Exploration in the Faroe–Shetland Basin on the Faroese Continental Shelf has revealed thick and complex volcanic successions and discovery of inter-volcanic oil-bearing siliciclastic sandstone fan deposits in the central parts of the basin. The possibility for such play types at the fringe of the North Atlantic Igneous Province requires a better understanding of the interaction between competing sedimentary and volcanic depositional transport systems. We have re-examined volcanic units in cuttings from exploration wells in the greater Judd Sub-basin area for evaluation of facies and geochemical affinity. This allows for chemostratigraphical correlation of wells to the absolute radiometrically age-constrained Faroe Islands Basalt Group. The collective well data were subsequently tied to a regional interpretation of 2D seismic data which facilitated a detailed interpretation of temporal development of the volcanic successions in the Judd Sub-basin area in terms of geometry, volcanic facies, depositional environment, and interdigitation with non-volcanic sedimentary units. The Judd Sub-basin was influenced by major volcanic phases during pre-breakup and syn-breakup. The influence was both direct, in the form of volcanic deposits, and indirect, in the form of obstructing established sedimentary transport systems and creating new provenance areas. The volcanic transport systems reached different areas of the Judd Sub-basin at different times during pre-breakup volcanism. The earliest incursion in the west was during late Mid Paleocene (T-sequence T31/T32). With at least three stratigraphically discrete incursions of volcanic material into the Judd Sub-basin, possibilities arise for sub- and inter-volcanic stratigraphic and structural traps for each incursion.
{"title":"Interaction between volcanic and non-volcanic systems and its implication for prospectivity in the Faroe–Shetland Basin, NE Atlantic continental margin","authors":"H. Ziska, U. Árting, M. Riishuus","doi":"10.1144/petgeo2021-058","DOIUrl":"https://doi.org/10.1144/petgeo2021-058","url":null,"abstract":"Exploration in the Faroe–Shetland Basin on the Faroese Continental Shelf has revealed thick and complex volcanic successions and discovery of inter-volcanic oil-bearing siliciclastic sandstone fan deposits in the central parts of the basin. The possibility for such play types at the fringe of the North Atlantic Igneous Province requires a better understanding of the interaction between competing sedimentary and volcanic depositional transport systems. We have re-examined volcanic units in cuttings from exploration wells in the greater Judd Sub-basin area for evaluation of facies and geochemical affinity. This allows for chemostratigraphical correlation of wells to the absolute radiometrically age-constrained Faroe Islands Basalt Group. The collective well data were subsequently tied to a regional interpretation of 2D seismic data which facilitated a detailed interpretation of temporal development of the volcanic successions in the Judd Sub-basin area in terms of geometry, volcanic facies, depositional environment, and interdigitation with non-volcanic sedimentary units. The Judd Sub-basin was influenced by major volcanic phases during pre-breakup and syn-breakup. The influence was both direct, in the form of volcanic deposits, and indirect, in the form of obstructing established sedimentary transport systems and creating new provenance areas. The volcanic transport systems reached different areas of the Judd Sub-basin at different times during pre-breakup volcanism. The earliest incursion in the west was during late Mid Paleocene (T-sequence T31/T32). With at least three stratigraphically discrete incursions of volcanic material into the Judd Sub-basin, possibilities arise for sub- and inter-volcanic stratigraphic and structural traps for each incursion.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45733531","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}
Mudrock strength parameters are required to improve the prediction of fracture gradient during drilling in poorly consolidated formations. Understanding the influence that mineral composition and consolidation stress have on the mechanical properties of mudrocks aids safe well design. Small changes in the mudrock clay content are shown to have significant effects on two important engineering parameters: the lateral stress ratio at rest, K0, and the critical state effective friction angle, ϕ′cs. A laboratory-testing programme using quartz silt and a Gulf of Mexico clay mixture investigates the effects of mudrock clay content on K0 and ϕ′cs at two stress levels: 1 and 10 MPa. Values of K0 and ϕ′cs were obtained by subjecting composition-controlled clay–silt specimens to a drained uniaxial vertical strain (K0 consolidation) phase, followed by an undrained compression triaxial shear phase. Triaxial tests illustrate consistent and systematic increases in K0 and decreases in ϕ′cs, with increases in clay content at both stress levels. Stress dependence is observed through increases in K0 and decreases in ϕ′cs with increases in stress level. Stress-dependent behaviour is shown to be more pronounced in mudrocks of high clay content. A predictive model is presented for K0 in normally consolidated mudrocks, as a function of clay content and effective stress. The model is used to calculate the fracture gradient (least horizontal stress) profile at the International Ocean Drilling Program (IODP) Expedition 308 Site 1324. The estimated fracture gradient illustrates the effects of clay content and consolidation stress on safe mud weight design. