A. Mangione, N. Schofield, S. Holford, C. Grove, C. Ellis, C. Forster, O. Schenk, D. Gardiner, B. Hedley, L. Broadley, J.R. Underhill
Previous basin modelling of the Faroe-Shetland Basin (FSB, offshore UK) has suggested mid-Cretaceous petroleum generation, which predates the deposition of the working Paleogene reservoirs and traps. To justify the time discrepancy between generation, reservoir and trap formation, factors such as intermediary accumulations and overpressure have been invoked. However, across much of the FSB, the Cretaceous sequences that overly the Kimmeridgian source rock are heavily intruded by Paleogene-aged intrusions. Recent modelling has shown that the emplacement of the intrusions, coupled with lower radiogenic heat production from underlying basement, leads to estimates of petroleum generation occurring up to 40 Myr more recently than suggested by previous models. In this work, we seek to better understand the role that igneous intrusions have exerted on petroleum generation and migration in the FSB. Models with varying thicknesses of Paleogene intrusions are compared with those that consider the Cretaceous sequence as purely sedimentary (i.e. similar to assumptions in previous modelling). The estimated times of petroleum generation are compared with geochronological constraints on the ages of oils (i.e. 90-68 Ma) and deposition and formation of other petroleum system elements. By considering only the effect of igneous intrusions, the expulsion onset from the source rocks is retarded by up to approximately 12 Myr. In addition, our models show the impact of the intrusions on petroleum saturation and migration suggesting that intrusions have potentially compartmentalised the basin, trapping petroleum beneath or within the sill complex. Finally, our findings suggest that basin models in regions impacted by significant magmatism need to consider the impact of intrusions to more accurately constrain both petroleum generation and migration. Thematic collection: This article is part of the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin
{"title":"Petroleum generation and migration through the Faroe-Shetland Basin - The role of Igneous Intrusions","authors":"A. Mangione, N. Schofield, S. Holford, C. Grove, C. Ellis, C. Forster, O. Schenk, D. Gardiner, B. Hedley, L. Broadley, J.R. Underhill","doi":"10.1144/petgeo2022-084","DOIUrl":"https://doi.org/10.1144/petgeo2022-084","url":null,"abstract":"Previous basin modelling of the Faroe-Shetland Basin (FSB, offshore UK) has suggested mid-Cretaceous petroleum generation, which predates the deposition of the working Paleogene reservoirs and traps. To justify the time discrepancy between generation, reservoir and trap formation, factors such as intermediary accumulations and overpressure have been invoked. However, across much of the FSB, the Cretaceous sequences that overly the Kimmeridgian source rock are heavily intruded by Paleogene-aged intrusions. Recent modelling has shown that the emplacement of the intrusions, coupled with lower radiogenic heat production from underlying basement, leads to estimates of petroleum generation occurring up to 40 Myr more recently than suggested by previous models. In this work, we seek to better understand the role that igneous intrusions have exerted on petroleum generation and migration in the FSB. Models with varying thicknesses of Paleogene intrusions are compared with those that consider the Cretaceous sequence as purely sedimentary (i.e. similar to assumptions in previous modelling). The estimated times of petroleum generation are compared with geochronological constraints on the ages of oils (i.e. 90-68 Ma) and deposition and formation of other petroleum system elements. By considering only the effect of igneous intrusions, the expulsion onset from the source rocks is retarded by up to approximately 12 Myr. In addition, our models show the impact of the intrusions on petroleum saturation and migration suggesting that intrusions have potentially compartmentalised the basin, trapping petroleum beneath or within the sill complex. Finally, our findings suggest that basin models in regions impacted by significant magmatism need to consider the impact of intrusions to more accurately constrain both petroleum generation and migration. Thematic collection: This article is part of the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134912044","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Philipp Müller, Christian Hermanrud, Haakon Fossen
