I. Abu-Mahfouz, Regina Iakusheva, T. Finkbeiner, J. Cartwright, V. Vahrenkamp
Mechanical properties of layered rocks are critical in ensuring wellbore integrity and predicting natural fracture occurrence for successful reservoir development, particularly in unconventional reservoirs for which fractures provide the main pathway for hydrocarbon flow. We examine rock mechanical properties of exceptionally organic-rich, immature source rocks from Jordan and understand their relationships with rock mineral composition and lithofacies variations. Four depositional microfacies were identified: organic-rich mudstone, organic-rich wackestone, silica-rich packstone, and fine-grained organic-rich wackestone. The four types exhibit various mineralogical compositions, dominated by carbonates, biogenic quartz, and apatite. Leeb hardness ranges between 288 – 654, with the highest average values in silica-rich packstone and organic-rich mudstone. The highest uniaxial compressive strength (derived from the intrinsic specific energy measured by Epslog's Wombat scratch device), compressional, and shear waves velocities were measured in organic-rich mudstones (140 MPa, 3368 m/s, and 1702 m/s, respectively). Porosity shows higher average values in organic-rich wackestones and fine-grained organic-rich wackestones (33% – 35%). Silica-rich packstone and organic-rich mudstone have brittle properties, while organic-rich wackestone and fine-grained organic-rich wackestone are ductile. High silica contents are correlated positively with brittleness. A strong hardness-brittleness correlation suggests that Leeb hardness is a useful proxy for brittleness. Our study allows a better understanding of the relationships between lithofacies, organic content and rock mechanical properties, with implications for fracking design to well completion and hydrocarbon production. Further work involving systematic sampling and a more rigorous study is still required to better understand the spatial distribution of target lithologies and their mechanical properties.
{"title":"Rock mechanical properties of immature, organic-rich source rocks and their relationships to rock composition and lithofacies","authors":"I. Abu-Mahfouz, Regina Iakusheva, T. Finkbeiner, J. Cartwright, V. Vahrenkamp","doi":"10.1144/petgeo2022-021","DOIUrl":"https://doi.org/10.1144/petgeo2022-021","url":null,"abstract":"Mechanical properties of layered rocks are critical in ensuring wellbore integrity and predicting natural fracture occurrence for successful reservoir development, particularly in unconventional reservoirs for which fractures provide the main pathway for hydrocarbon flow. We examine rock mechanical properties of exceptionally organic-rich, immature source rocks from Jordan and understand their relationships with rock mineral composition and lithofacies variations. Four depositional microfacies were identified: organic-rich mudstone, organic-rich wackestone, silica-rich packstone, and fine-grained organic-rich wackestone. The four types exhibit various mineralogical compositions, dominated by carbonates, biogenic quartz, and apatite. Leeb hardness ranges between 288 – 654, with the highest average values in silica-rich packstone and organic-rich mudstone. The highest uniaxial compressive strength (derived from the intrinsic specific energy measured by Epslog's Wombat scratch device), compressional, and shear waves velocities were measured in organic-rich mudstones (140 MPa, 3368 m/s, and 1702 m/s, respectively). Porosity shows higher average values in organic-rich wackestones and fine-grained organic-rich wackestones (33% – 35%). Silica-rich packstone and organic-rich mudstone have brittle properties, while organic-rich wackestone and fine-grained organic-rich wackestone are ductile. High silica contents are correlated positively with brittleness. A strong hardness-brittleness correlation suggests that Leeb hardness is a useful proxy for brittleness. Our study allows a better understanding of the relationships between lithofacies, organic content and rock mechanical properties, with implications for fracking design to well completion and hydrocarbon production. Further work involving systematic sampling and a more rigorous study is still required to better understand the spatial distribution of target lithologies and their mechanical properties.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-01-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42374216","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}
Predicting the performance of a subsurface oil field is a large, multivariant problem. Production is controlled and influenced by a wide array of geological and engineering parameters which overlap and interact in ways that are difficult to unravel in a manner that can be predictive. Supervised machine learning is a statistical approach which uses empirical learnings from a training dataset to create models and make predictions about future outcomes. The goal of this study is to test a number of supervised machine learning methods on a dataset of oil fields from the United Kingdom continental shelf (UKCS), in order to assess whether, a) it is possible to predict future oil field performance and b), which methods are the most effective. The study is based on a dataset of 60 fields with 5 controlling parameters, (gross depositional environment, average permeability, net-to-gross, gas-oil ratio and total number of wells) and 2 outcome parameters (recovery factor and maximum field rate) for each. The choice of controlling parameters was based on a PCA of a larger dataset from a wider project database. Five different machine learning algorithms were tested. These include linear regression, robust linear regression, linear kernel support vector regression, cubic kernel support vector regression and boosted trees regression. Overall, 83% of the data was used as a training dataset while 17% was used to test the predictability of the algorithms. Results were compared using R-Squared, Mean Square Error, Root Mean Square Error and Mean Absolute Error. Graphs of predicted responses vs true (actual) responses are also shown to give a visual illustration of model performance. Results of this analysis show that certain methods perform better than others, depending on the outcome variable in question (recovery factor or maximum field rate). The best method for both outcome variables was the support vector regression, where, depending on the kernel function applied, a reliable level of predictability with low error rates were achieved. This demonstrates a strong potential for statistics-based prediction models of reservoir performance.