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"The impact of clay fraction on the strength and stress ratio (K0) in Gulf of Mexico mudrocks and quartz silt mixtures: implications for borehole stability and fracture gradient","authors":"Mark Zablocki, J. Germaine, R. Plumb, P. Flemings","doi":"10.1144/petgeo2021-056","DOIUrl":"https://doi.org/10.1144/petgeo2021-056","url":null,"abstract":"Mudrock strength parameters are required to improve the prediction of fracture gradient during drilling in poorly consolidated formations. Understanding the influence that mineral composition and consolidation stress have on the mechanical properties of mudrocks aids safe well design. Small changes in the mudrock clay content are shown to have significant effects on two important engineering parameters: the lateral stress ratio at rest, K0, and the critical state effective friction angle, ϕ′cs. A laboratory-testing programme using quartz silt and a Gulf of Mexico clay mixture investigates the effects of mudrock clay content on K0 and ϕ′cs at two stress levels: 1 and 10 MPa. Values of K0 and ϕ′cs were obtained by subjecting composition-controlled clay–silt specimens to a drained uniaxial vertical strain (K0 consolidation) phase, followed by an undrained compression triaxial shear phase. Triaxial tests illustrate consistent and systematic increases in K0 and decreases in ϕ′cs, with increases in clay content at both stress levels. Stress dependence is observed through increases in K0 and decreases in ϕ′cs with increases in stress level. Stress-dependent behaviour is shown to be more pronounced in mudrocks of high clay content. A predictive model is presented for K0 in normally consolidated mudrocks, as a function of clay content and effective stress. The model is used to calculate the fracture gradient (least horizontal stress) profile at the International Ocean Drilling Program (IODP) Expedition 308 Site 1324. The estimated fracture gradient illustrates the effects of clay content and consolidation stress on safe mud weight design. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44934023","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 work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models.The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the north-eastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies.The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic 'truth case'. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimisation and machine learning.Supplementary material:https://doi.org/10.6084/m9.figshare.c.5823571
这项工作提出了一种新的开源碳酸盐岩储层案例研究，即COSTA模型，该模型独特地考虑了碳酸盐岩储层固有的重大不确定性，为一系列地能源应用提供了更具挑战性和更现实的基准测试。COSTA油田面积大，井多，伴生体积大。该数据集将许多相互作用的地质和岩石物理不确定性嵌入到具有实际地质和模型复杂性水平以及不同生产剖面的模型概念集合中。与当前的基准测试模型相比，由此产生的不同模型的数量和较长的运行时间产生了更苛刻的计算挑战。COSTA模型的灵感来自上Kharaib段(早白垩世)的陆架-盆地地质背景，这是世界上最多产的沉积准层序碳酸盐岩地层之一。该数据集基于Rub Al Khali盆地东北部的43口井和相应的完全匿名数据，该盆地是阿拉伯盆地的一个子盆地。我们的模型将大陆架-盆地剖面的大规模地质背景和储层非均质性封装到一个模型中，用于地质建模和储层模拟研究。这项研究的结果是一套半合成但地质上真实的碳酸盐岩储层模型，它捕获了广泛的地质、岩石物理和地质建模的不确定性，并且可以与未公开的合成“真实案例”进行历史匹配。模型和数据集作为开源提供，用于分析与测试地质建模，不确定性量化，油藏模拟，历史匹配，优化和机器学习的新数值算法相关的几个问题。辅料:https://doi.org/10.6084/m9.figshare.c.5823571
{"title":"The design of an open-source carbonate reservoir model","authors":"J. Costa Gomes, S. Geiger, D. Arnold","doi":"10.1144/petgeo2021-067","DOIUrl":"https://doi.org/10.1144/petgeo2021-067","url":null,"abstract":"This work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models.The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the north-eastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies.The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic 'truth case'. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimisation and machine learning.Supplementary material:https://doi.org/10.6084/m9.figshare.c.5823571","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47937781","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}
Knowledge of subsurface formation pressures is critical for the calibration of predictions and models needed for safe drilling of deep wells, historically for oil and gas wells. The same details apply to the sequestration of CO2, ephemeral storage of gases such as hydrogen and for geothermal power. An estimated 10–14% of wells globally experience an unexpected influx of formation fluid, indicative of the controlling mud in the borehole at that time having a lower pressure than the surrounding formation. The drilling events, known as kicks and wellbore breathing, lead to, at best, downtime on the drilling rig which might affect the economic viability of the well, or in the extreme its safety with possible loss of life such as in the case of an uncontrolled blowout. Not all kicks are of equivalent value: dynamic and static kicks can be classified with a high degree of confidence and may become values for true formation pressure. Other types of fluid influx during drilling, including swab kicks and wellbore breathing, need to be identified and will not be accepted in a kick database. These types of influx may be eliminated as potential formation pressure values but, along with mud weights, can be valuable data to constrain the range of possible formation pressures, of significant where no other data exist. A new, rigorous evaluation procedure for determining formation pressure is presented, and compared with direct pore pressure measurements (e.g. RFT, MDT, RCI values). The comparison shows that the proposed methodology illustrates typical uncertainty of about 10 bar (145 psi) pressure over the full range of pressures for which data are available in this study. