T. Bjørnarå, E. Skurtveit, E. Michie, Scott A. Smith
The article highlights the importance of understanding the permeability of fault zones as fluid migration pathways, with an example from the Vette Fault Zone in the North Sea. The study characterizes the hydraulic properties of the fault zone by mixing host rock lithologies into the fault zone and deriving the fault width from empirical relationships. A parametric study with 1125 model realizations was conducted to understand the sensitivity related to uncertainties in overburden lithologies and fault width correlations. The study found that the fault zone significantly alters the flow-field compared to a model that only considers lithological juxtaposition. The most significant hydraulic communication in the Vette Fault Zone is downwards from the storage reservoir where sand is mixed into the fault zone. The models highlight the potential for downward hydraulic communication along the fault for brine and CO 2 capillary sealing towards the overburden. Thematic collection: This article is part of the Fault and top seals collection available at: www.lyellcollection.org/topic/collections/fault-and-top-seals-2022
{"title":"Characterising along- and across-fault fluid flow properties for assessing flow rates and overburden fluid migration along faults - A case study from the North Sea","authors":"T. Bjørnarå, E. Skurtveit, E. Michie, Scott A. Smith","doi":"10.1144/petgeo2023-033","DOIUrl":"https://doi.org/10.1144/petgeo2023-033","url":null,"abstract":"\u0000 The article highlights the importance of understanding the permeability of fault zones as fluid migration pathways, with an example from the Vette Fault Zone in the North Sea. The study characterizes the hydraulic properties of the fault zone by mixing host rock lithologies into the fault zone and deriving the fault width from empirical relationships. A parametric study with 1125 model realizations was conducted to understand the sensitivity related to uncertainties in overburden lithologies and fault width correlations. The study found that the fault zone significantly alters the flow-field compared to a model that only considers lithological juxtaposition. The most significant hydraulic communication in the Vette Fault Zone is downwards from the storage reservoir where sand is mixed into the fault zone. The models highlight the potential for downward hydraulic communication along the fault for brine and CO\u0000 2\u0000 capillary sealing towards the overburden.\u0000 \u0000 \u0000 Thematic collection:\u0000 This article is part of the Fault and top seals collection available at:\u0000 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":"2023-06-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44913099","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}
Time-lapse or 4D Seismic data (4DS) are important constraints in reservoir studies because they enable monitoring of saturation and pressure changes that result from hydrocarbon production. 4DS have been quantitatively added, along with production data, in history matching or data assimilation (DA) procedures to reduce uncertainty and improve production forecasts. Before performing quantitative studies, it is important to ensure that the 4DS are reliable, with minimal artifacts such as side-lobe effects, that can disturb the identification of anomalies. In this work, we propose different ways of treating 4DS in DA for a real reservoir. Explicitly, we evaluated the impact on DA results when considering different amounts of 4D information and three treatments to the identified artifacts. The treatments were: ignoring them, excluding them from DA, or defining no seismic changes at their locations. The results show that well and seismic matches are improved when 4DS are assimilated, also improving the production predictions. Despite being a thin reservoir, assimilating two single-layer maps allowed us to predict relevant observed dynamic behaviour, such as the evolved gas trapped in the lower interval. Furthermore, when a treatment was applied to the artifacts, they produced better models than using a single two-layer map (with lower production errors and visually closer impedances to the observed data). Our recommendation is the assimilation of well and 4DS data, with the exclusion of unreliable information, for better life-cycle decisions.