Fault permeability prediction typically relies on empirical relationships between permeability and clay content or burial depth. Calibration of such methods relies on either core data or subsurface observations of fluid pressure and hydrocarbon contact offsets across faults. Published core data suggest that no relationships exist between host rock clay content and fault permeability for phyllosilicate-framework fault rocks, whereas published subsurface calibration data suggest otherwise. We here present a new method for calibration of fault rock permeabilities to subsurface pressure data. This approach is an analogue from electrical engineering to compute fault permeabilities across all major faults in a study area and optimise depth and clay content dependence of fault permeabilities. We tested this method at the Jurassic section of the Norwegian Njord Field area, where faults span the depth range of 2.7- 4.5 km and the lowest clay content in individual faults varies between 8.9 to 25.7%. The flow-restricting faults at Njord are phyllosilicate-framework fault rocks. Our modelling shows that fault rock permeability decreases with burial depth, whereas the clay content has nearly no impact. Sensitivity analyses show that these results are robust. Therefore, SGR-based algorithms for fault seal prediction cannot be expected to give good fault permeability predictions for seismic-scale faults at Njord. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022 Supplementary material: https://doi.org/10.6084/m9.figshare.c.6824325
{"title":"A new approach to investigate the effect of burial depth and clay content on fault permeabilities applied at the Njord Field","authors":"Philipp Müller, Christian Hermanrud, Haakon Fossen","doi":"10.1144/petgeo2023-025","DOIUrl":"https://doi.org/10.1144/petgeo2023-025","url":null,"abstract":"Fault permeability prediction typically relies on empirical relationships between permeability and clay content or burial depth. Calibration of such methods relies on either core data or subsurface observations of fluid pressure and hydrocarbon contact offsets across faults. Published core data suggest that no relationships exist between host rock clay content and fault permeability for phyllosilicate-framework fault rocks, whereas published subsurface calibration data suggest otherwise. We here present a new method for calibration of fault rock permeabilities to subsurface pressure data. This approach is an analogue from electrical engineering to compute fault permeabilities across all major faults in a study area and optimise depth and clay content dependence of fault permeabilities. We tested this method at the Jurassic section of the Norwegian Njord Field area, where faults span the depth range of 2.7- 4.5 km and the lowest clay content in individual faults varies between 8.9 to 25.7%. The flow-restricting faults at Njord are phyllosilicate-framework fault rocks. Our modelling shows that fault rock permeability decreases with burial depth, whereas the clay content has nearly no impact. Sensitivity analyses show that these results are robust. Therefore, SGR-based algorithms for fault seal prediction cannot be expected to give good fault permeability predictions for seismic-scale faults at Njord.\u0000 \u0000 Thematic collection:\u0000 This article is part of the Fault and top seals 2022 collection available at:\u0000 https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022\u0000 \u0000 \u0000 Supplementary material:\u0000 https://doi.org/10.6084/m9.figshare.c.6824325","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135981768","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study presents the results of a joint Chemostrat – APT study that aimed to produce a suite of Radioactive Heat Production (RHP) data for basement rocks in the Faroe Shetland Basin to enable more accurate basin modelling to be undertaken. To enable regional studies to be undertaken, the basement has been split into four zones based on similarities. Zone A is formed of high grade metamorphic basement from the Rockall trough (quads 154 & 164) southwest of the “Laxfordian front” postulated by Holdsworth et al., (2019). Zone B comprises granodioritic, tonalitic and dioritic Neoarchean aged (2700-2830 Ma) high grade metamorphic basement from the southwest of the Rona Ridge and Basin (wells 202/08-1, 204/15-2, 205/161, 205/21-1A, 206/7a-2, 206/08-2, 206/09-2 and 206/12-1) and northeast of the Laxfordian front. Zone C contains Neoarchean aged high grade metamorphic basement of a predominantly granitic and quartz rich granitoid composition from the northeast of the Rona Ridge (wells 207/01-3, 207/02-1, 208/23-1 and 208/26-1). Zone D differs from the rest of the material in this study in that it is Caledonian (∼460 Ma) granitic plutonic basement from Quads 209 (Ereland volcanic centre). Radioactive heat production values were derived from Potassium, Thorium and Uranium data produced from the analysis of eighty-four basement samples by ICP-OES and ICP-MS analysis. Each mapped basement zone was then assigned a mean radioactive heat production value for use in future basin modelling studies; Zone A = 0.21 µWm 3 , Zone B, 0.64 µWm 3 , zone C = 0.88 µWm 3 and zone D = 2.1 µWm 3 . Thematic collection: This article is part of the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin Supplementary material: https://doi.org/10.6084/m9.figshare.c.6771540
