Petroleum migration and accumulation associated with ostracod-bearing layers in shale oil systems were investigated using a large suite of high-resolution geochemical and mineralogical data combined with petrology description and pore characterization of shale core samples from the first member of the Upper Cretaceous Qingshankou Formation in the Qijia-Gulong sag of the Songliao Basin, northeastern China. The first member of the Qingshankou shale, deposited in a moderately deep lake setting, is dominated mainly by massive mud rock and laminated shale with numerous ostracod-enriched interbedded layers. The thin carbonate-rich ostracod-bearing layers dominate the total organic carbon (TOC)–lean facies having TOC values of <2 wt. %. Petroleum yields (volatile free hydrocarbons in programmed pyrolysis [S1]) and solvent extract yields share similar vertical variation trends with TOC content, indicating that TOC content exerts an important control on retained hydrocarbon. However, there exist some upward increasing trends of TOC-normalized petroleum yields (S1) and solvent extract yields around the organic-lean interbedded carbonate-rich layers dominated by ostracods. This phenomenon, combined with bitumen and fluorescing oil within fractures and ostracod-associated pores, abnormal Rock-Eval pyrolysis parameters, compositional differences, and molecular size differences, indicate the presence of migrated hydrocarbon in organic-lean interbedded ostracod-bearing layers. The oil production of ostracod-related organic-lean shale reservoirs is much more effective due to the high brittleness of organic-lean lithofacies, improved oil quality, and low content of adsorbed oil. Three stages were proposed in a conceptual model for petroleum migration and accumulation associated with ostracod-bearing layers in the Qingshankou shale oil system.
{"title":"Petroleum migration and accumulation in a shale oil system of the Upper Cretaceous Qingshankou Formation in the Songliao Basin, northeastern China","authors":"Wenming Ji, Fang Hao, Fanhao Gong, Jian Zhang, Yunfeng Bai, Chao Liang, Jinqiang Tian","doi":"10.1306/03212423016","DOIUrl":"https://doi.org/10.1306/03212423016","url":null,"abstract":"Petroleum migration and accumulation associated with ostracod-bearing layers in shale oil systems were investigated using a large suite of high-resolution geochemical and mineralogical data combined with petrology description and pore characterization of shale core samples from the first member of the Upper Cretaceous Qingshankou Formation in the Qijia-Gulong sag of the Songliao Basin, northeastern China. The first member of the Qingshankou shale, deposited in a moderately deep lake setting, is dominated mainly by massive mud rock and laminated shale with numerous ostracod-enriched interbedded layers. The thin carbonate-rich ostracod-bearing layers dominate the total organic carbon (TOC)–lean facies having TOC values of <2 wt. %. Petroleum yields (volatile free hydrocarbons in programmed pyrolysis [S1]) and solvent extract yields share similar vertical variation trends with TOC content, indicating that TOC content exerts an important control on retained hydrocarbon. However, there exist some upward increasing trends of TOC-normalized petroleum yields (S1) and solvent extract yields around the organic-lean interbedded carbonate-rich layers dominated by ostracods. This phenomenon, combined with bitumen and fluorescing oil within fractures and ostracod-associated pores, abnormal Rock-Eval pyrolysis parameters, compositional differences, and molecular size differences, indicate the presence of migrated hydrocarbon in organic-lean interbedded ostracod-bearing layers. The oil production of ostracod-related organic-lean shale reservoirs is much more effective due to the high brittleness of organic-lean lithofacies, improved oil quality, and low content of adsorbed oil. Three stages were proposed in a conceptual model for petroleum migration and accumulation associated with ostracod-bearing layers in the Qingshankou shale oil system.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718771","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 Tahe oil field is one of the largest deeply buried, multistage-charged Paleozoic oil fields in the Tarim Basin, northwestern China. Understanding the temporal evolution of Paleozoic oils is crucial for petroleum prospecting in this region. In this study, a combination of biomarker analysis, stable/radiogenic isotopic analysis, and Re-Os and U-Pb isotope geochronology is used to constrain the timing of oil accumulation in the Tahe oil field. Coexistence of unresolved complex mixture and intact n-alkane series in oil chromatograms suggests the presence of multistage oil accumulation processes in the studied area, and paleo-biodegradation occurred prior to the latest oil charge. Biomarker data show that the source rock for the latest accumulated oils was deposited in a marine reducing–weakly oxidizing environment. An early Permian oil generation event (276 ± 35 Ma) was suggested by Re-Os geochronology. This oil generation event is responsible for the late Permian–Late Triassic charge event (259.9–224.1 Ma), which is identified with in situ U-Pb isotopic analysis of calcites containing primary oil inclusions. These age data provide direct temporal constraints for the latest oil accumulation in the Tahe oil field. Furthermore, C-O-Sr-Os isotopic results show that hydrothermal fluid flowed during this oil accumulation event. Outcomes of this study unravel the Re-Os isotopic analysis of cogenetic crude oils and have the potential of direct dating the latest, hydrothermally linked oil accumulation in multistage-charged deep oil reservoirs.