{"title":"Evaluating the impact of 4D seismic data artifacts in data assimilation","authors":"Da Rosa, D. Schiozer, A. Davolio","doi":"10.1144/petgeo2022-069","DOIUrl":"https://doi.org/10.1144/petgeo2022-069","url":null,"abstract":"Time-lapse or 4D Seismic data (4DS) are important constraints in reservoir studies because they enable monitoring of saturation and pressure changes that result from hydrocarbon production. 4DS have been quantitatively added, along with production data, in history matching or data assimilation (DA) procedures to reduce uncertainty and improve production forecasts. Before performing quantitative studies, it is important to ensure that the 4DS are reliable, with minimal artifacts such as side-lobe effects, that can disturb the identification of anomalies. In this work, we propose different ways of treating 4DS in DA for a real reservoir. Explicitly, we evaluated the impact on DA results when considering different amounts of 4D information and three treatments to the identified artifacts. The treatments were: ignoring them, excluding them from DA, or defining no seismic changes at their locations. The results show that well and seismic matches are improved when 4DS are assimilated, also improving the production predictions. Despite being a thin reservoir, assimilating two single-layer maps allowed us to predict relevant observed dynamic behaviour, such as the evolved gas trapped in the lower interval. Furthermore, when a treatment was applied to the artifacts, they produced better models than using a single two-layer map (with lower production errors and visually closer impedances to the observed data). Our recommendation is the assimilation of well and 4DS data, with the exclusion of unreliable information, for better life-cycle decisions.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-05-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41691075","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}
Determining rock resistivity for saturation estimation in reservoirs is challenging due to the complex nature of pores in the rock. This paper aims to establish a computational relationship between formation factors ( F ) and permeability ( K ) by combining theoretical and experimental data. Firstly, the relationship between the permeability of the curved capillary model and formation factors, as well as the relationship between the permeability of the complex curved capillary model and formation factors, are deduced. Theoretical analysis proved that the formation factors( F ) have a power relationship with permeability( K ) and porosity ( φ ), and confirms the existence of additional resistivity ( R x ). To validate the the theoretical study, we conducted model analysis using open experimental data from thirty-five sandstone cores with different porosity and permeability from the tight gas sandstone in the Western U.S. Basins, which measured resistivity data in saline at 20ppm, 40ppm, and 80ppm, respectively. We confirmed the existences of additional resistivity ( R x ) by fitting the relationship between the rock resistivity of saturated formation water ( R o ) and the formation water resistivity ( R w ). We then fitted the formation resistivity change factor ( F d ) with permeability ( K ), the formation resistivity change factor ( F d ) with porosity ( φ ), the additional resistivity ( R x ) with permeability ( K ), and the additional resistivity ( R x ) with porosity ( φ ). Both changeable formation resistivity change factor ( F d ) and additional resistivity ( R x ) showed a strong linear relationship with permeability ( K ) in logarithmic coordinates. We also verified the existence of a suitable equation using available experimental data by changing formation parameters and permeability. The study shows that the fitting equations may be utilized to determine changeable formation resistivity change factor ( F d ), additional resistivity ( R x ), and the rock resistivity of saturated formation water ( R o ) with varying permeability. The predicted rock resistivity of saturated formation water ( R o ) strongly correlates with the one measured in the laboratory, providing better precision for future reservoir evaluation in saturation estimations.