{"title":"Radioactive Heat Production variations in the Faroe-Shetland Basin: key new heat production, geological and geochronological data for regional and local basin modelling","authors":"A. Finlay, D. Wray, Guy Comfort, Julian Moore","doi":"10.1144/petgeo2022-039","DOIUrl":"https://doi.org/10.1144/petgeo2022-039","url":null,"abstract":"\u0000 This study presents the results of a joint Chemostrat – APT study that aimed to produce a suite of Radioactive Heat Production (RHP) data for basement rocks in the Faroe Shetland Basin to enable more accurate basin modelling to be undertaken. To enable regional studies to be undertaken, the basement has been split into four zones based on similarities. Zone A is formed of high grade metamorphic basement from the Rockall trough (quads 154 & 164) southwest of the “Laxfordian front” postulated by Holdsworth et al., (2019). Zone B comprises granodioritic, tonalitic and dioritic Neoarchean aged (2700-2830 Ma) high grade metamorphic basement from the southwest of the Rona Ridge and Basin (wells 202/08-1, 204/15-2, 205/161, 205/21-1A, 206/7a-2, 206/08-2, 206/09-2 and 206/12-1) and northeast of the Laxfordian front. Zone C contains Neoarchean aged high grade metamorphic basement of a predominantly granitic and quartz rich granitoid composition from the northeast of the Rona Ridge (wells 207/01-3, 207/02-1, 208/23-1 and 208/26-1). Zone D differs from the rest of the material in this study in that it is Caledonian (∼460 Ma) granitic plutonic basement from Quads 209 (Ereland volcanic centre). Radioactive heat production values were derived from Potassium, Thorium and Uranium data produced from the analysis of eighty-four basement samples by ICP-OES and ICP-MS analysis. Each mapped basement zone was then assigned a mean radioactive heat production value for use in future basin modelling studies; Zone A = 0.21 µWm\u0000 3\u0000 , Zone B, 0.64 µWm\u0000 3\u0000 , zone C = 0.88 µWm\u0000 3\u0000 and zone D = 2.1 µWm\u0000 3\u0000 .\u0000 \u0000 \u0000 Thematic collection:\u0000 This article is part of the UKCS Atlantic Margin collection available at:\u0000 https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin\u0000 \u0000 \u0000 Supplementary material:\u0000 https://doi.org/10.6084/m9.figshare.c.6771540\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49452641","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Basso, G. Chinelatto, A. M. P. Belila, L. Mendes, J. P. Souza, D. Stefanelli, A. Vidal, J. F. Bueno
Precise knowledge on the spatial distribution patterns of non-matrix porosity zones and the establishment of the geological factors controlling their evolution is crucial for building more accurate carbonate reservoir models and improve hydrocarbon production. The occurrence of intervals affected by significant carbonate dissolution may result in drilling fluid loss and time-consuming drawbacks during well construction. Vug or cave-rich reservoirs may exhibit excess permeability and extremely high initial flow rates. Similar situations have been reported in exploration activities in the Brazilian Pre-Salt plays, where evidence of dissolution and other burial diagenetic processes, such as severe silicification and dolomitization, are common. In this study, we investigate evidence of major post-depositional changes in the lacustrine carbonate reservoirs of the Barra Velha Formation, which comprises the most prolific hydrocarbon play in Brazil. Using a comprehensive database comprising both core samples and well-log data from a vertical well in the Santos Basin, we have characterized, at multiple scales, reservoir zones affected by silicification and carbonate dissolution. Additionally, we performed a petrophysical evaluation of the reservoir to understand the impact of such processes on porosity and permeability development. The results suggested an intimate relationship between silicification and dissolution processes, which can be associated to late fluid percolation under a deep burial flow regime. The occurrence of silicified and vuggy beds, associated with specific zones and lithofacies, indicates an important degree of stratigraphic control on fluid percolation and lateral migration. Furthermore, the presence of fractures at discrete stratigraphic levels have preferentially influenced the development of high-permeability zones, including metric scale fracture-related conduits. This study contributes to the general knowledge of carbonate reservoirs affected by silicification and dissolution while providing support for the recognition of such processes in partially- or non-cored wells.