{"title":"Recognition of a hydrothermally linked oil accumulation process in the Tahe oil field, northwestern China, with organic geochemistry, Re-Os, and U-Pb geochronology","authors":"Shaojie Li, Xiaowen Guo, Bin Wang, Zicheng Cao, Hao Xu, Jiaxu Chen","doi":"10.1306/02132422124","DOIUrl":"https://doi.org/10.1306/02132422124","url":null,"abstract":"The Tahe oil field is one of the largest deeply buried, multistage-charged Paleozoic oil fields in the Tarim Basin, northwestern China. Understanding the temporal evolution of Paleozoic oils is crucial for petroleum prospecting in this region. In this study, a combination of biomarker analysis, stable/radiogenic isotopic analysis, and Re-Os and U-Pb isotope geochronology is used to constrain the timing of oil accumulation in the Tahe oil field. Coexistence of unresolved complex mixture and intact n-alkane series in oil chromatograms suggests the presence of multistage oil accumulation processes in the studied area, and paleo-biodegradation occurred prior to the latest oil charge. Biomarker data show that the source rock for the latest accumulated oils was deposited in a marine reducing–weakly oxidizing environment. An early Permian oil generation event (276 ± 35 Ma) was suggested by Re-Os geochronology. This oil generation event is responsible for the late Permian–Late Triassic charge event (259.9–224.1 Ma), which is identified with in situ U-Pb isotopic analysis of calcites containing primary oil inclusions. These age data provide direct temporal constraints for the latest oil accumulation in the Tahe oil field. Furthermore, C-O-Sr-Os isotopic results show that hydrothermal fluid flowed during this oil accumulation event. Outcomes of this study unravel the Re-Os isotopic analysis of cogenetic crude oils and have the potential of direct dating the latest, hydrothermally linked oil accumulation in multistage-charged deep oil reservoirs.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718832","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 informative Geologic Note, “Why does it take so long to publish a paper in the AAPG Bulletin?,” Camp (2024) presents useful information for authors, prospective authors, and reviewers of manuscripts for the AAPG Bulletin that I hope will decrease the time to publication. I would like to expand on Camp’s sage advice with suggestions based on fond memories of my experience and perspectives as AAPG Editor (2007–2010).The Editor bears responsibility for managing peer review and identifying and motivating volunteer reviewers and Associate Editors. The proverbial buck stops there.Individual elected editors of the AAPG Bulletin have...