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"Kicks and their significance in pore pressure prediction","authors":"Jack Lee, R. Swarbrick, S. O'Connor","doi":"10.1144/petgeo2021-061","DOIUrl":"https://doi.org/10.1144/petgeo2021-061","url":null,"abstract":"Knowledge of subsurface formation pressures is critical for the calibration of predictions and models needed for safe drilling of deep wells, historically for oil and gas wells. The same details apply to the sequestration of CO2, ephemeral storage of gases such as hydrogen and for geothermal power. An estimated 10–14% of wells globally experience an unexpected influx of formation fluid, indicative of the controlling mud in the borehole at that time having a lower pressure than the surrounding formation. The drilling events, known as kicks and wellbore breathing, lead to, at best, downtime on the drilling rig which might affect the economic viability of the well, or in the extreme its safety with possible loss of life such as in the case of an uncontrolled blowout. Not all kicks are of equivalent value: dynamic and static kicks can be classified with a high degree of confidence and may become values for true formation pressure. Other types of fluid influx during drilling, including swab kicks and wellbore breathing, need to be identified and will not be accepted in a kick database. These types of influx may be eliminated as potential formation pressure values but, along with mud weights, can be valuable data to constrain the range of possible formation pressures, of significant where no other data exist. A new, rigorous evaluation procedure for determining formation pressure is presented, and compared with direct pore pressure measurements (e.g. RFT, MDT, RCI values). The comparison shows that the proposed methodology illustrates typical uncertainty of about 10 bar (145 psi) pressure over the full range of pressures for which data are available in this study. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46890612","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. Drews, I. Shatyrbayeva, D. Bohnsack, F. Duschl, P. Obermeier, M. Loewer, F. Flechtner, M. Keim
Pore pressure prediction is a well-developed key discipline for well planning in the hydrocarbon industry, suggesting a similar importance for deep geothermal wells, especially, since drilling cost is often the largest investment in deep geothermal energy projects. To address the role of pore pressure prediction in deep geothermal energy, we investigated pore pressure-related drilling problems in the overpressured North Alpine Foreland Basin in SE Germany – one of Europe's most extensively explored deep geothermal energy plays. In the past, pore pressure was mainly predicted via maximum drilling mud weights of offset hydrocarbon wells, but recently more data became available, which led to a re-evaluation of the pore pressure distribution in this area. To compare the impact of pore pressure and its prediction, 70% of all deep geothermal wells drilled have been investigated for pore pressure-related drilling problems and two deep geothermal projects are given as more detailed examples. Thereby, pore pressure-related drilling problems were encountered in one third of all wells drilled, resulting in several side-tracks and an estimated drilling rate decrease of up to 40%, highlighting the importance of accurate pore pressure prediction to significantly reduce the cost of deep geothermal drilling in overpressured environments. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"The role of pore pressure and its prediction in deep geothermal energy drilling – examples from the North Alpine Foreland Basin, SE Germany","authors":"M. Drews, I. Shatyrbayeva, D. Bohnsack, F. Duschl, P. Obermeier, M. Loewer, F. Flechtner, M. Keim","doi":"10.1144/petgeo2021-060","DOIUrl":"https://doi.org/10.1144/petgeo2021-060","url":null,"abstract":"Pore pressure prediction is a well-developed key discipline for well planning in the hydrocarbon industry, suggesting a similar importance for deep geothermal wells, especially, since drilling cost is often the largest investment in deep geothermal energy projects. To address the role of pore pressure prediction in deep geothermal energy, we investigated pore pressure-related drilling problems in the overpressured North Alpine Foreland Basin in SE Germany – one of Europe's most extensively explored deep geothermal energy plays. In the past, pore pressure was mainly predicted via maximum drilling mud weights of offset hydrocarbon wells, but recently more data became available, which led to a re-evaluation of the pore pressure distribution in this area. To compare the impact of pore pressure and its prediction, 70% of all deep geothermal wells drilled have been investigated for pore pressure-related drilling problems and two deep geothermal projects are given as more detailed examples. Thereby, pore pressure-related drilling problems were encountered in one third of all wells drilled, resulting in several side-tracks and an estimated drilling rate decrease of up to 40%, highlighting the importance of accurate pore pressure prediction to significantly reduce the cost of deep geothermal drilling in overpressured environments. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44760327","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}