{"title":"Characterization of silicification and dissolution zones by integrating borehole image logs and core samples: A case study of a well from the Brazilian Pre-salt","authors":"M. Basso, G. Chinelatto, A. M. P. Belila, L. Mendes, J. P. Souza, D. Stefanelli, A. Vidal, J. F. Bueno","doi":"10.1144/petgeo2022-044","DOIUrl":"https://doi.org/10.1144/petgeo2022-044","url":null,"abstract":"Precise knowledge on the spatial distribution patterns of non-matrix porosity zones and the establishment of the geological factors controlling their evolution is crucial for building more accurate carbonate reservoir models and improve hydrocarbon production. The occurrence of intervals affected by significant carbonate dissolution may result in drilling fluid loss and time-consuming drawbacks during well construction. Vug or cave-rich reservoirs may exhibit excess permeability and extremely high initial flow rates. Similar situations have been reported in exploration activities in the Brazilian Pre-Salt plays, where evidence of dissolution and other burial diagenetic processes, such as severe silicification and dolomitization, are common. In this study, we investigate evidence of major post-depositional changes in the lacustrine carbonate reservoirs of the Barra Velha Formation, which comprises the most prolific hydrocarbon play in Brazil. Using a comprehensive database comprising both core samples and well-log data from a vertical well in the Santos Basin, we have characterized, at multiple scales, reservoir zones affected by silicification and carbonate dissolution. Additionally, we performed a petrophysical evaluation of the reservoir to understand the impact of such processes on porosity and permeability development. The results suggested an intimate relationship between silicification and dissolution processes, which can be associated to late fluid percolation under a deep burial flow regime. The occurrence of silicified and vuggy beds, associated with specific zones and lithofacies, indicates an important degree of stratigraphic control on fluid percolation and lateral migration. Furthermore, the presence of fractures at discrete stratigraphic levels have preferentially influenced the development of high-permeability zones, including metric scale fracture-related conduits. This study contributes to the general knowledge of carbonate reservoirs affected by silicification and dissolution while providing support for the recognition of such processes in partially- or non-cored wells.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-07-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48463130","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In Tunisia Chotts Basin, the upper Silurian (Ludfordian) Fegaguira Formation comprises, organic-rich black mudstones deposited during a major anoxic event. It is a prolific source rock having yielded a large volume of oil and gas from conventional reservoirs that reached about 69 MMB OE with around 45MM BOE as recoverable reserves still to be produced. Based on various investigations, the stratigraphy of the Fegaguira Formation is updated and its unconventional play potential is assessed. It is divided, in the present work, into three units (HSII.1, HSII.2, and HSII.3) characterized by gamma-ray values up to 400 API, organic matter content (up to 17wt. % TOC), and petroleum potential (up to 60mg HC/g rock) with mature Type II marine kerogen. The first and the second units which are dominantly organic-rich mudstones can be compared to the Barnett, Antelope, and Tuscaloosa. Evaluation of the brittleness index shows that the HSII.1 and 2 units are mostly ductile and comparable to tight oil and gas reservoirs, while the HSII.3 third unit, where organic-rich facies are juxtaposed to organic-lean limestone beds with natural fractures (porosity between 3 and 7% ), may be compared to the Niobrara B formation. Within the shale-oil fairway of the Chotts basin, the estimated recoverable oil is around 1.3 billion bbl. It is comparable to the recoverable oil estimated volume for the Middle Member of the Bakken in the USA. This study demonstrates that the Fegaguira source rock should be considered as an additional unconventional oil-shale target for Tunisia.