{"title":"Why does it take so long to publish a paper in the AAPG Bulletin?: Discussion","authors":"Gretchen M. Gillis","doi":"10.1306/04172424017","DOIUrl":"https://doi.org/10.1306/04172424017","url":null,"abstract":"In the informative Geologic Note, “Why does it take so long to publish a paper in the AAPG Bulletin?,” Camp (2024) presents useful information for authors, prospective authors, and reviewers of manuscripts for the AAPG Bulletin that I hope will decrease the time to publication. I would like to expand on Camp’s sage advice with suggestions based on fond memories of my experience and perspectives as AAPG Editor (2007–2010).The Editor bears responsibility for managing peer review and identifying and motivating volunteer reviewers and Associate Editors. The proverbial buck stops there.Individual elected editors of the AAPG Bulletin have...","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718775","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}
Wayne Narr, Eric A. Flodin, Ted E. Playton, Vincent Heesakkers
A system of exceptionally well-exposed, early-burial fractures in outcrops of Devonian carbonates on the Lennard Shelf, Canning Basin, Western Australia, serves as an analogue for fractures in deep reefal carbonate petroleum reservoirs in the Precaspian Basin of Kazakhstan. Data from early fractures were collected at Windjana Gorge, which crosscuts such a reefal depositional system. Less extensive evaluations were also made at three auxiliary sites along the Lennard Shelf.These early-formed, near-vertical fractures strike parallel or normal to the strike of the Devonian depositional margin. Fracture density correlates with the textural character of the host rock, with the highest values in boundstone-rich rock, lowest values in grain-rich rocks, and intermediate values in rocks of mixed assemblage, including breccia. Fracture density is also controlled in part by the mechanical character of bedding at the time the fracture system developed, syndepositionally or soon after. The environment of deposition (EoD) shows a weaker correlation with fracture density. At Windjana Gorge, fracture height correlates with the EoD, with the largest values in the reef core, progressing serially to shorter average height in the upper slope, middle slope, reef flat, and platform top/reef flat (a transitional EoD).To better understand the fracture size distribution within a reservoir that can influence fluid drainage, we introduce a new parameter, the intersected fracture height density (IFHD). This describes the aggregate fracture height connected directly to a traverse line or borehole. Because IFHD requires the measurement of fracture heights, it is measurable only at outcrop analogue exposures.
{"title":"Depositional and lithological control on fractures in a steep, reefal carbonate margin: Lennard Shelf outcrops of the Canning Basin, Western Australia","authors":"Wayne Narr, Eric A. Flodin, Ted E. Playton, Vincent Heesakkers","doi":"10.1306/02132423039","DOIUrl":"https://doi.org/10.1306/02132423039","url":null,"abstract":"A system of exceptionally well-exposed, early-burial fractures in outcrops of Devonian carbonates on the Lennard Shelf, Canning Basin, Western Australia, serves as an analogue for fractures in deep reefal carbonate petroleum reservoirs in the Precaspian Basin of Kazakhstan. Data from early fractures were collected at Windjana Gorge, which crosscuts such a reefal depositional system. Less extensive evaluations were also made at three auxiliary sites along the Lennard Shelf.These early-formed, near-vertical fractures strike parallel or normal to the strike of the Devonian depositional margin. Fracture density correlates with the textural character of the host rock, with the highest values in boundstone-rich rock, lowest values in grain-rich rocks, and intermediate values in rocks of mixed assemblage, including breccia. Fracture density is also controlled in part by the mechanical character of bedding at the time the fracture system developed, syndepositionally or soon after. The environment of deposition (EoD) shows a weaker correlation with fracture density. At Windjana Gorge, fracture height correlates with the EoD, with the largest values in the reef core, progressing serially to shorter average height in the upper slope, middle slope, reef flat, and platform top/reef flat (a transitional EoD).To better understand the fracture size distribution within a reservoir that can influence fluid drainage, we introduce a new parameter, the intersected fracture height density (IFHD). This describes the aggregate fracture height connected directly to a traverse line or borehole. Because IFHD requires the measurement of fracture heights, it is measurable only at outcrop analogue exposures.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718777","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}
I thank previous AAPG Editor and former AAPG President, Gretchen Gillis, for her supportive comments and encouragement for the AAPG Bulletin Editors to help to expedite the peer review process. Issues with timely peer reviews are not limited to the Bulletin but are also experienced by other scientific journals (M. Pranter, 2024, personal communication). My analysis was based on a review of articles published in volume 107 of the Bulletin through November 2023. The results showed that most of the review period was consumed by the time required for revisions (average 12 months), which is a function of the quality...
