium porosity and oil emplacement. We clarified the formation time and the underlying mechanisms. Three typical examples from the major oil-bearing basins in China were chosen to analyze the integration process of diagenesis, the porosity evolution of tight sandstones, as well as the coupling relationship between porosity evolution and oil emplacement. Tight sandstones characterized by different diagenetic alterations exhibit different coupling relationships between porosity evolution and oil emplacement. Our study can provide important guidance for reservoir quality prediction and oil exploration potential evaluation.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140196734","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wei Wang, Hongwei Yin, Huiwen Xie, Dong Jia, Bin Wang, Gengxiong Yang, Haoyu Luo
The Hetianhe–Madong region of the southwestern Tarim Basin contains two thrust systems: the Cenozoic Mazhatage thrust belt in the northwest and the Paleozoic Madong fold-thrust belt in the southeast. The two structural belts have almost vertical propagation directions of deformation and abut in a narrow interaction zone between them. Proven hydrocarbons are closely related to the structural deformation experienced in this region and restricted along the fault system of the Mazhatage structure and the narrow interaction zone. Based on seismic interpretations and analogue modeling, structural models were constructed in this study for the two thrust systems and the interaction zone. Then, the controlling factors of the restricted distribution of hydrocarbon plays are discussed. The results suggest that the Mazhatage structure is a basement-controlled structure, whereas the Madong fold-thrust belt reflects a thin-skinned structural style with a middle Cambrian salt as the detachment layer. The interaction zone is controlled by a strike-slip fault, and the preexisting structures and the salt layer affect its structural geometry. The basement-continued thrust fault and the strike-slip fault of the interaction zone cut through the salt layer, providing conduits for hydrocarbons from subsalt source rocks to suprasalt traps, explaining the restricted hydrocarbon distribution in the Hetianhe–Madong region. This study provides insight into regions undergoing multiphase deformation and its control on hydrocarbon distribution. The results may be helpful for understanding such structures.
{"title":"Multiphase deformation and its impacts on hydrocarbon distribution in the Hetianhe–Madong region, southwestern Tarim Basin","authors":"Wei Wang, Hongwei Yin, Huiwen Xie, Dong Jia, Bin Wang, Gengxiong Yang, Haoyu Luo","doi":"10.1306/05032321079","DOIUrl":"https://doi.org/10.1306/05032321079","url":null,"abstract":"The Hetianhe–Madong region of the southwestern Tarim Basin contains two thrust systems: the Cenozoic Mazhatage thrust belt in the northwest and the Paleozoic Madong fold-thrust belt in the southeast. The two structural belts have almost vertical propagation directions of deformation and abut in a narrow interaction zone between them. Proven hydrocarbons are closely related to the structural deformation experienced in this region and restricted along the fault system of the Mazhatage structure and the narrow interaction zone. Based on seismic interpretations and analogue modeling, structural models were constructed in this study for the two thrust systems and the interaction zone. Then, the controlling factors of the restricted distribution of hydrocarbon plays are discussed. The results suggest that the Mazhatage structure is a basement-controlled structure, whereas the Madong fold-thrust belt reflects a thin-skinned structural style with a middle Cambrian salt as the detachment layer. The interaction zone is controlled by a strike-slip fault, and the preexisting structures and the salt layer affect its structural geometry. The basement-continued thrust fault and the strike-slip fault of the interaction zone cut through the salt layer, providing conduits for hydrocarbons from subsalt source rocks to suprasalt traps, explaining the restricted hydrocarbon distribution in the Hetianhe–Madong region. This study provides insight into regions undergoing multiphase deformation and its control on hydrocarbon distribution. The results may be helpful for understanding such structures.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140196672","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Practically quantifying gas-in-place content in organic matter (OM)–hosted and mineral-hosted pores is essential to understanding shale gas storage and recovery mechanism, and this remains challenging by conventional methods. This study obtained different porosity type and pore size distribution by integrating scanning electron microscopy and helium ion microscopy image analysis and CO2 adsorption experiments. Based on detailed porosity data and a nonlinear multiple regression model of methane-adsorbed density, adsorbed- and free-gas content of OM-hosted pores and mineral-hosted pores were estimated for the most gas-productive marine Silurian Longmaxi shales in the Sichuan Basin, China. Results show that the gas-in-place volume of 14 wells with producing depths of 387 to 4334 m (1270 to 14,219 ft) ranges from 1.9 to 7.9 m3/t (67 to 279 SCF/ton), and OM is the main gas storage site. The total gas content increases first and then remains relatively stable at depths greater than 3500 m (11,482 ft). Compared to deep shales with free-gas percentages of more than 60%, the shallow shales especially lower than 500 m (1640 ft) are dominated by adsorbed gas. The depth-dependent gas-bearing properties are suggested to be coupling results of reservoir pressure conditions and pore characteristics by tectonic uplifts. The gas recovery across pore size at different production pressures was further estimated, and a higher ultimate production was found at higher depths. Our proposed model provides important insights for gas occurrence in nanopores, and it is significant for an accurate gas-in-place estimation and production prediction for deep shales.
