X. Wang, L. Pan, L. Li, H. C. Lau, M. Zhang, H. Wang, N. Cai
Natural fractures play an important role in the storage, migration, accumulation, and escape of hydrocarbons in shale reservoirs. They can also interact with hydraulic fractures to create an interconnected fracture network, thereby enhancing the productivity of the reservoir. Among various types of natural fractures in shale, subaqueous syneresis fractures are commonly observed. The identification of syneresis fractures can aid greatly in pinpointing the most favorable areas in shale reservoirs. In our study, we conducted experimental research to investigate the occurrence of syneresis fractures in a subaqueous environment, where the only influencing factors were the natural processes of mud deposition. Through analyzing fracture parameters, we found that subaqueous syneresis fractures can develop rapidly and extensively during mud subsidence, exhibiting a preference for specific regions. The key factor governing the formation of syneresis fractures is the dip angle of the underlying structure. Steeper dip angles tend to generate fractures with higher density, intensity, and fracturing degree. Furthermore, among underlying structures with the same dip angles, those with longer strike lines tend to form longer and wider fractures. In addition, the sediment composition plays a crucial role in generating more fractures. Although environmental temperature has a minor controlling influence, it leads to limited variations in subaqueous fracture development. Our findings provide efficient guidance for locating significant natural fractures in shale formation. Specifically, we propose that calcareous shale layers deposited on moderate to steeply dipping slopes with longer strike lines, under high depositional temperature, hold promise for developing extensive syneresis fractures. Such areas could serve as favorable zones for hydrocarbon accumulation, representing potential sweet spots in shale reservoirs.
{"title":"Locating massive syneresis fractures in shale: An experimental study","authors":"X. Wang, L. Pan, L. Li, H. C. Lau, M. Zhang, H. Wang, N. Cai","doi":"10.1306/03132418139","DOIUrl":"https://doi.org/10.1306/03132418139","url":null,"abstract":"Natural fractures play an important role in the storage, migration, accumulation, and escape of hydrocarbons in shale reservoirs. They can also interact with hydraulic fractures to create an interconnected fracture network, thereby enhancing the productivity of the reservoir. Among various types of natural fractures in shale, subaqueous syneresis fractures are commonly observed. The identification of syneresis fractures can aid greatly in pinpointing the most favorable areas in shale reservoirs. In our study, we conducted experimental research to investigate the occurrence of syneresis fractures in a subaqueous environment, where the only influencing factors were the natural processes of mud deposition. Through analyzing fracture parameters, we found that subaqueous syneresis fractures can develop rapidly and extensively during mud subsidence, exhibiting a preference for specific regions. The key factor governing the formation of syneresis fractures is the dip angle of the underlying structure. Steeper dip angles tend to generate fractures with higher density, intensity, and fracturing degree. Furthermore, among underlying structures with the same dip angles, those with longer strike lines tend to form longer and wider fractures. In addition, the sediment composition plays a crucial role in generating more fractures. Although environmental temperature has a minor controlling influence, it leads to limited variations in subaqueous fracture development. Our findings provide efficient guidance for locating significant natural fractures in shale formation. Specifically, we propose that calcareous shale layers deposited on moderate to steeply dipping slopes with longer strike lines, under high depositional temperature, hold promise for developing extensive syneresis fractures. Such areas could serve as favorable zones for hydrocarbon accumulation, representing potential sweet spots in shale reservoirs.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"67 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141170780","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 Tuscaloosa marine shale is an unconventional play whose core area is located in southwestern Mississippi and southeastern Louisiana. Its significance to the energy industry stems from its large oil and gas resources of approximately 1.5 billion bbl of oil (238.5 million m3 of oil) and 4.6 TCF of gas (1.29 billion m3 of gas) and proximity to existing infrastructure. Despite more than 80 wells being hydraulically fractured in the formation, resulting in a total of 13.82 million bbl of oil and 9.04 BCF of gas, challenges remain due to the shale’s high clay content and diverse mineral makeup. Besides, a well-developed network of natural fractures exists across the play, and its effect on hydrocarbon production is yet to be fully understood. This study uses an integrated approach to the characterization of natural fractures in the Tuscaloosa marine shale, incorporating electrical borehole image logs, shear-wave splitting data, and core descriptions from seven wells across the formation. The results show that the identified natural fractures are vertical and subvertical extension fractures, which can be fully mineralized and have heights between 1 and 3 ft (0.31 and 0.91 m). These fractures occur along the east-west direction, are associated with calcite-rich strata, and are capable of transecting the whole borehole. Smaller fractures terminate due to changes in lithology but commonly reactivate in parallel planes. The proposed methodology can help maximize hydraulic fracturing performance across the shale play by identifying stress direction and optimum lateral placement with respect to fracture location. A total of 500 closed fractures are identified in the lateral section of one well. It is also shown that the maximum horizontal stress orientation is consistent throughout the formation and adheres to the general stress trend in the Gulf Coast Basin.