{"title":"New insights on the upper Silurian Fegaguira shale oil play in the Chotts Basin (Southern Tunisia)","authors":"A. B. Mohamed, M. Soussi, M. Saidi, D. Jarvie","doi":"10.1144/petgeo2023-015","DOIUrl":"https://doi.org/10.1144/petgeo2023-015","url":null,"abstract":"In Tunisia Chotts Basin, the upper Silurian (Ludfordian) Fegaguira Formation comprises, organic-rich black mudstones deposited during a major anoxic event. It is a prolific source rock having yielded a large volume of oil and gas from conventional reservoirs that reached about 69 MMB OE with around 45MM BOE as recoverable reserves still to be produced. Based on various investigations, the stratigraphy of the Fegaguira Formation is updated and its unconventional play potential is assessed.\u0000 It is divided, in the present work, into three units (HSII.1, HSII.2, and HSII.3) characterized by gamma-ray values up to 400 API, organic matter content (up to 17wt. % TOC), and petroleum potential (up to 60mg HC/g rock) with mature Type II marine kerogen. The first and the second units which are dominantly organic-rich mudstones can be compared to the Barnett, Antelope, and Tuscaloosa.\u0000 Evaluation of the brittleness index shows that the HSII.1 and 2 units are mostly ductile and comparable to tight oil and gas reservoirs, while the HSII.3 third unit, where organic-rich facies are juxtaposed to organic-lean limestone beds with natural fractures (porosity between 3 and 7% ), may be compared to the Niobrara B formation.\u0000 Within the shale-oil fairway of the Chotts basin, the estimated recoverable oil is around 1.3 billion bbl. It is comparable to the recoverable oil estimated volume for the Middle Member of the Bakken in the USA. This study demonstrates that the Fegaguira source rock should be considered as an additional unconventional oil-shale target for Tunisia.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-07-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41567348","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ahmed Y. Tawfik, R. Ondrak, G. Winterleitner, M. Mutti
We integrated geological and 2D basin modeling to investigate the tectonostratigraphic evolution of the East Beni Suef Basin (EBSB) of north central Egypt and its implications for the Upper Cretaceous petroleum system. Two intersecting seismic sections and three exploration wells were used for this study. The geological model defines the structural and geometrical framework of the basin, which formed the basis for subsequent 2D basin modeling. The developed basin models were calibrated and fine-tuned using vitrinite reflectance and corrected temperature data. Modeling results indicate that the Abu Roash “F” source rock maturity ranges from the early oil window at the basin margins to the main oil window in the center. The main phase of hydrocarbon generation occurred during the Eocene after trap formation in the Late Cretaceous. Generated hydrocarbons have migrated both laterally and vertically, most likely from the central part of the basin toward the basin margins, particularly eastward to the structural traps. The model predicts low accumulation rates for the EBSB, which are caused by the ineffective sealing capacity of the overburden rocks and normal faults. In addition to the proven kitchen for the charging of the Abu Roash “E” reservoirs, an additional kitchen area to the northwest of the basin is suggested for the Abu Roash “G” reservoirs. Basin modeling provides a powerful approach to examining subsurface geology, reconstructing the evolution of sedimentary basins through time, and evaluating potential prospects of the associated petroleum systems by integrating fundamental aspects from geology, geophysics, and geochemistry (Poelchau et al. 1997; Hantschel and Kauerauf 2009; Peters et al. 2017). Reliability and validity of basin models require integrating multidisciplinary data and methods to maximize the understanding of the various interrelated controls on petroleum systems (Ungerer et al. 1990; Rudkiewicz et al. 2000; Verweij et al. 2000; Mosca et al. 2017; Khan et al. 2022; Mahdi et al. 2022). Integrated basin modeling studies contribute to constraining the put-forward assumptions, minimizing the potential uncertainties, and reducing exploration risk by investigating different scenarios and hypotheses.
利用地质建模和二维盆地建模相结合的方法，研究了埃及中北部东贝尼苏夫盆地(EBSB)的构造地层演化及其对上白垩统含油气系统的影响。本研究采用了2个相交地震剖面和3口勘探井。地质模型确定了盆地的构造和几何格架，为后续的二维盆地建模奠定了基础。利用镜质组反射率和校正后的温度数据，对开发的盆地模型进行了校准和微调。模拟结果表明，Abu Roash“F”烃源岩成熟度范围从盆地边缘的早期油窗到中部的主油窗。晚白垩世圈闭形成后始新世为主要生烃期。生成的油气在横向和纵向上都有运移，最有可能从盆地中部向盆地边缘运移，特别是向东运移到构造圈闭。该模型预测，由于上覆岩和正断层的封闭能力不强，沉积速率较低。除了Abu Roash“E”水库的厨房外，还建议在盆地西北部为Abu Roash“G”水库增加一个厨房区。通过整合地质学、地球物理学和地球化学的基本方面，盆地建模提供了一种强有力的方法来检查地下地质，重建沉积盆地随时间的演化，并评估相关石油系统的潜在前景(Poelchau等人，1997;Hantschel and Kauerauf 2009;Peters et al. 2017)。盆地模型的可靠性和有效性需要综合多学科数据和方法，以最大限度地了解对石油系统的各种相互关联的控制(Ungerer等，1990;Rudkiewicz et al. 2000;Verweij et al. 2000;Mosca et al. 2017;Khan et al. 2022;Mahdi et al. 2022)。综合盆地建模研究通过研究不同的情景和假设，有助于约束提出的假设，最大限度地减少潜在的不确定性，并降低勘探风险。