{"title":"Why does it take so long to publish a paper in the AAPG Bulletin: Reply","authors":"Wayne K. Camp","doi":"10.1306/04172424028","DOIUrl":"https://doi.org/10.1306/04172424028","url":null,"abstract":"I thank previous AAPG Editor and former AAPG President, Gretchen Gillis, for her supportive comments and encouragement for the AAPG Bulletin Editors to help to expedite the peer review process. Issues with timely peer reviews are not limited to the Bulletin but are also experienced by other scientific journals (M. Pranter, 2024, personal communication). My analysis was based on a review of articles published in volume 107 of the Bulletin through November 2023. The results showed that most of the review period was consumed by the time required for revisions (average 12 months), which is a function of the quality...","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718773","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}
Present-day stress, permeability, and hydraulic fracturing of coals at 323- to 1454-m (1060- to 4770-ft) depths were studied from the Qinshui Basin to analyze the influence of variable present-day stress regimes on coalbed methane productivity. The present maximum horizontal stress orientation is primarily northeast-southwest, with some local variations. Stress magnitudes generally increase with depth but with U-shaped variations in stress gradients. A strike-slip fault stress regime is dominant and is consecutively distributed vertically, whereas normal and reverse fault stress regimes are distributed mainly in specific depth intervals. Permeability (0.004–13.18 md) and stress regime present high variability, with changes in structural trends; structural lows result in a strike-slip fault stress regime and extremely low permeability (<0.1 md), and structural highs create relatively higher permeability regions with lower horizontal stress differential. Fracture stimulation designs should consider transitions in depth- and structural trends-related stress regimes and preexisting fractures, instead, using the current uniform schemes. Hydraulic fracture geometries are influenced by both stress and preexisting fractures in structural highs, occurring at multiple orientations with larger angles and allowing for greater reservoir stimulation volumes. Conversely, in structural lows, the higher differential stresses direct both major fracture and branches propagation along the maximum horizontal orientation. Most deep seams located in syncline axis, fault troughs, and subsags within the basin require a better proppant-supported profile, whereas small-scale fracturing has shown limited adaptability. Higher pumped rates and treating pressures are necessary in deep structural highs to reduce fracture complexity and improve proppant filling effectiveness.
{"title":"Present-day stress regime, permeability, and fracture stimulations of coal reservoirs in the Qinshui Basin, northern China","authors":"Shida Chen, Yafei Zhang, Dazhen Tang, Shu Tao, Yifan Pu, Zhenhong Chen","doi":"10.1306/03202422056","DOIUrl":"https://doi.org/10.1306/03202422056","url":null,"abstract":"Present-day stress, permeability, and hydraulic fracturing of coals at 323- to 1454-m (1060- to 4770-ft) depths were studied from the Qinshui Basin to analyze the influence of variable present-day stress regimes on coalbed methane productivity. The present maximum horizontal stress orientation is primarily northeast-southwest, with some local variations. Stress magnitudes generally increase with depth but with U-shaped variations in stress gradients. A strike-slip fault stress regime is dominant and is consecutively distributed vertically, whereas normal and reverse fault stress regimes are distributed mainly in specific depth intervals. Permeability (0.004–13.18 md) and stress regime present high variability, with changes in structural trends; structural lows result in a strike-slip fault stress regime and extremely low permeability (<0.1 md), and structural highs create relatively higher permeability regions with lower horizontal stress differential. Fracture stimulation designs should consider transitions in depth- and structural trends-related stress regimes and preexisting fractures, instead, using the current uniform schemes. Hydraulic fracture geometries are influenced by both stress and preexisting fractures in structural highs, occurring at multiple orientations with larger angles and allowing for greater reservoir stimulation volumes. Conversely, in structural lows, the higher differential stresses direct both major fracture and branches propagation along the maximum horizontal orientation. Most deep seams located in syncline axis, fault troughs, and subsags within the basin require a better proppant-supported profile, whereas small-scale fracturing has shown limited adaptability. Higher pumped rates and treating pressures are necessary in deep structural highs to reduce fracture complexity and improve proppant filling effectiveness.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718833","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}