{"title":"Natural fractures of the Tuscaloosa marine shale","authors":"Cristina Mariana Ruse, Mehdi Mokhtari","doi":"10.1306/03052423020","DOIUrl":"https://doi.org/10.1306/03052423020","url":null,"abstract":"The Tuscaloosa marine shale is an unconventional play whose core area is located in southwestern Mississippi and southeastern Louisiana. Its significance to the energy industry stems from its large oil and gas resources of approximately 1.5 billion bbl of oil (238.5 million m3 of oil) and 4.6 TCF of gas (1.29 billion m3 of gas) and proximity to existing infrastructure. Despite more than 80 wells being hydraulically fractured in the formation, resulting in a total of 13.82 million bbl of oil and 9.04 BCF of gas, challenges remain due to the shale’s high clay content and diverse mineral makeup. Besides, a well-developed network of natural fractures exists across the play, and its effect on hydrocarbon production is yet to be fully understood. This study uses an integrated approach to the characterization of natural fractures in the Tuscaloosa marine shale, incorporating electrical borehole image logs, shear-wave splitting data, and core descriptions from seven wells across the formation. The results show that the identified natural fractures are vertical and subvertical extension fractures, which can be fully mineralized and have heights between 1 and 3 ft (0.31 and 0.91 m). These fractures occur along the east-west direction, are associated with calcite-rich strata, and are capable of transecting the whole borehole. Smaller fractures terminate due to changes in lithology but commonly reactivate in parallel planes. The proposed methodology can help maximize hydraulic fracturing performance across the shale play by identifying stress direction and optimum lateral placement with respect to fracture location. A total of 500 closed fractures are identified in the lateral section of one well. It is also shown that the maximum horizontal stress orientation is consistent throughout the formation and adheres to the general stress trend in the Gulf Coast Basin.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"49 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141170718","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}
Porosity determines the storage capacity of shale reservoirs and is of great significance for evaluating shale gas resources and production. However, compared with commercially developed marine shales, paralic shales contain different organic matter types, mineralogical compositions, and microstructures. Moreover, a systematic understanding of the pore evolution mechanisms in paralic shales is lacking. Thus, we selected the overmature upper Permian Longtan Formation in northern Guizhou Province, southwestern China, as an example to investigate the pore characteristics and evolution mechanisms in paralic shales. Reflected-light microscopy with oil immersion combined with scanning electron microscopy observations confirmed that the macerals of the Longtan shales are composed mainly of vitrinite and pyrobitumen, followed by inertinite. The pore types can be divided into organic matter pores and mineral matrix pores. Organic matter pores include primary organic matter pores and secondary organic matter pores. Mineral matrix pores include intergranular and intragranular pores. Intragranular pores can be further divided into intraplatelet pores within clay aggregates, intercrystalline pores, and dissolution pores. Mesopores and macropores provide most of the total pore volume, whereas micropores provide most of the total surface area. Total organic carbon content is the main factor controlling the pore development, and the contribution of clay minerals to porosity is still questionable. The maceral types and thermal evolution are of great significance to the development of organic matter pores in paralic shales. The primary composition and diagenetic modifications of the identified four major shale lithofacies are different, and therefore, result in various pore networks of each lithofacies.
{"title":"Pore characteristics and evolution mechanisms of paralic shales from the Upper Permian Longtan Formation, southwestern China","authors":"Qing He, Tian Dong, Sheng He","doi":"10.1306/02132422108","DOIUrl":"https://doi.org/10.1306/02132422108","url":null,"abstract":"Porosity determines the storage capacity of shale reservoirs and is of great significance for evaluating shale gas resources and production. However, compared with commercially developed marine shales, paralic shales contain different organic matter types, mineralogical compositions, and microstructures. Moreover, a systematic understanding of the pore evolution mechanisms in paralic shales is lacking. Thus, we selected the overmature upper Permian Longtan Formation in northern Guizhou Province, southwestern China, as an example to investigate the pore characteristics and evolution mechanisms in paralic shales. Reflected-light microscopy with oil immersion combined with scanning electron microscopy observations confirmed that the macerals of the Longtan shales are composed mainly of vitrinite and pyrobitumen, followed by inertinite. The pore types can be divided into organic matter pores and mineral matrix pores. Organic matter pores include primary organic matter pores and secondary organic matter pores. Mineral matrix pores include intergranular and intragranular pores. Intragranular pores can be further divided into intraplatelet pores within clay aggregates, intercrystalline pores, and dissolution pores. Mesopores and macropores provide most of the total pore volume, whereas micropores provide most of the total surface area. Total organic carbon content is the main factor controlling the pore development, and the contribution of clay minerals to porosity is still questionable. The maceral types and thermal evolution are of great significance to the development of organic matter pores in paralic shales. The primary composition and diagenetic modifications of the identified four major shale lithofacies are different, and therefore, result in various pore networks of each lithofacies.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"39 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141198441","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}
In the first comprehensive study of the Termit Basin petroleum system, an integrated organic geochemistry and basin modeling study of potential source rocks and related oils was conducted to evaluate source rock potential, classify oil families, establish oil–source correlation, and explain the distribution of petroleum systems. Six hundred forty-three cutting samples from the Paleogene Sokor1 Formation, Upper Cretaceous Yogou and Donga Formations, and Lower Cretaceous K1 Formation were analyzed using total organic carbon, Rock-Eval pyrolysis, vitrinite reflectance, and kerogen element analysis. The results suggest that the Sokor1, Yogou, and Donga Formations are poor to excellent source rocks with type I, II, II-III, and III kerogen, and most of the samples are thermally mature and within the oil window. Samples from the K1 Formation have poor organic richness and are thermally mature to postmature. In vertical, samples from the upper member of the Yogou Formation have greater organic matter richness and contain more oil-prone type I and oil-prone type II organic matter than those from the lower member. In horizontal, samples from the Donga Formation on the east side of the basin are dominated by very oil-prone type I and oil-prone type II organic matter and have higher hydrocarbon generation potential than those on the west side, which mainly contain oil- and gas-prone type II-III and gas-prone type III organic matter. One-dimensional basin modeling results demonstrate that the Sokor1 source rocks are mature in the northwestern part of the basin, are immature on the eastern side at present-day, and oil generation began in the early Oligocene. The Yogou source rocks are in the early oil to wet gas stage at present-day, and oil generation began at the end of the Late Cretaceous. The Donga source rocks are in the late oil to dry gas stage at present-day, and oil generation commenced in the middle Late Cretaceous. The maturation of these source rocks increased rapidly during the Oligocene due to active rifting. Three families (I, II, and III) were identified by hierarchical cluster analysis, principal component analysis, and stable carbon isotope compositions for 97 oil samples and eight rock extracts. Most of the oils (family I) were derived from Yogou source rocks, and their extensive distribution and wide range of thermal maturities are closely related to the large area of mature Yogou source rocks in the basin. Family II oils occur in the northwestern part of the basin and are genetically related to Sokor1 source rocks. The family III oil occurs on the east side of the basin and originated from the Donga Formation. This study confirms the existence of three petroleum systems between the Paleogene and Upper Cretaceous and helps to identify exploration prospects and guide petroleum resource assessment in the Termit Basin.