{"title":"The Upper Cretaceous Petroleum System of the East Beni Suef Basin, Egypt: An Integrated Geological and 2D Basin Modeling Approach","authors":"Ahmed Y. Tawfik, R. Ondrak, G. Winterleitner, M. Mutti","doi":"10.1144/petgeo2022-077","DOIUrl":"https://doi.org/10.1144/petgeo2022-077","url":null,"abstract":"We integrated geological and 2D basin modeling to investigate the tectonostratigraphic evolution of the East Beni Suef Basin (EBSB) of north central Egypt and its implications for the Upper Cretaceous petroleum system. Two intersecting seismic sections and three exploration wells were used for this study. The geological model defines the structural and geometrical framework of the basin, which formed the basis for subsequent 2D basin modeling. The developed basin models were calibrated and fine-tuned using vitrinite reflectance and corrected temperature data. Modeling results indicate that the Abu Roash “F” source rock maturity ranges from the early oil window at the basin margins to the main oil window in the center. The main phase of hydrocarbon generation occurred during the Eocene after trap formation in the Late Cretaceous. Generated hydrocarbons have migrated both laterally and vertically, most likely from the central part of the basin toward the basin margins, particularly eastward to the structural traps. The model predicts low accumulation rates for the EBSB, which are caused by the ineffective sealing capacity of the overburden rocks and normal faults. In addition to the proven kitchen for the charging of the Abu Roash “E” reservoirs, an additional kitchen area to the northwest of the basin is suggested for the Abu Roash “G” reservoirs.\u0000 \u0000 Basin modeling provides a powerful approach to examining subsurface geology, reconstructing the evolution of sedimentary basins through time, and evaluating potential prospects of the associated petroleum systems by integrating fundamental aspects from geology, geophysics, and geochemistry (Poelchau\u0000 et al.\u0000 1997; Hantschel and Kauerauf 2009; Peters\u0000 et al.\u0000 2017). Reliability and validity of basin models require integrating multidisciplinary data and methods to maximize the understanding of the various interrelated controls on petroleum systems (Ungerer\u0000 et al.\u0000 1990; Rudkiewicz\u0000 et al.\u0000 2000; Verweij\u0000 et al.\u0000 2000; Mosca\u0000 et al.\u0000 2017; Khan\u0000 et al.\u0000 2022; Mahdi\u0000 et al.\u0000 2022). Integrated basin modeling studies contribute to constraining the put-forward assumptions, minimizing the potential uncertainties, and reducing exploration risk by investigating different scenarios and hypotheses.\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-07-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41540554","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Interpretation of seismic data over the south-eastern flank of the Eratosthenes High shows nine principal seismic stratigraphic units overlying probable faulted basement. Among these are three superposed carbonate platforms which build a stratigraphy exceeding 3000 m. Regional comparisons suggest these range in age from Jurassic to Miocene. The Jurassic carbonate platform exhibits layered stratigraphy and aggradational deposition style over the whole study area. A Lower Cretaceous platform subsequently developed as a linear, aggrading bank and prograded as multiple high-frequency sequences for over 40 km into the Eratosthenes High interior, isolating an intrashelf basin which remained connected to the Levant Basin by a narrow seaway. The Jurassic platform margin was a fault-controlled, scalloped escarpment, while the mid-Cretaceous platform was strongly influenced by linear, northwest-southeast-orientated, fault-controlled sags. The Miocene platform, a shoaling, “catch-up” neritic shelf, was established after a hiatus during which the flat top of the Cretaceous platform lay below the photic zone. The Miocene platform surface was subsequently incised by Messinian erosional channels which fed offlapping and down-stepping regressive carbonate or evaporitic shorelines that tracked Messinian sea-level fall. Updoming and segmentation of the Eratosthenes high occurred during the early Messinian prior to emplacement of Messinian salt onto its flanks.