Several mechanisms have been suggested as drivers of naturally occurring underpressure. However, the phenomenon is largely underrepresented in literature. Previous studies have focused on individual cases in North America, where challenges due to topography and defining hydrostatic gradients exist. More recent publications from underpressured basins have emerged from other parts of the world, where settings are arguably more favourable to studying the phenomenon. Based on a total of 29 underpressured locations, it is apparent that the magnitudes and depths of underpressure are similar throughout the world. Pressures of up to 60 bar blow hydrostatic are common in sedimentary basins of North America, China, Russia, and Europe and typically occur at shallow depths (<2500 m). All occurrences of underpressure occur in areas that have been geologically recently uplifted and is predominantly confined to low permeability rocks. Although rarely tested, it appears that mudstone intervals are susceptible to developing underpressure. Given the shallowness, low permeability, and recent uplift of the cases, it seems that underpressure is typically a geologically short-lived phenomenon. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"Naturally occurring underpressure – a global review","authors":"T. Birchall, K. Senger, R. Swarbrick","doi":"10.1144/petgeo2021-051","DOIUrl":"https://doi.org/10.1144/petgeo2021-051","url":null,"abstract":"Several mechanisms have been suggested as drivers of naturally occurring underpressure. However, the phenomenon is largely underrepresented in literature. Previous studies have focused on individual cases in North America, where challenges due to topography and defining hydrostatic gradients exist. More recent publications from underpressured basins have emerged from other parts of the world, where settings are arguably more favourable to studying the phenomenon. Based on a total of 29 underpressured locations, it is apparent that the magnitudes and depths of underpressure are similar throughout the world. Pressures of up to 60 bar blow hydrostatic are common in sedimentary basins of North America, China, Russia, and Europe and typically occur at shallow depths (<2500 m). All occurrences of underpressure occur in areas that have been geologically recently uplifted and is predominantly confined to low permeability rocks. Although rarely tested, it appears that mudstone intervals are susceptible to developing underpressure. Given the shallowness, low permeability, and recent uplift of the cases, it seems that underpressure is typically a geologically short-lived phenomenon. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45375325","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}
Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"Geoscience for CO2 storage: an introduction to the thematic collection","authors":"P. Ringrose, G. Yielding","doi":"10.1144/petgeo2022-003","DOIUrl":"https://doi.org/10.1144/petgeo2022-003","url":null,"abstract":"Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47607905","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}
Edgar Eduardo Yáñez Angarita, V. Núñez-López, A. Ramírez Ramírez, Edgar Fernando Castillo Monroy, A. Faaij
Estimating the oil recovery potential using CO2 (CO2-EOR) at a national level is resource-intensive at a scale that is not usually available. The aim of this study is two-fold: first, the potential for CO2 storage and enhanced oil recovery (EOR) in Colombia is evaluated; and, second, the results from two different calculation methods (stochastic and deterministic) are compared when there is lack of information for a quick screening of suitable oilfields. The deterministic approach is based on expert insight and data found in the literature; while, the stochastic uses statistical data from two different databases (commercial and simulation-based results) to run a Monte Carlo simulation. Potential estimates based on typical values from the literature (deterministic) results in 277 MMbbl (million barrels) of oil and 36 Mt (million tonnes) of CO2. In contrast, a probabilistic-based method using a wide simulation database (stochastic) provides higher values of 690 MMbbl of oil and 203 Mt of CO2. Results using simulation-based and commercial project data also show significant differences. The volume of CO2 injected, which affects the recovery factor, is usually 100% hydrocarbon pore volume (HCPV) in simulation, while commercial projects have nowadays regularly increased from 30% to exceed the 100% threshold. A combination of these approaches avoids a resource-intensive estimation process and effectively provides a more realistic picture of the feasibility of applying CO2-EOR technologies. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