在对特米特盆地石油系统进行的首次综合研究中，对潜在的源岩和相关石油进行了有机地球化学和盆地模型综合研究，以评估源岩潜力、划分石油家族、建立油源相关性并解释石油系统的分布。研究人员利用总有机碳、Rock-Eval 热解、玻璃光泽反射率和角质元素分析方法，对来自古近纪索科尔1 地层、上白垩统约古地层和东嘎地层以及下白垩统 K1 地层的 643 个切割样本进行了分析。结果表明，索科尔1地层、窑沟地层和东嘎地层是贫油源岩到极佳油源岩，具有I、II、II-III和III型角质，大多数样本热成熟，处于石油窗口期。K1 地层的样本有机质丰富度较差，热成熟至后成熟。在纵向上，窑沟地层上部的样本比下部的样本富含更多的有机质，并含有更多的易出油 I 型和易出油 II 型有机质。在水平方向上，盆地东侧的东嘎地层样本以极易生油的Ⅰ型和Ⅱ型有机质为主，生烃潜力高于西侧的样本，后者主要含有易生油气的Ⅱ-Ⅲ型和易生气的Ⅲ型有机质。一维盆地建模结果表明，索科尔1号源岩在盆地西北部发育成熟，东侧目前尚未发育成熟，石油生成始于渐新世早期。Yogou源岩目前处于早期石油到湿气阶段，石油生成始于晚白垩世末期。东嘎源岩目前处于晚期石油到干气阶段，石油生成始于晚白垩世中期。在渐新世，由于断裂活跃，这些源岩的成熟度迅速提高。通过对 97 个石油样本和 8 个岩石提取物进行分层聚类分析、主成分分析和稳定碳同位素组成分析，确定了三个系列（I、II 和 III）。大部分油类（I 族）来自窑沟源岩，其广泛分布和广泛的热成熟度与盆地中大面积的成熟窑沟源岩密切相关。二系石油分布在盆地西北部，在基因上与索科尔1号源岩有关。III 族石油分布在盆地东侧，源于东嘎地层。这项研究证实了在古近纪和上白垩纪之间存在三个石油系统，有助于确定勘探前景并指导特米特盆地的石油资源评估。
{"title":"Oil families, oil–source rock correlation, basin modeling, and implication for petroleum systems, Termit Basin, Niger","authors":"Bang Liu, Lirong Dou, Guanghua Zhai, Fengjun Mao, Jiguo Liu, Mingsheng Lü, Dingsheng Cheng","doi":"10.1306/02132422137","DOIUrl":"https://doi.org/10.1306/02132422137","url":null,"abstract":"In the first comprehensive study of the Termit Basin petroleum system, an integrated organic geochemistry and basin modeling study of potential source rocks and related oils was conducted to evaluate source rock potential, classify oil families, establish oil–source correlation, and explain the distribution of petroleum systems. Six hundred forty-three cutting samples from the Paleogene Sokor1 Formation, Upper Cretaceous Yogou and Donga Formations, and Lower Cretaceous K1 Formation were analyzed using total organic carbon, Rock-Eval pyrolysis, vitrinite reflectance, and kerogen element analysis. The results suggest that the Sokor1, Yogou, and Donga Formations are poor to excellent source rocks with type I, II, II-III, and III kerogen, and most of the samples are thermally mature and within the oil window. Samples from the K1 Formation have poor organic richness and are thermally mature to postmature. In vertical, samples from the upper member of the Yogou Formation have greater organic matter richness and contain more oil-prone type I and oil-prone type II organic matter than those from the lower member. In horizontal, samples from the Donga Formation on the east side of the basin are dominated by very oil-prone type I and oil-prone type II organic matter and have higher hydrocarbon generation potential than those on the west side, which mainly contain oil- and gas-prone type II-III and gas-prone type III organic matter. One-dimensional basin modeling results demonstrate that the Sokor1 source rocks are mature in the northwestern part of the basin, are immature on the eastern side at present-day, and oil generation began in the early Oligocene. The Yogou source rocks are in the early oil to wet gas stage at present-day, and oil generation began at the end of the Late Cretaceous. The Donga source rocks are in the late oil to dry gas stage at present-day, and oil generation commenced in the middle Late Cretaceous. The maturation of these source rocks increased rapidly during the Oligocene due to active rifting. Three families (I, II, and III) were identified by hierarchical cluster analysis, principal component analysis, and stable carbon isotope compositions for 97 oil samples and eight rock extracts. Most of the oils (family I) were derived from Yogou source rocks, and their extensive distribution and wide range of thermal maturities are closely related to the large area of mature Yogou source rocks in the basin. Family II oils occur in the northwestern part of the basin and are genetically related to Sokor1 source rocks. The family III oil occurs on the east side of the basin and originated from the Donga Formation. This study confirms the existence of three petroleum systems between the Paleogene and Upper Cretaceous and helps to identify exploration prospects and guide petroleum resource assessment in the Termit Basin.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"49 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141193414","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}
Zhiyao Zhang, Yijie Zhang, Guangyou Zhu, Jianfa Han, Linxian Chi
Unraveling the charge histories of pools with complex petroleum fluid phases is crucial for effective exploration and fluid prediction. Oil and gas samples from multiphase pools in the Tazhong area of the Tarim Basin, China, were analyzed using complementary geochemical (e.g., gas chromatography [GC], two-dimensional GC coupled with time-of-flight mass spectrometry, compound-specific carbon isotope analysis, and pyrolysis simulations) and geological data to better understand their origins and spatial distribution. The integration of these data suggests that the petroleum in these multiphase pools was significantly impacted by various secondary geochemical processes, including oil cracking, thermochemical sulfate reduction (TSR), and gas invasion. Oil and gas in deep Cambrian pools were altered by oil cracking and TSR due to high temperatures of more than 170°C (320°F) at depths of more than 8500 m (27,900 ft), leading to the generation of