Neil F. Hurley, Ted E. Playton, Josephina Schembre-McCabe
Tengiz and Korolev fields are isolated carbonate buildups in western Kazakhstan, characterized by a range of primary rock types and fabrics in shallow-platform to slope depositional settings. These rock fabrics underwent extensive diagenetic modification from the time of deposition through deep burial, resulting in a complex paragenetic sequence with a variety of pore types. This study is focused on the Bashkirian–Serpukhovian–upper Visean interval (unit 1), which is the major oil-producing reservoir in Tengiz and Korolev fields. Most samples are from outer-platform and slope settings.Pore types are defined as collections or groups of micro- and macropores that may have different origins. These groups, which are linked to the paragenetic sequence, form characteristic assemblages that occur repeatedly in slope and platform settings. Pore types are classified based on the amount, distribution, and connectivity of micro- and macropores.Laser scanning confocal microscopy, which generates images of pores as small as 0.2 µm in diameter, provides an effective tool to visualize and quantify micropores (i.e., pores with pore diameter ≤10 µm). Confocal microscopy, combined with transmitted-light (TL) petrography, routine core analysis, and mercury injection capillary pressure (MICP) data were used to designate five pore types, which include micropore-dominated, macropore-dominated, and mixed micro- and macropore-bearing rocks with variable degrees of connectivity.This approach, which offers a new way to define complex pore families that correlate to reservoir-property groups, applies to any carbonate reservoir. This integrated petrographic and petrophysical classification links pore-body (confocal and TL) and pore-throat (MICP) size distributions. Future work includes prediction of pore types from logs and development of strategies for spatial distribution of pore types between wells in full-field geologic models.
{"title":"Integrated approach to pore typing in complex carbonate reservoirs, Tengiz and Korolev fields, Kazakhstan","authors":"Neil F. Hurley, Ted E. Playton, Josephina Schembre-McCabe","doi":"10.1306/03132422025","DOIUrl":"https://doi.org/10.1306/03132422025","url":null,"abstract":"Tengiz and Korolev fields are isolated carbonate buildups in western Kazakhstan, characterized by a range of primary rock types and fabrics in shallow-platform to slope depositional settings. These rock fabrics underwent extensive diagenetic modification from the time of deposition through deep burial, resulting in a complex paragenetic sequence with a variety of pore types. This study is focused on the Bashkirian–Serpukhovian–upper Visean interval (unit 1), which is the major oil-producing reservoir in Tengiz and Korolev fields. Most samples are from outer-platform and slope settings.Pore types are defined as collections or groups of micro- and macropores that may have different origins. These groups, which are linked to the paragenetic sequence, form characteristic assemblages that occur repeatedly in slope and platform settings. Pore types are classified based on the amount, distribution, and connectivity of micro- and macropores.Laser scanning confocal microscopy, which generates images of pores as small as 0.2 µm in diameter, provides an effective tool to visualize and quantify micropores (i.e., pores with pore diameter ≤10 µm). Confocal microscopy, combined with transmitted-light (TL) petrography, routine core analysis, and mercury injection capillary pressure (MICP) data were used to designate five pore types, which include micropore-dominated, macropore-dominated, and mixed micro- and macropore-bearing rocks with variable degrees of connectivity.This approach, which offers a new way to define complex pore families that correlate to reservoir-property groups, applies to any carbonate reservoir. This integrated petrographic and petrophysical classification links pore-body (confocal and TL) and pore-throat (MICP) size distributions. Future work includes prediction of pore types from logs and development of strategies for spatial distribution of pore types between wells in full-field geologic models.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718772","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}
Neil F. Hurley, Ted E. Playton, Josephina Schembre-McCabe