{"title":"Seismic stratigraphy of southern Eratosthenes High, eastern Mediterranean Sea: growth, demise and deformation of three superposed carbonate platforms (Mesozoic-Cenozoic)","authors":"T. Burchette, Gavrielle Groves-Gidney, K. Karcz","doi":"10.1144/petgeo2023-017","DOIUrl":"https://doi.org/10.1144/petgeo2023-017","url":null,"abstract":"Interpretation of seismic data over the south-eastern flank of the Eratosthenes High shows nine principal seismic stratigraphic units overlying probable faulted basement. Among these are three superposed carbonate platforms which build a stratigraphy exceeding 3000 m. Regional comparisons suggest these range in age from Jurassic to Miocene.\u0000 The Jurassic carbonate platform exhibits layered stratigraphy and aggradational deposition style over the whole study area. A Lower Cretaceous platform subsequently developed as a linear, aggrading bank and prograded as multiple high-frequency sequences for over 40 km into the Eratosthenes High interior, isolating an intrashelf basin which remained connected to the Levant Basin by a narrow seaway. The Jurassic platform margin was a fault-controlled, scalloped escarpment, while the mid-Cretaceous platform was strongly influenced by linear, northwest-southeast-orientated, fault-controlled sags.\u0000 The Miocene platform, a shoaling, “catch-up” neritic shelf, was established after a hiatus during which the flat top of the Cretaceous platform lay below the photic zone. The Miocene platform surface was subsequently incised by Messinian erosional channels which fed offlapping and down-stepping regressive carbonate or evaporitic shorelines that tracked Messinian sea-level fall. Updoming and segmentation of the Eratosthenes high occurred during the early Messinian prior to emplacement of Messinian salt onto its flanks.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-07-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45656946","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
V. Romano, S. Bigi, Heeho D. Park, A. Valocchi, J. Hyman, S. Karra, M. Nole, Glenn Hammond, G. Proietti, M. Battaglia
Understanding whether fractures and faults impact the CO 2 migration through the overburden is critical in the evaluation and monitoring of CO 2 geological storage sites. We present a numerical model and workflow to describe the hydraulic behaviour of a fault located in the shallow part of the overburden. This helps to evaluate the sealing potential of the system in case of unwanted CO 2 migration toward the surface and to design an efficient monitoring plan. The model configuration is representative of several experiments performed at real sites under quite shallow conditions (50-500 m). The model results, applied to a selected fault outcropping in the Apennines (Italy), show that most of the gas migrates through the high, while some of the gas also migrates through the fault core in the hanging wall damage zone. A significant amount of gas then dissolves into the water, emphasizing the importance of accurate modelling to assess the hazard of CO 2 leakage into near-surface aquifers or to the surface. The occurrence of pressure buildup close to the fault core points out that detailed modelling of the migration conditions is required to predict gas path through a fault zone. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
{"title":"A numerical model and workflow for gas CO\u0000 2\u0000 injection and migration in a fault zone","authors":"V. Romano, S. Bigi, Heeho D. Park, A. Valocchi, J. Hyman, S. Karra, M. Nole, Glenn Hammond, G. Proietti, M. Battaglia","doi":"10.1144/petgeo2022-092","DOIUrl":"https://doi.org/10.1144/petgeo2022-092","url":null,"abstract":"\u0000 Understanding whether fractures and faults impact the CO\u0000 2\u0000 migration through the overburden is critical in the evaluation and monitoring of CO\u0000 2\u0000 geological storage sites. We present a numerical model and workflow to describe the hydraulic behaviour of a fault located in the shallow part of the overburden. This helps to evaluate the sealing potential of the system in case of unwanted CO\u0000 2\u0000 migration toward the surface and to design an efficient monitoring plan. The model configuration is representative of several experiments performed at real sites under quite shallow conditions (50-500 m). The model results, applied to a selected fault outcropping in the Apennines (Italy), show that most of the gas migrates through the high, while some of the gas also migrates through the fault core in the hanging wall damage zone. A significant amount of gas then dissolves into the water, emphasizing the importance of accurate modelling to assess the hazard of CO\u0000 2\u0000 leakage into near-surface aquifers or to the surface. The occurrence of pressure buildup close to the fault core points out that detailed modelling of the migration conditions is required to predict gas path through a fault zone.\u0000 \u0000 \u0000 Thematic collection:\u0000 This article is part of the Fault and top seals 2022 collection available at:\u0000 https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-07-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43458507","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Parnell, J. Armstrong, N. Blamey, A. Boyce, A. Schito, D. Muirhead