{"title":"Estimating Additional Resistivity by Permeability in Brine Saturated Sandstones","authors":"Wenjun Zhao, Tangyan Liu, Jizhou Tang, J. Zhang","doi":"10.1144/petgeo2022-067","DOIUrl":"https://doi.org/10.1144/petgeo2022-067","url":null,"abstract":"\u0000 Determining rock resistivity for saturation estimation in reservoirs is challenging due to the complex nature of pores in the rock. This paper aims to establish a computational relationship between formation factors (\u0000 F\u0000 ) and permeability (\u0000 K\u0000 ) by combining theoretical and experimental data. Firstly, the relationship between the permeability of the curved capillary model and formation factors, as well as the relationship between the permeability of the complex curved capillary model and formation factors, are deduced. Theoretical analysis proved that the formation factors(\u0000 F\u0000 ) have a power relationship with permeability(\u0000 K\u0000 ) and porosity (\u0000 \u0000 \u0000 φ\u0000 \u0000 \u0000 ), and confirms the existence of additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ). To validate the the theoretical study, we conducted model analysis using open experimental data from thirty-five sandstone cores with different porosity and permeability from the tight gas sandstone in the Western U.S. Basins, which measured resistivity data in saline at 20ppm, 40ppm, and 80ppm, respectively. We confirmed the existences of additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ) by fitting the relationship between the rock resistivity of saturated formation water (\u0000 R\u0000 o\u0000 ) and the formation water resistivity (\u0000 \u0000 R\u0000 w\u0000 \u0000 ). We then fitted the formation resistivity change factor (\u0000 \u0000 F\u0000 d\u0000 \u0000 ) with permeability (\u0000 K\u0000 ), the formation resistivity change factor (\u0000 \u0000 F\u0000 d\u0000 \u0000 ) with porosity (\u0000 \u0000 \u0000 φ\u0000 \u0000 \u0000 ), the additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ) with permeability (\u0000 K\u0000 ), and the additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ) with porosity (\u0000 \u0000 \u0000 φ\u0000 \u0000 \u0000 ). Both changeable formation resistivity change factor (\u0000 \u0000 F\u0000 d\u0000 \u0000 ) and additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ) showed a strong linear relationship with permeability (\u0000 K\u0000 ) in logarithmic coordinates.\u0000 \u0000 \u0000 We also verified the existence of a suitable equation using available experimental data by changing formation parameters and permeability. The study shows that the fitting equations may be utilized to determine changeable formation resistivity change factor (\u0000 \u0000 F\u0000 d\u0000 \u0000 ), additional resistivity (\u0000 \u0000 R\u0000 x\u0000 \u0000 ), and the rock resistivity of saturated formation water (\u0000 R\u0000 o\u0000 ) with varying permeability. The predicted rock resistivity of saturated formation water (\u0000 R\u0000 o\u0000 ) strongly correlates with the one measured in the laboratory, providing better precision for future reservoir evaluation in saturation estimations.\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44662834","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}
Giacomo Mangano, T. Alves, M. Zecchin, D. Civile, S. Critelli
This work addresses the tectonic significance of a NW-SE strike-slip fault zone in the Calabrian Arc of Southern Italy, the Rossano-San Nicola Fault Zone (RSFZ). High-quality seismic reflection and 1D forward models of exploration boreholes and pseudo-wells show that the RSFZ experienced multiple Miocene phases of contractional/transpressional tectonics. These were followed by crustal extension during the Pliocene in association with the oceanisation of the Tyrrhenian Sea, Apennine orogenesis, and collision between the Calabrian Arc and adjacent tectonic plates. Such a setting had a profound influence on the Crotone Basin and its economic potential: 1) tectonic reactivation allowed reservoir units of the Crotone Basin to be charged by gas derived from Triassic/Lower Jurassic source rocks, and 2) source rocks reached their maximum depth and remained in the gas generation window after the emplacement of a large mass-transport complex in the Pliocene. In the surrounding areas, tectonic activity near the RSFZ contributed to source-rock maturation by enhancing local sedimentation rates, particularly during Langhian (Middle Miocene) and Zanclean (early Pliocene) tectonics. This work is important as it demonstrates the tectono-stratigraphic evolution of the Crotone Basin to be closely related to the structural evolution of the RSFZ. Crucially, the study area reveals the first example of a gas field fully sealed by a large mass-transport complex. As a corollary, we tie the Late Cenozoic geological history of the Crotone Basin to the geodynamic evolution of the central Mediterranean region, namely the Ionian and Tyrrhenian seas. We identify new prospects in the Crotone Basin and provide a time frame for gas generation and accumulation in Southern Italy.