The purpose of this study is to classify and quantify predominantly open microfractures in the subsurface Tengiz and Korolev carbonate reservoirs of western Kazakhstan. Microfractures, previously unknown in these fields, occur in nearly all of hundreds of the thin sections examined using transmitted-light (TL) and confocal microscopy. This study, done in carbonate rocks, differs from most previous work on microfractures, which mainly concentrates on silica-bearing rocks (sandstones and granites) and sealed (cemented), rather than open, microfractures.Microfractures in Tengiz and Korolev rocks are obscure or invisible using TL petrography. However, they are clearly visible in high-resolution (0.2 μm/pixel) laser-scanning confocal images. In decreasing order of abundance, we observed the following microfracture types: (1) dissolution-enlarged microfractures, (2) mosaic microfractures, (3) sealed and partially sealed microfractures lined with carbonate cement and/or bitumen, (4) intercrystalline microfractures in echinoderm fragments and coarse blocky calcite cements, (5) en echelon microfractures, (6) sediment-filled microfractures, (7) microfaults and deformation bands, (8) microfracture ganglia, and (9) reaction halos in the matrix near open microfractures. All microfracture types are interpreted to be natural, as opposed to induced features.Microfracture quantification, used here to determine the amount of open microfracture porosity in two-dimensional confocal images, has been applied to more than 300 samples. Microfracture porosity typically ranges from 0.2 to 1.0 porosity units. Aperture widths are generally on the order of 0.2 to 10 μm.A unique feature of this study is the relationship between dynamic properties and the amounts and types of microfractures observed in the rocks. Specifically, microfracture abundance relates to the effect of variable confining pressure on porosity and permeability in core plugs. Samples in which total confocal porosity is dominated (>80%) by microfractures, mainly upper-slope boundstones, showed moderate decreases in porosity and major decreases in permeability as a function of increased confining pressure. Samples in which microfractures are a relatively minor component (<20%) of total confocal porosity, mainly middle-slope breccias and grainstones and outer-platform grainstones, showed significantly smaller decreases in porosity and permeability as a function of increased confining pressure. Hysteresis effects, especially for permeability, are common. In conclusion, in reservoirs with open microfractures, core-plug scale permeability is subject to change with variable confining pressure. This mode of permeability variation should be considered in reservoir models conditioned by core-plug results.
{"title":"Microfracture classification, quantification, and petrophysical behavior in the Tengiz and Korolev carbonate reservoirs, Kazakhstan","authors":"Neil F. Hurley, Ted E. Playton, Josephina Schembre-McCabe","doi":"10.1306/03132422024","DOIUrl":"https://doi.org/10.1306/03132422024","url":null,"abstract":"The purpose of this study is to classify and quantify predominantly open microfractures in the subsurface Tengiz and Korolev carbonate reservoirs of western Kazakhstan. Microfractures, previously unknown in these fields, occur in nearly all of hundreds of the thin sections examined using transmitted-light (TL) and confocal microscopy. This study, done in carbonate rocks, differs from most previous work on microfractures, which mainly concentrates on silica-bearing rocks (sandstones and granites) and sealed (cemented), rather than open, microfractures.Microfractures in Tengiz and Korolev rocks are obscure or invisible using TL petrography. However, they are clearly visible in high-resolution (0.2 μm/pixel) laser-scanning confocal images. In decreasing order of abundance, we observed the following microfracture types: (1) dissolution-enlarged microfractures, (2) mosaic microfractures, (3) sealed and partially sealed microfractures lined with carbonate cement and/or bitumen, (4) intercrystalline microfractures in echinoderm fragments and coarse blocky calcite cements, (5) en echelon microfractures, (6) sediment-filled microfractures, (7) microfaults and deformation bands, (8) microfracture ganglia, and (9) reaction halos in the matrix near open microfractures. All microfracture types are interpreted to be natural, as opposed to induced features.Microfracture quantification, used here to determine the amount of open microfracture porosity in two-dimensional confocal images, has been applied to more than 300 samples. Microfracture porosity typically ranges from 0.2 to 1.0 porosity units. Aperture widths are generally on the order of 0.2 to 10 μm.A unique feature