Carbonaceous shales in the Southern Uplands-Down-Longford Terrane accretionary prism had extremely high potential for hydrocarbon generation in the Lower Paleozoic. Structural thickening in the prism enhanced the rapid generation of oil. Shale horizons are separated by thick turbidites composed of low-permeability greywackes, so oil under high fluid pressure either pooled along shale bedding surfaces or migrated into fractured greywackes. Pooled oil became solidified to bitumen, which locally formed deposits on a scale of tonnes, mined as coal. The carbon-rich shale also sequestered large amounts of sulfur from seawater, which precipitated as pyrite firstly during early diagenesis, then further during fluid flow through the shale beds. The oil was also sulfur-bearing. Deformation focused on the shale beds during the evolution of the accretionary prism would have been closely related to the fluid flow which precipitated bitumen and sulfides. The palaeo-fluids were also anomalously rich in methane and hydrogen, similar to fluids venting from modern accretionary prisms. Supplementary material: details of localities searched for coal in Lower Palaeozoic, Southern Uplands-Down-Longford Terrane (locations shown in Fig. 6 ) are available at https://doi.org/10.6084/m9.figshare.c.6691597
{"title":"The role of organic carbon in the Southern Uplands-Down-Longford Terrane accretionary prism, Scotland and Ireland","authors":"J. Parnell, J. Armstrong, N. Blamey, A. Boyce, A. Schito, D. Muirhead","doi":"10.1144/petgeo2022-059","DOIUrl":"https://doi.org/10.1144/petgeo2022-059","url":null,"abstract":"Carbonaceous shales in the Southern Uplands-Down-Longford Terrane accretionary prism had extremely high potential for hydrocarbon generation in the Lower Paleozoic. Structural thickening in the prism enhanced the rapid generation of oil. Shale horizons are separated by thick turbidites composed of low-permeability greywackes, so oil under high fluid pressure either pooled along shale bedding surfaces or migrated into fractured greywackes. Pooled oil became solidified to bitumen, which locally formed deposits on a scale of tonnes, mined as coal. The carbon-rich shale also sequestered large amounts of sulfur from seawater, which precipitated as pyrite firstly during early diagenesis, then further during fluid flow through the shale beds. The oil was also sulfur-bearing. Deformation focused on the shale beds during the evolution of the accretionary prism would have been closely related to the fluid flow which precipitated bitumen and sulfides. The palaeo-fluids were also anomalously rich in methane and hydrogen, similar to fluids venting from modern accretionary prisms.\u0000 \u0000 Supplementary material:\u0000 details of localities searched for coal in Lower Palaeozoic, Southern Uplands-Down-Longford Terrane (locations shown in\u0000 Fig. 6\u0000 ) are available at\u0000 https://doi.org/10.6084/m9.figshare.c.6691597\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-06-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44725469","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The following chemostratigraphy study was completed on the Permo-Carboniferous Unayzah Group in Eastern Saudi Arabia. The aim of the study was to determine whether the technique could be used to identify formation and member boundaries on a subregional scale, with the area extending for approximately 550 Km in a NW-SE direction and 350 Km NE-SW. A total of 30,375 core and cuttings samples were analyzed from 225 wells using ICP (inductively Coupled Plasma) and XRF (X-ray Fluorescence) instruments, with data acquired for 42-53 elements for each sample in the range Na-U in the periodic table. Of these, details of 14 wells are discussed in the present work. Based on variations in Zr/Ti, Zr/U, Zr/Y, Y/U, U/Th, Gd/Zr, Nb/Yb and Nb/Th it is possible to identify a hierarchical order of one zone, fours subzones and five divisions, these chemozones being correlative on a subregional scale. By comparing geochemical, biostratigraphic, sedimentological and wireline log data in selected reference wells, it was possible to relate chemozones to particular members of the Unayzah Group. The differences in geochemistry between these chemozones/members is largely explained by changes in provenance, though depositional environment may have exerted at least some influence.
{"title":"Utilization of chemostratigraphy to the subregional scale correlation of Permo-Carboniferous sediments, eastern Saudi Arabia","authors":"N. Craigie, C. Scheibe","doi":"10.1144/petgeo2023-007","DOIUrl":"https://doi.org/10.1144/petgeo2023-007","url":null,"abstract":"The following chemostratigraphy study was completed on the Permo-Carboniferous Unayzah Group in Eastern Saudi Arabia. The aim of the study was to determine whether the technique could be used to identify formation and member boundaries on a subregional scale, with the area extending for approximately 550 Km in a NW-SE direction and 350 Km NE-SW. A total of 30,375 core and cuttings samples were analyzed from 225 wells using ICP (inductively Coupled Plasma) and XRF (X-ray Fluorescence) instruments, with data acquired for 42-53 elements for each sample in the range Na-U in the periodic table. Of these, details of 14 wells are discussed in the present work.\u0000 Based on variations in Zr/Ti, Zr/U, Zr/Y, Y/U, U/Th, Gd/Zr, Nb/Yb and Nb/Th it is possible to identify a hierarchical order of one zone, fours subzones and five divisions, these chemozones being correlative on a subregional scale. By comparing geochemical, biostratigraphic, sedimentological and wireline log data in selected reference wells, it was possible to relate chemozones to particular members of the Unayzah Group. The differences in geochemistry between these chemozones/members is largely explained by changes in provenance, though depositional environment may have exerted at least some influence.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41991490","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"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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