这项工作探讨了意大利南部卡拉布里亚弧北西-东南走向走滑断层带Rossano San Nicola断层带（RSFZ）的构造意义。勘探钻孔和伪井的高质量地震反射和1D正演模型表明，RSFZ经历了多个中新世收缩/转挤压构造阶段。随后是上新世地壳伸展，与第勒尼安海的海洋化、亚平宁造山运动以及卡拉布里亚弧与相邻构造板块之间的碰撞有关。这种环境对克罗托内盆地及其经济潜力产生了深远影响：1）构造复活使克罗托内流域的储层单元受到来自三叠纪/下侏罗纪烃源岩的天然气的充注，2）烃源岩在上新世大型物质运输杂岩侵位后达到最大深度并保持在天然气生成窗口中。在周围地区，RSFZ附近的构造活动通过提高局部沉积速率，特别是在Langhian（中新世中期）和Zanclean（上新世早期）构造期间，有助于源岩成熟。这项工作很重要，因为它证明了克罗托内盆地的构造-地层演化与RSFZ的结构演化密切相关。至关重要的是，该研究区域揭示了第一个由大型质量传输复合体完全密封的气田的例子。因此，我们将克罗托内盆地晚新生代地质史与地中海中部地区（即爱奥尼亚海和第勒尼安海）的地球动力学演化联系起来。我们确定了克罗托内盆地的新前景，并为意大利南部的天然气生成和聚集提供了时间框架。
{"title":"The Rossano-San Nicola Fault Zone evolution impacts the burial and maturation histories of the Crotone Basin, Calabrian Arc, Italy","authors":"Giacomo Mangano, T. Alves, M. Zecchin, D. Civile, S. Critelli","doi":"10.1144/petgeo2022-085","DOIUrl":"https://doi.org/10.1144/petgeo2022-085","url":null,"abstract":"This work addresses the tectonic significance of a NW-SE strike-slip fault zone in the Calabrian Arc of Southern Italy, the Rossano-San Nicola Fault Zone (RSFZ). High-quality seismic reflection and 1D forward models of exploration boreholes and pseudo-wells show that the RSFZ experienced multiple Miocene phases of contractional/transpressional tectonics. These were followed by crustal extension during the Pliocene in association with the oceanisation of the Tyrrhenian Sea, Apennine orogenesis, and collision between the Calabrian Arc and adjacent tectonic plates. Such a setting had a profound influence on the Crotone Basin and its economic potential: 1) tectonic reactivation allowed reservoir units of the Crotone Basin to be charged by gas derived from Triassic/Lower Jurassic source rocks, and 2) source rocks reached their maximum depth and remained in the gas generation window after the emplacement of a large mass-transport complex in the Pliocene. In the surrounding areas, tectonic activity near the RSFZ contributed to source-rock maturation by enhancing local sedimentation rates, particularly during Langhian (Middle Miocene) and Zanclean (early Pliocene) tectonics. This work is important as it demonstrates the tectono-stratigraphic evolution of the Crotone Basin to be closely related to the structural evolution of the RSFZ. Crucially, the study area reveals the first example of a gas field fully sealed by a large mass-transport complex. As a corollary, we tie the Late Cenozoic geological history of the Crotone Basin to the geodynamic evolution of the central Mediterranean region, namely the Ionian and Tyrrhenian seas. We identify new prospects in the Crotone Basin and provide a time frame for gas generation and accumulation in Southern Italy.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-04-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44256773","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}
{"title":"Geopressure: an introduction to the thematic collection","authors":"R. Swarbrick","doi":"10.1144/petgeo2023-026","DOIUrl":"https://doi.org/10.1144/petgeo2023-026","url":null,"abstract":"\u0000 Thematic collection:\u0000 This article is part of the Geopressure collection available at:\u0000 https://www.lyellcollection.org/topic/collections/geopressure\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47391645","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 discovery of Wytch Farm field in the Wessex Basin, and Kinsale Head field in the North Celtic Sea Basin in the early 1970s, led to exploration interest offshore in the Western Approaches Trough. Despite this activity, little evidence for prospective hydrocarbon resources has been found. To better understand the failures and analyse remaining hydrocarbon potential in this region, we make use of a large collection of new seismic reflection and well data to map Carboniferous to Neogene stratigraphy. The improved seismic imaging has allowed a better interpretation of the hitherto poorly understood, salt-related structures in the South Melville and the Plymouth Bay basins. The implications of the new interpretations for Carnian (Late Triassic), and Carboniferous stratigraphic and geodynamic evolution are assessed and contextualised with regional salt deposition in the Wessex, Bristol, and South Celtic Sea basins. From a petroleum system perspective, the Lias and Carboniferous source rocks are evaluated and modelled to analyse the maturity and evolution of the petroleum systems. We conclude that the Lias is an ineffective petroleum system due to timing and source maturation risk. However, the Triassic salt and associated subcropping faults have produced several possible pre-salt hydrocarbon traps. The traps may be charged from