of this study is the relationship between dynamic properties and the amounts and types of microfractures observed in the rocks. Specifically, microfracture abundance relates to the effect of variable confining pressure on porosity and permeability in core plugs. Samples in which total confocal porosity is dominated (>80%) by microfractures, mainly upper-slope boundstones, showed moderate decreases in porosity and major decreases in permeability as a function of increased confining pressure. Samples in which microfractures are a relatively minor component (<20%) of total confocal porosity, mainly middle-slope breccias and grainstones and outer-platform grainstones, showed significantly smaller decreases in porosity and permeability as a function of increased confining pressure. Hysteresis effects, especially for permeability, are common. In conclusion, in reservoirs with open microfractures, core-plug scale permeability is subject to change with variable confining pressure. This mode of permeability variation should be considered in reservoir models conditioned by core-plug results.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141718834","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}
Nian Liu, Nansheng Qiu, Mingkuan Qin, Zhenming Li, Chuan Cai, Yuanjie Wang, Qiang Guo, Man Lu
Gas source and genetic type identification are important for gas system analysis and successful exploration. However, such crucial information is generally lacking or highly controversial in the northern Jizhong subbasin, Bohai Bay Basin, hindering further gas exploration. In this study, multiple genetic types of gases are identified in the northern Jizhong subbasin, including biogenic gas, coal-derived gas, and oil-associated gas. In particular, gases in the shallow Paleogene reservoirs are composed mainly of oil-associated gases derived from sapropelic organic matter in the Paleogene third member of the Shahejie Formation (Es3) and dark shales in the fourth member of the Shahejie and Kongdian Formations (Es4 + Ek). Gases in the deeply buried Ordovician and Carboniferous–Permian reservoirs are mainly derived from coal, with some contributions from oil-associated gases. The deep gases are mainly derived from the Carboniferous–Permian coal-bearing humic source rocks, with contributions from mixed organic matter in the Es4 + Ek source rocks. Biogenic gases, mainly present in the Paleogene Es3 reservoirs, are dominated by secondary microbially generated gas via CO2 reduction. Microbially generated gases are probably derived from sapropelic organic matter in the Es3 source rock. Based on the findings, it is concluded that shallow Paleogene rocks may be a favorable reservoir zone for primary (kerogen) cracking gases generated from type II1 kerogen. Dry gases derived from type III kerogen and secondary cracking gases from type II1 kerogen in the deep and ultradeep Ordovician and Precambrian–Cambrian reservoirs can be other potential exploration targets in the northern Jizhong subbasin.
气源和成因类型鉴定对于天然气系统分析和成功勘探非常重要。然而，在渤海湾盆地冀中北亚盆地，这些关键信息普遍缺乏或极具争议，阻碍了进一步的天然气勘探。本研究确定了冀中北亚盆地的多种气体成因类型，包括生物气、煤源气和石油伴生气。其中，浅层古近系储层中的气体主要由古近系沙河街地层第三系（Es3）中的皂质有机质和沙河街、孔店地层第四系（Es4+Ek）中的暗色页岩衍生的油伴生气组成。深埋奥陶系和石炭系-二叠系储层中的气体主要来自煤炭，部分来自石油伴生气。深层气体主要来自石炭纪-二叠纪含煤腐殖质源岩，Es4 + Ek 源岩中的混合有机物也有贡献。生物源气体主要存在于古近纪 Es3 储层中，主要是微生物通过二氧化碳还原作用产生的二次气体。微生物产生的气体可能来自Es3源岩中的溶胶有机物。根据研究结果，可以得出结论：浅古元古代岩石可能是 II1 型角质岩产生的原生（角质）裂解气的有利储集带。深奥陶系和超深奥陶系及前寒武-寒武系储层中的Ⅲ型角质产生的干气和Ⅱ1型角质产生的二次裂解气可能是冀中北亚盆地的其他潜在勘探目标。
{"title":"Geochemical characteristics, genetic types, and sources of gas accumulations in the northern Jizhong subbasin, Bohai Bay Basin, eastern China","authors":"Nian Liu, Nansheng Qiu, Mingkuan Qin, Zhenming Li, Chuan Cai, Yuanjie Wang, Qiang Guo, Man Lu","doi":"10.1306/10052322134","DOIUrl":"https://doi.org/10.1306/10052322134","url":null,"abstract":"Gas source and genetic type identification are important for gas system analysis and successful exploration. However, such crucial information is generally lacking or highly controversial in the northern Jizhong subbasin, Bohai Bay Basin, hindering further gas exploration. In this study, multiple genetic types of gases are identified in the northern Jizhong subbasin, including biogenic gas, coal-derived gas, and oil-associated gas. In particular, gases in the shallow Paleogene reservoirs are composed mainly of oil-associated gases derived from sapropelic organic matter in the Paleogene third member of the Shahejie Formation (Es3) and dark shales in the fourth member of the Shahejie and Kongdian Formations (Es4 + Ek). Gases in the deeply buried Ordovician and Carboniferous–Permian reservoirs are mainly derived from coal, with some contributions from oil-associated gases. The deep gases are mainly derived from the