secondary products, including diamondoids, organosulfur compounds (OSCs), and TSR-altered, H2S-rich cracking gases. This deep Cambrian gas, with diamondoids and OSCs, dissolved in the vapor phase, migrated upward through strike-slip faults, and invaded previously charged oil pools in Ordovician carbonates, changing the reservoir fluid characteristics and fluid phases. Thus, condensates were formed due to the introduction of excessive deep gas into the primary oil. The amount of gas invasion decreased with increasing distance from the strike-slip faults, thus forming multiphase pools with a spatial distribution pattern. Oil pools near strike-slip faults are more affected by gas invasion than weakly altered volatile oil pools and unaltered oil pools with greater distances away. The oil pools near the faults form condensate pools that show enrichment of H2S and carbon isotopic fractionation in C2–C4 gas components. This study provides new insights into the causal mechanism and distribution of multiphase pools in superdeep strata and has great potential for petroleum exploration in deeply buried Ordovician carbonates in the Tarim Basin.
揭示具有复杂石油流体相的油气藏的充注历史对于有效勘探和流体预测至关重要。我们利用互补的地球化学数据（如气相色谱、二维气相色谱-飞行时间质谱、特定化合物碳同位素分析和热解模拟）和地质数据分析了中国塔里木盆地塔中地区多相油气藏的油气样品，以更好地了解它们的起源和空间分布。这些数据的整合表明，这些多相池中的石油受到了各种次生地球化学过程的严重影响，包括石油裂解、热化学硫酸盐还原（TSR）和气体侵入。在超过 8500 米（27900 英尺）的深处，寒武纪深层油池中的石油和天然气因超过 170°C （320°F）的高温而发生了石油裂解和 TSR 变化，从而产生了二次产物，包括金刚石类、有机硫化合物 (OSC) 以及经 TSR 变化的富含 H2S 的裂解气。这种寒武纪深层天然气含有菱形物质和有机硫化物，溶解在气相中，通过走向滑动断层向上迁移，侵入奥陶系碳酸盐岩中先前带电的油池，改变了储层流体特征和流体相。因此，由于在原生油中引入了过量的深层气体，形成了凝析油。气体侵入量随着与走向滑动断层距离的增加而减少，从而形成了具有空间分布模式的多相油池。靠近走向滑动断层的油池受气体入侵的影响要大于弱蚀变挥发性油池和距离断层较远的未蚀变油池。断层附近的油池形成的凝析油池显示出 H2S 的富集和 C2-C4 气体组分的碳同位素分馏。这项研究为超深部地层中多相油池的成因机制和分布提供了新的见解，对塔里木盆地深埋奥陶系碳酸盐岩的石油勘探具有巨大的潜力。
{"title":"Multiphase pools caused by gas invasion in deep Ordovician carbonates from the Tazhong area, Tarim Basin, China","authors":"Zhiyao Zhang, Yijie Zhang, Guangyou Zhu, Jianfa Han, Linxian Chi","doi":"10.1306/12212318282","DOIUrl":"https://doi.org/10.1306/12212318282","url":null,"abstract":"Unraveling the charge histories of pools with complex petroleum fluid phases is crucial for effective exploration and fluid prediction. Oil and gas samples from multiphase pools in the Tazhong area of the Tarim Basin, China, were analyzed using complementary geochemical (e.g., gas chromatography [GC], two-dimensional GC coupled with time-of-flight mass spectrometry, compound-specific carbon isotope analysis, and pyrolysis simulations) and geological data to better understand their origins and spatial distribution. The integration of these data suggests that the petroleum in these multiphase pools was significantly impacted by various secondary geochemical processes, including oil cracking, thermochemical sulfate reduction (TSR), and gas invasion. Oil and gas in deep Cambrian pools were altered by oil cracking and TSR due to high temperatures of more than 170°C (320°F) at depths of more than 8500 m (27,900 ft), leading to the generation of secondary products, including diamondoids, organosulfur compounds (OSCs), and TSR-altered, H2S-rich cracking gases. This deep Cambrian gas, with diamondoids and OSCs, dissolved in the vapor phase, migrated upward through strike-slip faults, and invaded previously charged oil pools in Ordovician carbonates, changing the reservoir fluid characteristics and fluid phases. Thus, condensates were formed due to the introduction of excessive deep gas into the primary oil. The amount of gas invasion decreased with increasing distance from the strike-slip faults, thus forming multiphase pools with a spatial distribution pattern. Oil pools near strike-slip faults are more affected by gas invasion than weakly altered volatile oil pools and unaltered oil pools with greater distances away. The oil pools near the faults form condensate pools that show enrichment of H2S and carbon isotopic fractionation in C2–C4 gas components. This study provides new insights into the causal mechanism and distribution of multiphase pools in superdeep strata and has great potential for petroleum exploration in deeply buried Ordovician carbonates in the Tarim Basin.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"12 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140611534","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}
Huabiao Qiu, Wei Lin, Shang Deng, Huixi Lin, Zhongpei Zhang, Zicheng Cao, Cheng Huang, Jun Han