sporadic Mid-Late Carboniferous coal-bearing post-orogenic basins, a petroleum system previously overlooked. Supplementary material : [Appendix showing seismic, well data and petroleum systems boundary conditions. Burial history plots of the petroleum systems modelling scenarios used to generate source rock transformation ratio plots shown in Figs 9 & 10. [Item 1: Spreadsheet with seismic and well data used in the study, and petroleum system modelling input data. Item 2: Raw decompacted burial history plot, and burial history plots of the 3 Lias petroleum systems scenarios] https://doi.org/10.6084/m9.figshare.c.6486999 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":"New insights into the stratigraphic evolution of southwest Britain: Implications for Triassic salt and hydrocarbon prospectivity","authors":"S. S. Husein, A. Fraser, G. Roberts, R. Bell","doi":"10.1144/petgeo2022-051","DOIUrl":"https://doi.org/10.1144/petgeo2022-051","url":null,"abstract":"The discovery of Wytch Farm field in the Wessex Basin, and Kinsale Head field in the North Celtic Sea Basin in the early 1970s, led to exploration interest offshore in the Western Approaches Trough. Despite this activity, little evidence for prospective hydrocarbon resources has been found. To better understand the failures and analyse remaining hydrocarbon potential in this region, we make use of a large collection of new seismic reflection and well data to map Carboniferous to Neogene stratigraphy. The improved seismic imaging has allowed a better interpretation of the hitherto poorly understood, salt-related structures in the South Melville and the Plymouth Bay basins. The implications of the new interpretations for Carnian (Late Triassic), and Carboniferous stratigraphic and geodynamic evolution are assessed and contextualised with regional salt deposition in the Wessex, Bristol, and South Celtic Sea basins. From a petroleum system perspective, the Lias and Carboniferous source rocks are evaluated and modelled to analyse the maturity and evolution of the petroleum systems. We conclude that the Lias is an ineffective petroleum system due to timing and source maturation risk. However, the Triassic salt and associated subcropping faults have produced several possible pre-salt hydrocarbon traps. The traps may be charged from sporadic Mid-Late Carboniferous coal-bearing post-orogenic basins, a petroleum system previously overlooked.\u0000 \u0000 Supplementary material\u0000 : [Appendix showing seismic, well data and petroleum systems boundary conditions. Burial history plots of the petroleum systems modelling scenarios used to generate source rock transformation ratio plots shown in Figs 9 & 10. [Item 1: Spreadsheet with seismic and well data used in the study, and petroleum system modelling input data. Item 2: Raw decompacted burial history plot, and burial history plots of the 3 Lias petroleum systems scenarios]\u0000 https://doi.org/10.6084/m9.figshare.c.6486999\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","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46491601","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 the Pannonian Basin, especially in Croatia, there are a small number of wells with acquired shear velocities. Often, quantitative interpretation must rely only on compressional velocity data, and shear velocity must be modelled. Shear wave velocity estimation in combination with other petrophysical data is essential for detailed reservoir characterization. Compressional and shear wave velocity allow the seismic modelling of different saturation states in a reservoir. This paper demonstrates a workflow for S-wave velocity estimation where shear velocity data is absent in the gas field and neighboring fields with the same lithology, based on the Kuster-Toksöz and Xu-Payne models applied to the Pannonian basin limestone reservoir. The results are calibrated with the P-wave velocity obtained from borehole data and the VSP S-wave interval velocity. Although rock physics models are idealized analogues of real rocks, a very good correlation was obtained between the modelled and measured P-wave velocity, as well as between the modelled S-wave velocity and the VSP interval velocity. The study also illustrates the problem of defining the pore aspect ratio in zones of increasing shale content. Due to the limited research on the limestones of the Pannonian Basin, these results enable a better understanding of the seismic parameters of the Pannonian Basin limestones. The results indicate that the proposed workflow gives an adequate estimation of S-wave velocities.