{"title":"Rapid screening and probabilistic estimation of the potential for CO2-EOR and associated geological CO2 storage in Colombian petroleum basins","authors":"Edgar Eduardo Yáñez Angarita, V. Núñez-López, A. Ramírez Ramírez, Edgar Fernando Castillo Monroy, A. Faaij","doi":"10.1144/petgeo2020-110","DOIUrl":"https://doi.org/10.1144/petgeo2020-110","url":null,"abstract":"Estimating the oil recovery potential using CO2 (CO2-EOR) at a national level is resource-intensive at a scale that is not usually available. The aim of this study is two-fold: first, the potential for CO2 storage and enhanced oil recovery (EOR) in Colombia is evaluated; and, second, the results from two different calculation methods (stochastic and deterministic) are compared when there is lack of information for a quick screening of suitable oilfields. The deterministic approach is based on expert insight and data found in the literature; while, the stochastic uses statistical data from two different databases (commercial and simulation-based results) to run a Monte Carlo simulation. Potential estimates based on typical values from the literature (deterministic) results in 277 MMbbl (million barrels) of oil and 36 Mt (million tonnes) of CO2. In contrast, a probabilistic-based method using a wide simulation database (stochastic) provides higher values of 690 MMbbl of oil and 203 Mt of CO2. Results using simulation-based and commercial project data also show significant differences. The volume of CO2 injected, which affects the recovery factor, is usually 100% hydrocarbon pore volume (HCPV) in simulation, while commercial projects have nowadays regularly increased from 30% to exceed the 100% threshold. A combination of these approaches avoids a resource-intensive estimation process and effectively provides a more realistic picture of the feasibility of applying CO2-EOR technologies. Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43514571","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":"Editorial comments from the incoming Chief Editor, January 2022","authors":"","doi":"10.1144/petgeo2022-005","DOIUrl":"https://doi.org/10.1144/petgeo2022-005","url":null,"abstract":"","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"28 1","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41871703","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 overpressure variation in the Cenozoic–Jurassic succession in the northern part of the Danish Central Graben may broadly be divided into three major compartments. An upper hydrostatically pressured unit comprises the post-mid Miocene–recent succession down to c. 1200 m depth in the northern and c. 700 m in the southern parts of the Danish Central Graben. The second compartment comprises the mid-Miocene smectite-rich clays down to and including the upper Cretaceous chalk. There the Paleogene–Lower Miocene succession provides the seal. The third compartment constitutes the Jurassic succession with pressure above hydrostatic that may exceed twice that seen at the upper Chalk level. Pressure levels can be estimated using the Eaton approach for the second compartment that are in agreement with pressure data. Modelling of the transient pressure development in the Cretaceous–mid-Miocene succession broadly complies with the Eaton estimates and shows that the main overpressure build-up has occurred within the last 10 myr. The overpressure in this succession may be mapped using methods that exploit correlations between fluid pressure and the degree of consolidation, while that in the Jurassic cannot. However, the lateral variation in the Upper Jurassic overpressure correlates broadly with the maturity of the Upper Jurassic source rock, allowing the pressure variation to be mapped. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"Pressure variations in the northern part of the Danish Central Graben, North Sea","authors":"O. V. Vejbæk","doi":"10.1144/petgeo2021-070","DOIUrl":"https://doi.org/10.1144/petgeo2021-070","url":null,"abstract":"The overpressure variation in the Cenozoic–Jurassic succession in the northern part of the Danish Central Graben may broadly be divided into three major compartments. An upper hydrostatically pressured unit comprises the post-mid Miocene–recent succession down to c. 1200 m depth in the northern and c. 700 m in the southern parts of the Danish Central Graben. The second compartment comprises the mid-Miocene smectite-rich clays down to and including the upper Cretaceous chalk. There the Paleogene–Lower Miocene succession provides the seal. The third compartment constitutes the Jurassic succession with pressure above hydrostatic that may exceed twice that seen at the upper Chalk level. Pressure levels can be estimated using the Eaton approach for the second compartment that are in agreement with pressure data. Modelling of the transient pressure development in the Cretaceous–mid-Miocene succession broadly complies with the Eaton estimates and shows that the main overpressure build-up has occurred within the last 10 myr. The overpressure in this succession may be mapped using methods that exploit correlations between fluid pressure and the degree of consolidation, while that in the Jurassic cannot. However, the lateral variation in the Upper Jurassic overpressure correlates broadly with the maturity of the Upper Jurassic source rock, allowing the pressure variation to be mapped. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2022-01-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46649266","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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