The Tarim Basin is the largest superimposed and oil-bearing basin in China, presented as an episodic tectonic superposition in the Central uplift. Understanding hydrocarbon differential accumulation in the Central uplift requires a proper view of the evolution of the early Paleozoic carbonate platform. Through detailed two-dimensional seismic interpretation, paleogeographic and paleotectonic reconstructions of the carbonate platform are performed. Tying hydrocarbon accumulation elements to the dynamic evolutionary process of the carbonate platform, this paper provides new insights into hydrocarbon differential accumulation in the Tazhong and Bachu uplifts. Due to ongoing compression from the south, the Hetian paleohigh and the Tazhong uplift initially formed in the Cambrian–Middle Ordovician carbonate platform interior in the latest Middle Ordovician. The climax of uplifting and northward tilting of preexisting paleohighs occurred in the latest Ordovician and latest Middle Devonian, respectively. The carbonate platform suffered polyphase exposures in these paleohighs and strike-slip faulting in the northern slope of the Tazhong uplift, forming favorable karst reservoirs and strike-slip fault-controlled reservoirs. Following the latest Permian uplifting of the northwestern Hetian paleohigh, the Bachu uplift nucleated in the northern Hetian paleohigh in the Cenozoic. The southwestern Hetian paleohigh was inverted into a southwest-dipping monocline. In the Bachu uplift, the allochthonous hydrocarbons from the southwestern Hetian paleohigh underwent episodic migration, accumulation, adjustment, and destruction during the evolution of these uninherited paleohighs. The hydrocarbons mainly remain in structural-stratigraphic traps in the southern margin of the Bachu uplift. Multiple periods of gentle tilting have occurred in the Tazhong uplift since the Late Devonian. Episodic migrating hydrocarbons from autochthonous and neighboring source rocks in the north are enriched in the northern flank of the inherited Tazhong uplift.
{"title":"The evolution of the early Paleozoic carbonate platform in the Central uplift, Tarim Basin, northwestern China, and hydrocarbon accumulation","authors":"Huabiao Qiu, Wei Lin, Shang Deng, Huixi Lin, Zhongpei Zhang, Zicheng Cao, Cheng Huang, Jun Han","doi":"10.1306/01242418082","DOIUrl":"https://doi.org/10.1306/01242418082","url":null,"abstract":"The Tarim Basin is the largest superimposed and oil-bearing basin in China, presented as an episodic tectonic superposition in the Central uplift. Understanding hydrocarbon differential accumulation in the Central uplift requires a proper view of the evolution of the early Paleozoic carbonate platform. Through detailed two-dimensional seismic interpretation, paleogeographic and paleotectonic reconstructions of the carbonate platform are performed. Tying hydrocarbon accumulation elements to the dynamic evolutionary process of the carbonate platform, this paper provides new insights into hydrocarbon differential accumulation in the Tazhong and Bachu uplifts. Due to ongoing compression from the south, the Hetian paleohigh and the Tazhong uplift initially formed in the Cambrian–Middle Ordovician carbonate platform interior in the latest Middle Ordovician. The climax of uplifting and northward tilting of preexisting paleohighs occurred in the latest Ordovician and latest Middle Devonian, respectively. The carbonate platform suffered polyphase exposures in these paleohighs and strike-slip faulting in the northern slope of the Tazhong uplift, forming favorable karst reservoirs and strike-slip fault-controlled reservoirs. Following the latest Permian uplifting of the northwestern Hetian paleohigh, the Bachu uplift nucleated in the northern Hetian paleohigh in the Cenozoic. The southwestern Hetian paleohigh was inverted into a southwest-dipping monocline. In the Bachu uplift, the allochthonous hydrocarbons from the southwestern Hetian paleohigh underwent episodic migration, accumulation, adjustment, and destruction during the evolution of these uninherited paleohighs. The hydrocarbons mainly remain in structural-stratigraphic traps in the southern margin of the Bachu uplift. Multiple periods of gentle tilting have occurred in the Tazhong uplift since the Late Devonian. Episodic migrating hydrocarbons from autochthonous and neighboring source rocks in the north are enriched in the northern flank of the inherited Tazhong uplift.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"6 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140623040","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}
Stratigraphic nomenclature describing Cretaceous- and Jurassic-age strata spanning the continental to deep-water depositional realms in the West Siberian Basin is lithostratigraphic, complex, and locally variable. A bureaucratically derived stratigraphic nomenclature system developed during early exploration (1940s) is administered by the Interdepartmental Stratigraphic Committee of Russia. Formation names were assigned on a well-by-well basis according to the geographic location of the well, the facies characteristics of the strata (i.e., facies regions, facies zones), the stratigraphic position, and the hydrocarbon region in which the well was drilled. Although rocks were primarily dated biostratigraphically, little to no consideration was given to the correlation of the strata in time. Thus, basin-scale lithostratigraphic cross sections display a plethora of formation names and lack chronostratigraphic detail. Furthermore, reservoirs are indexed. That is, reservoirs within a formation are given discrete names. Indexed reservoirs are correlated lithostratigraphically across time lines, resulting in incorrect predictions of reservoir continuity and erroneous volumetric estimates. The plethora of formation names and reservoir