{"title":"Shear velocity estimation based on rock physics modeling of limestone gas reservoir in the Pannonian basin","authors":"D. Vukadin","doi":"10.1144/petgeo2022-070","DOIUrl":"https://doi.org/10.1144/petgeo2022-070","url":null,"abstract":"In the Pannonian Basin, especially in Croatia, there are a small number of wells with acquired shear velocities. Often, quantitative interpretation must rely only on compressional velocity data, and shear velocity must be modelled. Shear wave velocity estimation in combination with other petrophysical data is essential for detailed reservoir characterization. Compressional and shear wave velocity allow the seismic modelling of different saturation states in a reservoir. This paper demonstrates a workflow for S-wave velocity estimation where shear velocity data is absent in the gas field and neighboring fields with the same lithology, based on the Kuster-Toksöz and Xu-Payne models applied to the Pannonian basin limestone reservoir. The results are calibrated with the P-wave velocity obtained from borehole data and the VSP S-wave interval velocity. Although rock physics models are idealized analogues of real rocks, a very good correlation was obtained between the modelled and measured P-wave velocity, as well as between the modelled S-wave velocity and the VSP interval velocity. The study also illustrates the problem of defining the pore aspect ratio in zones of increasing shale content. Due to the limited research on the limestones of the Pannonian Basin, these results enable a better understanding of the seismic parameters of the Pannonian Basin limestones. The results indicate that the proposed workflow gives an adequate estimation of S-wave velocities.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-03-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48220930","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 the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker n -C 33 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded.
{"title":"The potential extent of Early Triassic Kockatea Shale equivalent source rocks in the Northern Carnarvon and Perth Basins (Western Australia)","authors":"T. Taniwaki, C. Elders, A. Holman, K. Grice","doi":"10.1144/petgeo2022-023","DOIUrl":"https://doi.org/10.1144/petgeo2022-023","url":null,"abstract":"\u0000 In the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker\u0000 n\u0000 -C\u0000 33\u0000 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded.\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-03-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46282674","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}
Oluwafemi E. Aro, S. Jones, N. Meadows, J. Gluyas, Dimitrios Charlaftis
Clay-coated grains play an important role in preserving reservoir quality in high-pressure high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high energy channel sandstones have higher permeabilities (100-1150 mD) than low energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay coat coverage correlating with grain size, clay coat volume and quartz cement. Higher coverage (70-98%) occurs in finer-grained, low energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration. Supplementary material: of data and technique used in this study are available at https://doi.org/10.6084/m9.figshare.c.6438450.v1
{"title":"The importance of facies, grain size, and clay content in controlling fluvial reservoir quality – An example from the Triassic Skagerrak Formation, Central North Sea, UK","authors":"Oluwafemi E. Aro, S. Jones, N. Meadows, J. Gluyas, Dimitrios Charlaftis","doi":"10.1144/petgeo2022-043","DOIUrl":"https://doi.org/10.1144/petgeo2022-043","url":null,"abstract":"Clay-coated grains play an important role in preserving reservoir quality in high-pressure high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high energy channel sandstones have higher permeabilities (100-1150 mD) than low energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay coat coverage correlating with grain size, clay coat volume and quartz cement. Higher coverage (70-98%) occurs in finer-grained, low energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration.\u0000 \u0000 Supplementary material:\u0000 of data and technique used in this study are available at\u0000 https://doi.org/10.6084/m9.figshare.c.6438450.v1\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-02-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45696107","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. Awad Sayid, Z. Yao, Rongxi Li, M. M. Ahmed Saif