{"title":"Gas-in-place prediction from quantifying organic matter– and mineral-hosted porosities in marine gas shales","authors":"Yingzhu Wang, Jijin Yang","doi":"10.1306/09212322099","DOIUrl":"https://doi.org/10.1306/09212322099","url":null,"abstract":"Practically quantifying gas-in-place content in organic matter (OM)–hosted and mineral-hosted pores is essential to understanding shale gas storage and recovery mechanism, and this remains challenging by conventional methods. This study obtained different porosity type and pore size distribution by integrating scanning electron microscopy and helium ion microscopy image analysis and CO2 adsorption experiments. Based on detailed porosity data and a nonlinear multiple regression model of methane-adsorbed density, adsorbed- and free-gas content of OM-hosted pores and mineral-hosted pores were estimated for the most gas-productive marine Silurian Longmaxi shales in the Sichuan Basin, China. Results show that the gas-in-place volume of 14 wells with producing depths of 387 to 4334 m (1270 to 14,219 ft) ranges from 1.9 to 7.9 m3/t (67 to 279 SCF/ton), and OM is the main gas storage site. The total gas content increases first and then remains relatively stable at depths greater than 3500 m (11,482 ft). Compared to deep shales with free-gas percentages of more than 60%, the shallow shales especially lower than 500 m (1640 ft) are dominated by adsorbed gas. The depth-dependent gas-bearing properties are suggested to be coupling results of reservoir pressure conditions and pore characteristics by tectonic uplifts. The gas recovery across pore size at different production pressures was further estimated, and a higher ultimate production was found at higher depths. Our proposed model provides important insights for gas occurrence in nanopores, and it is significant for an accurate gas-in-place estimation and production prediction for deep shales.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140196780","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Early Cretaceous Pettet Formation of east Texas, United States, was deposited as part of the giant Comanche carbonate platform of the northern Gulf of Mexico. It is largely characterized by shallow-water platform interior carbonates, including skeletal-oolitic shoals and muddy green algae-rich lagoons. The Pettet is broken up into four subunits (Pettet A, B, C, and D), each of which represents a high-frequency sequence. Within the framework of these sequences, mapping of distribution and thickness of skeletal-oolitic shoal intervals uncovers progradational and retrogradational patterns at a larger scale. These shoal intervals are the main hydrocarbon targets in the Pettet play. Integration of mapped shoal intervals with historic well production data from Rusk County, Texas, reveals that there are three main controls on productivity: (1) reservoir facies type, (2) diagenetic alteration, and (3) regional structure. Shoal-complex mixed skeletal-oolitic grainstones are shown to have significantly better reservoir quality than shoal-complex ooid grainstones and off-shoal packstone facies. Although the Pettet B and C shoal intervals are both widespread throughout Rusk County, the Pettet B is dominated by mixed skeletal-oolitic grainstones, whereas the Pettet C is ooid dominated. The Pettet B is also less diagenetically altered, with fewer late-stage pore-occluding calcite cements than the Pettet C; consequently, it is considered to be a better reservoir interval. Production data corroborate these findings and additionally show the influence of structure on hydrocarbon accumulations. The integrated data highlight the continued potential of the Pettet, both in terms of new exploration and existing wells that may bypass potential Pettet reservoirs.