indices are of little use in relating the geological characteristics of hydrocarbon fields basin wide. Geologic age is the only criterion linking the stratigraphy of one location to the next.Stratigraphic columns are summarized to place formation names and reservoirs into a basin-wide chronostratigraphic context. Until the advent of basin-scale sequence-stratigraphic studies, these summaries offered the only basin-scale method of relating variously named formations and reservoirs chronostratigraphically. Moreover, at the field scale, chronostratigraphic correlation of parasequences, as opposed to lithostratigraphically correlating indexed reservoirs, can resolve field-development problems by yielding more precise estimates of resource volumes and distribution and more efficiently placed wells.
{"title":"A primer on West Siberian Basin stratigraphy: Chronostratigraphic cross-references for Cretaceous- and Jurassic-age strata, Russian Federation","authors":"Robert S. Tye","doi":"10.1306/12212323015","DOIUrl":"https://doi.org/10.1306/12212323015","url":null,"abstract":"Stratigraphic nomenclature describing Cretaceous- and Jurassic-age strata spanning the continental to deep-water depositional realms in the West Siberian Basin is lithostratigraphic, complex, and locally variable. A bureaucratically derived stratigraphic nomenclature system developed during early exploration (1940s) is administered by the Interdepartmental Stratigraphic Committee of Russia. Formation names were assigned on a well-by-well basis according to the geographic location of the well, the facies characteristics of the strata (i.e., facies regions, facies zones), the stratigraphic position, and the hydrocarbon region in which the well was drilled. Although rocks were primarily dated biostratigraphically, little to no consideration was given to the correlation of the strata in time. Thus, basin-scale lithostratigraphic cross sections display a plethora of formation names and lack chronostratigraphic detail. Furthermore, reservoirs are indexed. That is, reservoirs within a formation are given discrete names. Indexed reservoirs are correlated lithostratigraphically across time lines, resulting in incorrect predictions of reservoir continuity and erroneous volumetric estimates. The plethora of formation names and reservoir indices are of little use in relating the geological characteristics of hydrocarbon fields basin wide. Geologic age is the only criterion linking the stratigraphy of one location to the next.Stratigraphic columns are summarized to place formation names and reservoirs into a basin-wide chronostratigraphic context. Until the advent of basin-scale sequence-stratigraphic studies, these summaries offered the only basin-scale method of relating variously named formations and reservoirs chronostratigraphically. Moreover, at the field scale, chronostratigraphic correlation of parasequences, as opposed to lithostratigraphically correlating indexed reservoirs, can resolve field-development problems by yielding more precise estimates of resource volumes and distribution and more efficiently placed wells.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"108 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140623291","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}
Recently, considerable hydrocarbon reserves have been discovered in Lower–Middle Ordovician carbonate reservoirs situated surrounding two conjugate strike-slip fault zones in the Shunbei oil field, Tarim Basin, northwestern China. Through the integrated analysis of crude oil physical properties, geochemical compositions, and fluid inclusions, the differential petroleum charging history of the Shunbei oil field has been investigated. For the Shunbei (SHB)5 fault zone, two discrete ranges of homogenization temperature of coeval aqueous inclusions indicate intense charging during the early Yanshan Orogeny, with minor charging during the late Himalayan Orogeny. For the SHB1 fault zone, the extended homogenization temperature range probably reflects continuous charging from the early Yanshan to the late Himalayan Orogenies. The presence of bitumen indicates an earliest petroleum charging event during the late Caledonian Orogeny. Differential petroleum charging during the Himalayan Orogeny caused stark differences in the thermal maturity of trapped oil and the mixing of oil with variable maturity, with the SHB1 fault zone receiving more intense charging of late-stage oils than the SHB5 fault zone. The differential petroleum charging during the Himalayan Orogeny can be explained by preferential reactivation of northeast-trending strike-slip faults, controlled by the regional northeast 45°-oriented compressive stress field. Crude oil with high maturity would preferentially migrate vertically via the reactivated northeast-striking SHB1 fault zone, charging into reservoirs, resulting in the current maturity differences in the trapped oils in the Shunbei oil field. These results illustrate the preferential vertical petroleum migration along the reactivated fault and the controlling role of the regional stress field on fault behaviors.