Carboniferous–Permian coal-bearing humic source rocks, with contributions from mixed organic matter in the Es4 + Ek source rocks. Biogenic gases, mainly present in the Paleogene Es3 reservoirs, are dominated by secondary microbially generated gas via CO2 reduction. Microbially generated gases are probably derived from sapropelic organic matter in the Es3 source rock. Based on the findings, it is concluded that shallow Paleogene rocks may be a favorable reservoir zone for primary (kerogen) cracking gases generated from type II1 kerogen. Dry gases derived from type III kerogen and secondary cracking gases from type II1 kerogen in the deep and ultradeep Ordovician and Precambrian–Cambrian reservoirs can be other potential exploration targets in the northern Jizhong subbasin.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141522790","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}
With the rapid development of the petroleum industry, oil and gas exploration gradually changes from conventional shallow and middle-depth reservoirs to deep and ultradeep reservoirs. In western China, especially in the Tarim Basin, the deep Ordovician and ultradeep Cambrian carbonate is the most important hydrocarbon reservoir. But because of complex near-surface conditions and complicated subsurface structures, high-precision seismic imaging for such deep and ultradeep reservoirs is still challenging with the state-of-art migration methods. One of the critical factors is that the reflections from deep and ultradeep strata cannot be coherently stacked in the migration because of accumulative traveltime errors caused by an inaccurate velocity model. To mitigate this issue, we present a coherent-stack-based least-squares migration (LSM) approach to improve the imaging quality for deep and ultradeep structures. Unlike traditional LSM that uses the stacked gradient during iterations, the proposed method updates the reflectivity model in the subsurface half-opening angle domain and then applies a coherent stacking to implement constructive summation for angle-domain common-image gathers. The new LSM scheme enables us to reduce the artifacts caused by an inaccurate velocity model and produces high-quality images for deep and ultradeep strata. Two models with typical steep-dipping faults, overthrust folds, and fault-karst carbonate reservoirs are designed to test the feasibility of the proposed method, and a field data set from a land survey is used to demonstrate its adaptability for low signal-to-noise ratio data.
{"title":"High-precision seismic imaging for complex deep structures in the hydrocarbon exploration using a coherent-stacking-based least-squares migration","authors":"Jidong Yang, Jianping Huang, Tengfei Lin, Zhenchun Li, Liang Chen","doi":"10.1306/10192321180","DOIUrl":"https://doi.org/10.1306/10192321180","url":null,"abstract":"With the rapid development of the petroleum industry, oil and gas exploration gradually changes from conventional shallow and middle-depth reservoirs to deep and ultradeep reservoirs. In western China, especially in the Tarim Basin, the deep Ordovician and ultradeep Cambrian carbonate is the most important hydrocarbon reservoir. But because of complex near-surface conditions and complicated subsurface structures, high-precision seismic imaging for such deep and ultradeep reservoirs is still challenging with the state-of-art migration methods. One of the critical factors is that the reflections from deep and ultradeep strata cannot be coherently stacked in the migration because of accumulative traveltime errors caused by an inaccurate velocity model. To mitigate this issue, we present a coherent-stack-based least-squares migration (LSM) approach to improve the imaging quality for deep and ultradeep structures. Unlike traditional LSM that uses the stacked gradient during iterations, the proposed method updates the reflectivity model in the subsurface half-opening angle domain and then applies a coherent stacking to implement constructive summation for angle-domain common-image gathers. The new LSM scheme enables us to reduce the artifacts caused by an inaccurate velocity model and produces high-quality images for deep and ultradeep strata. Two models with typical steep-dipping faults, overthrust folds, and fault-karst carbonate reservoirs are designed to test the feasibility of the proposed method, and a field data set from a land survey is used to demonstrate its adaptability for low signal-to-noise ratio data.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":null,"pages":null},"PeriodicalIF":3.5,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141522792","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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