美国得克萨斯州东部的早白垩世佩特地层沉积为墨西哥湾北部巨大的科曼奇碳酸盐平台的一部分。其主要特征是浅水平台内部的碳酸盐，包括骨骼-鲕粒浅滩和富含泥质绿藻的泻湖。佩特岩分为四个亚单元（佩特岩 A、B、C 和 D），每个亚单元代表一个高频序列。在这些序列的框架内，对骨架-橄榄岩滩涂间隙的分布和厚度进行测绘，揭示了更大范围内的顺向和逆向模式。这些浅滩层段是佩特油气区的主要油气目标。将绘制的滩状岩层间隔与得克萨斯州 Rusk 县的历史油井生产数据相结合，可以发现生产率主要受以下三个方面的控制：（1）储层面类型；（2）成岩蚀变；（3）区域构造。结果表明，浅滩复合混合骨架-橄榄岩晶粒岩的储层质量明显优于浅滩复合卵岩晶粒岩和浅滩外包裹岩面。虽然 Pettet B 和 C 浅滩层段都广泛分布于整个卢斯科县，但 Pettet B 以混合骨架-橄榄岩粒岩为主，而 Pettet C 则以类卵岩为主。与 Pettet C 相比，Pettet B 的成岩蚀变程度较低，后期孔隙闭锁方解石胶结物较少，因此被认为是一个较好的储层区间。生产数据证实了这些发现，并进一步显示了结构对油气积聚的影响。综合数据凸显了 Pettet 的持续潜力，包括新的勘探和可能绕过潜在 Pettet 储层的现有油井。
{"title":"Lithologic controls on reservoir quality and production trends in the Pettet Formation, Rusk County, east Texas","authors":"Kelly E. Hattori, Eric M. Radjef","doi":"10.1306/11022322150","DOIUrl":"https://doi.org/10.1306/11022322150","url":null,"abstract":"The Early Cretaceous Pettet Formation of east Texas, United States, was deposited as part of the giant Comanche carbonate platform of the northern Gulf of Mexico. It is largely characterized by shallow-water platform interior carbonates, including skeletal-oolitic shoals and muddy green algae-rich lagoons. The Pettet is broken up into four subunits (Pettet A, B, C, and D), each of which represents a high-frequency sequence. Within the framework of these sequences, mapping of distribution and thickness of skeletal-oolitic shoal intervals uncovers progradational and retrogradational patterns at a larger scale. These shoal intervals are the main hydrocarbon targets in the Pettet play. Integration of mapped shoal intervals with historic well production data from Rusk County, Texas, reveals that there are three main controls on productivity: (1) reservoir facies type, (2) diagenetic alteration, and (3) regional structure. Shoal-complex mixed skeletal-oolitic grainstones are shown to have significantly better reservoir quality than shoal-complex ooid grainstones and off-shoal packstone facies. Although the Pettet B and C shoal intervals are both widespread throughout Rusk County, the Pettet B is dominated by mixed skeletal-oolitic grainstones, whereas the Pettet C is ooid dominated. The Pettet B is also less diagenetically altered, with fewer late-stage pore-occluding calcite cements than the Pettet C; consequently, it is considered to be a better reservoir interval. Production data corroborate these findings and additionally show the influence of structure on hydrocarbon accumulations. The integrated data highlight the continued potential of the Pettet, both in terms of new exploration and existing wells that may bypass potential Pettet reservoirs.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139909972","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Daniela Becerra, Christopher R. Clarkson, Amin Ghanizadeh
Low-permeability (tight) siltstones and mudstones of the Montney Formation in western Canada are currently being exploited with multistage fractured horizontal wells. A significant challenge for development is effectively targeting zones for lateral placement and hydraulic fracture stimulation within the typically thick (up to 350 m) gross Montney interval. At the vertical resolution of common well-log suites, the Montney displays limited variability, with important centimeter-scale changes in petrophysical and geomechanical properties, which can affect reservoir quality, being undetectable.An unprecedented high-resolution data set consisting of elemental compositions (from x-ray fluorescence), permeability (using a profile permeameter), and rock hardness (using a microrebound hammer tool) was obtained from a continuous core (230 m) sampling of the entire Montney, as well as small intervals of the bounding formations. These nondestructive tests were collected on the slabbed core at 2.5-cm intervals (approximately 10,000 measurement points). Routine core data (porosity, permeability, etc.), collected sporadically throughout the 210-m interval