{"title":"Differential petroleum charging controlled by movements of two strike-slip faults in the Shunbei area, Tarim Basin, northwestern China","authors":"Fuyun Cong, Jinqiang Tian, Fang Hao, Qi Wang, Jianzhang Liu, Zicheng Cao","doi":"10.1306/12152319179","DOIUrl":"https://doi.org/10.1306/12152319179","url":null,"abstract":"Recently, considerable hydrocarbon reserves have been discovered in Lower–Middle Ordovician carbonate reservoirs situated surrounding two conjugate strike-slip fault zones in the Shunbei oil field, Tarim Basin, northwestern China. Through the integrated analysis of crude oil physical properties, geochemical compositions, and fluid inclusions, the differential petroleum charging history of the Shunbei oil field has been investigated. For the Shunbei (SHB)5 fault zone, two discrete ranges of homogenization temperature of coeval aqueous inclusions indicate intense charging during the early Yanshan Orogeny, with minor charging during the late Himalayan Orogeny. For the SHB1 fault zone, the extended homogenization temperature range probably reflects continuous charging from the early Yanshan to the late Himalayan Orogenies. The presence of bitumen indicates an earliest petroleum charging event during the late Caledonian Orogeny. Differential petroleum charging during the Himalayan Orogeny caused stark differences in the thermal maturity of trapped oil and the mixing of oil with variable maturity, with the SHB1 fault zone receiving more intense charging of late-stage oils than the SHB5 fault zone. The differential petroleum charging during the Himalayan Orogeny can be explained by preferential reactivation of northeast-trending strike-slip faults, controlled by the regional northeast 45°-oriented compressive stress field. Crude oil with high maturity would preferentially migrate vertically via the reactivated northeast-striking SHB1 fault zone, charging into reservoirs, resulting in the current maturity differences in the trapped oils in the Shunbei oil field. These results illustrate the preferential vertical petroleum migration along the reactivated fault and the controlling role of the regional stress field on fault behaviors.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"38 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140635139","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}
Xi Zhang, Xiaoming Zhao, Jiawang Ge, Shuxin Li, Tingshan Zhang
Organic-rich continental and marine–continental (i.e., transitional) shales are characterized by numerous hydrocarbon production layers having an uneven horizontal distribution, which are challenging to locate and exploit. We examined the effects of karst topography on organic carbon accumulation during the early Permian in the southeastern Ordos Basin, northwestern China, using outcrop and well data. Our study involved geomorphological, sedimentological, petrological, and geochemical methods. We identified a regional unconformity on the Dongdayao Limestone (DDYL) that formed in the early Permian (Asselian; i.e., in the Shanxi Formation) in the study area based on (1) cave, pore, and breccia development in outcrops and drill cores; (2) high Mn–Fe and low Sr contents associated with negative δ18O and normal δ13C values, which are indicative of strong leaching by meteoric waters; and (3) the irregular thickness of the DDYL that is indicative of differential karstification, resulting in the formation of horizontal gullies. The karst topography of the DDYL was identified based on the moldic and residual thickness methods, including karst highland, gentle slope, and microbasin geomorphic units. We propose that the karst topography controlled the redox environment and led to enrichment of the organic-rich transitional shales in the selected submember of the Shanxi Formation. The U/Th, V/Cr, and V/(V+Ni) ratios exhibit a linear relationship with geomorphic unit types. The karst microbasins had a weakly oxic environment, which widely preserved thick, organic-rich, transitional shales having high total organic carbon content and gas-bearing potential.
{"title":"Karst topography paces the deposition of lower Permian, organic-rich, marine–continental transitional shales in the southeastern Ordos Basin, northwestern China","authors":"Xi Zhang, Xiaoming Zhao, Jiawang Ge, Shuxin Li, Tingshan Zhang","doi":"10.1306/11152322091","DOIUrl":"https://doi.org/10.1306/11152322091","url":null,"abstract":"Organic-rich continental and marine–continental (i.e., transitional) shales are characterized by numerous hydrocarbon production layers having an uneven horizontal distribution, which are challenging to locate and exploit. We examined the effects of karst topography on organic carbon accumulation during the early Permian in the southeastern Ordos Basin, northwestern China, using outcrop and well data. Our study involved geomorphological, sedimentological, petrological, and geochemical methods. We identified a regional unconformity on the Dongdayao Limestone (DDYL) that formed in the early Permian (Asselian; i.e., in the Shanxi Formation) in the study area based on (1) cave, pore, and breccia development in outcrops and drill cores; (2) high Mn–Fe and low Sr contents associated with negative δ18O and normal δ13C values, which are indicative of strong leaching by meteoric waters; and (3) the irregular thickness of the DDYL that is indicative of differential karstification, resulting in the formation of horizontal gullies. The karst topography of the DDYL was identified based on the moldic and residual thickness methods, including karst highland, gentle slope, and microbasin geomorphic units. We propose that the karst topography controlled the redox environment and led to enrichment of the organic-rich transitional shales in the selected submember of the Shanxi Formation. The U/Th, V/Cr, and V/(V+Ni) ratios exhibit a linear relationship with geomorphic unit types. The karst microbasins had a weakly oxic environment, which widely preserved thick, organic-rich, transitional shales having high total organic carbon content and gas-bearing potential.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"44 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140611632","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}