This study investigates the hydrocarbon generation and retention potential of Chang 7 organic-rich shale, with an emphasis on the producibility of retained hydrocarbons, using a sample set chosen to represent a maturity spectrum of 0.54 % to 0.9 % Ro and organic matter of type II and mixed type II-III. Based on the present-day hydrogen index (HI pd ), the sample sets are divided into three sections, Upper, Middle, and Lower. The three sections have a high hydrocarbons generation potential, with an average original TOC (TOC o ) of 12.27, 3.10, and 5.13 wt.% of which 49.39, 23.62, and 49.86 wt.% represent generative organic carbon (GOC), an original hydrogen index (HI o ) of 581.27, 278.05 and 586.82 HC/g rock, in the Upper, Middle, and Lower Sections, respectively. The bulk of analyzed samples exhibit moderate-high oil saturation, yet the oil crossover effect is observed only in two organic-rich samples indicating organic-rich shale-oil resource systems. The sorption capacity of organic matter controls oil retention in the Chang 7 shale system, where the oil saturation index increases with increasing maturity in the oil window until a maximum retention capacity of about 82-83 mg HC/g TOC is reached at a vitrinite reflectance of 0.8% and thereafter decreases with further maturity. Supplementary material: [Detailed spreadsheet of the back-calculated original geochemical parameters using the mass-balance method of Jarvie (2012a)], are available at https://doi.org/10.6084/m9.figshare.c.6387577 .
{"title":"Hydrocarbon generation and retention potential of Chang 7 organic-rich shale in Ordos Basin, China","authors":"M. Awad Sayid, Z. Yao, Rongxi Li, M. M. Ahmed Saif","doi":"10.1144/petgeo2022-008","DOIUrl":"https://doi.org/10.1144/petgeo2022-008","url":null,"abstract":"\u0000 This study investigates the hydrocarbon generation and retention potential of Chang 7 organic-rich shale, with an emphasis on the producibility of retained hydrocarbons, using a sample set chosen to represent a maturity spectrum of 0.54 % to 0.9 % Ro and organic matter of type II and mixed type II-III. Based on the present-day hydrogen index (HI\u0000 pd\u0000 ), the sample sets are divided into three sections, Upper, Middle, and Lower. The three sections have a high hydrocarbons generation potential, with an average original TOC (TOC\u0000 o\u0000 ) of 12.27, 3.10, and 5.13 wt.% of which 49.39, 23.62, and 49.86 wt.% represent generative organic carbon (GOC), an original hydrogen index (HI\u0000 o\u0000 ) of 581.27, 278.05 and 586.82 HC/g rock, in the Upper, Middle, and Lower Sections, respectively. The bulk of analyzed samples exhibit moderate-high oil saturation, yet the oil crossover effect is observed only in two organic-rich samples indicating organic-rich shale-oil resource systems. The sorption capacity of organic matter controls oil retention in the Chang 7 shale system, where the oil saturation index increases with increasing maturity in the oil window until a maximum retention capacity of about 82-83 mg HC/g TOC is reached at a vitrinite reflectance of 0.8% and thereafter decreases with further maturity.\u0000 \u0000 \u0000 Supplementary material:\u0000 [Detailed spreadsheet of the back-calculated original geochemical parameters using the mass-balance method of Jarvie (2012a)], are available at\u0000 https://doi.org/10.6084/m9.figshare.c.6387577\u0000 .\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-01-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41864994","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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