covering the Montney portion of the core, and a conventional log suite were also available for comparison with the high-resolution data set.Vertical profiling results demonstrate that the entire Montney Formation (Lower and Middle Members) exhibits significant centimeter-scale heterogeneity. These members are easily distinguished with the high-resolution data set, and reservoir quality trends (as quantified with permeability and rock hardness) are similarly easily inferred. As a result, targets for horizontal lateral placement can be confidently selected. In addition, the high-resolution profiling method proposed herein may have important applications for simulating hydraulic fracture height growth and for selecting appropriate and representative samples (e.g., core plugs). For the former, low-hardness, organic-rich mudstone beds and weak interfaces with more competent rock could act to blunt hydraulic fracture growth. For the latter, the centimeter-scale resolution of profiling enables sampling of lithologies for which reservoir properties vary at the centimeter scale, which is not possible through well-log analysis.
{"title":"High-resolution petrophysical, geochemical, and geomechanical profiling of a 230-m continuous core from the Montney Formation, Canada","authors":"Daniela Becerra, Christopher R. Clarkson, Amin Ghanizadeh","doi":"10.1306/05032322095","DOIUrl":"https://doi.org/10.1306/05032322095","url":null,"abstract":"Low-permeability (tight) siltstones and mudstones of the Montney Formation in western Canada are currently being exploited with multistage fractured horizontal wells. A significant challenge for development is effectively targeting zones for lateral placement and hydraulic fracture stimulation within the typically thick (up to 350 m) gross Montney interval. At the vertical resolution of common well-log suites, the Montney displays limited variability, with important centimeter-scale changes in petrophysical and geomechanical properties, which can affect reservoir quality, being undetectable.An unprecedented high-resolution data set consisting of elemental compositions (from x-ray fluorescence), permeability (using a profile permeameter), and rock hardness (using a microrebound hammer tool) was obtained from a continuous core (230 m) sampling of the entire Montney, as well as small intervals of the bounding formations. These nondestructive tests were collected on the slabbed core at 2.5-cm intervals (approximately 10,000 measurement points). Routine core data (porosity, permeability, etc.), collected sporadically throughout the 210-m interval covering the Montney portion of the core, and a conventional log suite were also available for comparison with the high-resolution data set.Vertical profiling results demonstrate that the entire Montney Formation (Lower and Middle Members) exhibits significant centimeter-scale heterogeneity. These members are easily distinguished with the high-resolution data set, and reservoir quality trends (as quantified with permeability and rock hardness) are similarly easily inferred. As a result, targets for horizontal lateral placement can be confidently selected. In addition, the high-resolution profiling method proposed herein may have important applications for simulating hydraulic fracture height growth and for selecting appropriate and representative samples (e.g., core plugs). For the former, low-hardness, organic-rich mudstone beds and weak interfaces with more competent rock could act to blunt hydraulic fracture growth. For the latter, the centimeter-scale resolution of profiling enables sampling of lithologies for which reservoir properties vary at the centimeter scale, which is not possible through well-log analysis.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769909","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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