Total organic carbon (TOC) content and hydrogen index (HI) are critical parameters for evaluating the hydrocarbon generation potential of source rocks and shale gas resources. However, for overmature shales, laboratory-measured residual TOC content and residual HI fail to reflect original properties. In this study, overmature Upper Ordovician to early Silurian Wufeng–Longmaxi shales from south China were selected to estimate the original TOC content and original HI based on major- and trace-element concentrations that are rarely lost during thermal alteration. Proxies were used, including biogenic silica, Cu/Al, P/Al, Mo-enrichment factor (EF), U/Th, U-EF, Al, and Ti content to document the organic matter accumulation process of the Wufeng–Longmaxi Formations. The relationships among proxies for paleoproductivity (biogenic silica), paleoredox conditions (Mo-EF), terrigenous influx (Al), and TOC content suggest that organic matter accumulation was primarily controlled by high paleoproductivity and anoxic conditions. Moreover, the ratio of biogenic silica to total silica is an effective proxy for estimating the marine organic matter fraction. The original HI values of global immature marine shales display a normal distribution; hence, the calculated marine organic matter fraction is hypothesized to conform to a normal distribution. Based on intervals (μ − σ, μ + σ) and (μ − 2σ, μ + 2σ) (μ is the deviation and σ is the variance) with the same probability, a correlation between original HI and organic matter abundance was established. The average restored original TOC and HI were 4.9 wt. % and 493 mg/g, respectively, indicating the dominance of organic matter type I–II1. The thermal maturity and hydrocarbon generation history modeling results suggest that the estimated original TOC and HI values are reasonable.
总有机碳（TOC）含量和氢指数（HI）是评估源岩和页岩气资源碳氢化合物生成潜力的关键参数。然而，对于过成熟页岩，实验室测量的残余 TOC 含量和残余 HI 无法反映其原始属性。本研究选取了中国南方上奥陶统至志留纪早期的过成熟五峰-龙马溪页岩，根据热蚀变过程中很少损失的主要元素和痕量元素浓度来估算原始 TOC 含量和原始 HI。利用生物硅、Cu/Al、P/Al、Mo-富集因子（EF）、U/Th、U-EF、Al和Ti含量等代用指标记录了五峰-龙马溪地层的有机质累积过程。古生产率（生物硅）、古缺氧条件（Mo-EF）、土著涌入量（Al）和总有机碳含量等代用指标之间的关系表明，有机质的积累主要受高古生产率和缺氧条件的控制。此外，生物硅石与总硅石的比率是估算海洋有机质部分的有效替代指标。全球未成熟海相页岩的原始 HI 值呈正态分布，因此推测计算出的海相有机质部分也符合正态分布。根据概率相同的区间 (μ - σ, μ + σ) 和 (μ - 2σ, μ + 2σ) (μ为偏差，σ为方差)，确定了原始 HI 与有机质丰度之间的相关性。平均恢复的原始总有机碳和 HI 分别为 4.9 重量%和 493 毫克/克，表明有机物类型 I-II1 占主导地位。热成熟度和碳氢化合物生成历史建模结果表明，估计的原始总有机碳含量和总碳氢化合物含量值是合理的。
{"title":"Estimation of original total organic carbon content and hydrogen index using major and trace element concentrations in the overmature Upper Ordovician–lower Silurian Wufeng–Longmaxi marine shales, southeast Sichuan Basin, south China","authors":"Xunyao Wang, Tian Dong, Sheng He, Qing He","doi":"10.1306/12212322070","DOIUrl":"https://doi.org/10.1306/12212322070","url":null,"abstract":"Total organic carbon (TOC) content and hydrogen index (HI) are critical parameters for evaluating the hydrocarbon generation potential of source rocks and shale gas resources. However, for overmature shales, laboratory-measured residual TOC content and residual HI fail to reflect original properties. In this study, overmature Upper Ordovician to early Silurian Wufeng–Longmaxi shales from south China were selected to estimate the original TOC content and original HI based on major- and trace-element concentrations that are rarely lost during thermal alteration. Proxies were used, including biogenic silica, Cu/Al, P/Al, Mo-enrichment factor (EF), U/Th, U-EF, Al, and Ti content to document the organic matter accumulation process of the Wufeng–Longmaxi Formations. The relationships among proxies for paleoproductivity (biogenic silica), paleoredox conditions (Mo-EF), terrigenous influx (Al), and TOC content suggest that organic matter accumulation was primarily controlled by high paleoproductivity and anoxic conditions. Moreover, the ratio of biogenic silica to total silica is an effective proxy for estimating the marine organic matter fraction. The original HI values of global immature marine shales display a normal distribution; hence, the calculated marine organic matter fraction is hypothesized to conform to a normal distribution. Based on intervals (μ − σ, μ + σ) and (μ − 2σ, μ + 2σ) (μ is the deviation and σ is the variance) with the same probability, a correlation between original HI and organic matter abundance was established. The average restored original TOC and HI were 4.9 wt. % and 493 mg/g, respectively, indicating the dominance of organic matter type I–II1. The thermal maturity and hydrocarbon generation history modeling results suggest that the estimated original TOC and HI values are reasonable.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"149 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140623219","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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