{"title":"Predicting Oil Field Performance using Machine Learning Programming: A Comparative Case Study from the UK Continental Shelf","authors":"Ukari Osah, J. Howell","doi":"10.1144/petgeo2022-071","DOIUrl":"https://doi.org/10.1144/petgeo2022-071","url":null,"abstract":"Predicting the performance of a subsurface oil field is a large, multivariant problem. Production is controlled and influenced by a wide array of geological and engineering parameters which overlap and interact in ways that are difficult to unravel in a manner that can be predictive. Supervised machine learning is a statistical approach which uses empirical learnings from a training dataset to create models and make predictions about future outcomes. The goal of this study is to test a number of supervised machine learning methods on a dataset of oil fields from the United Kingdom continental shelf (UKCS), in order to assess whether, a) it is possible to predict future oil field performance and b), which methods are the most effective. The study is based on a dataset of 60 fields with 5 controlling parameters, (gross depositional environment, average permeability, net-to-gross, gas-oil ratio and total number of wells) and 2 outcome parameters (recovery factor and maximum field rate) for each. The choice of controlling parameters was based on a PCA of a larger dataset from a wider project database. Five different machine learning algorithms were tested. These include linear regression, robust linear regression, linear kernel support vector regression, cubic kernel support vector regression and boosted trees regression. Overall, 83% of the data was used as a training dataset while 17% was used to test the predictability of the algorithms. Results were compared using R-Squared, Mean Square Error, Root Mean Square Error and Mean Absolute Error. Graphs of predicted responses vs true (actual) responses are also shown to give a visual illustration of model performance. Results of this analysis show that certain methods perform better than others, depending on the outcome variable in question (recovery factor or maximum field rate). The best method for both outcome variables was the support vector regression, where, depending on the kernel function applied, a reliable level of predictability with low error rates were achieved. This demonstrates a strong potential for statistics-based prediction models of reservoir performance.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-01-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43238699","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}
Yuan-Jian LIN, Jiang-Feng LIU, Tao CHEN, Bing-Xiang Huang, Shi-Jia MA, Hai-Bo BAI
In this study, a thermal–hydraulic–mechanical–chemical (THMC) multi-field coupling triaxial cell was used to study systematically the evolution of gas permeability and the deformation characteristics of sandstone. The effects of confining, axial and gas pressure on gas permeability characteristics were fully considered in the test. The gas permeability of sandstone decreases with increasing confining pressure. When the confining pressure is low, the variation of gas permeability is greater than that of gas permeability at high confining pressure. The gas injection pressure significantly affects the gas permeability evolution of sandstone. As the gas injection pressure increases, the gas permeability of sandstone tends to decrease. At the same confining pressure, the gas permeability of the sample during the unloading path is less than the gas permeability of the sample in the loading path. When axial pressure is applied, it has a significant influence on the permeability evolution of sandstone. When the axial pressure is less than 30 MPa, it significantly influences the permeability evolution of sandstone. At axial pressures greater than 30 MPa, the permeability decreases as the axial pressure increases. Finally, the micro-pore/fracture structure of the sample after the gas permeability test was observed using 3D X-ray CT imaging.
{"title":"Gas permeability change with deformation and cracking of a sandstone under triaxial compression","authors":"Yuan-Jian LIN, Jiang-Feng LIU, Tao CHEN, Bing-Xiang Huang, Shi-Jia MA, Hai-Bo BAI","doi":"10.1144/petgeo2022-016","DOIUrl":"https://doi.org/10.1144/petgeo2022-016","url":null,"abstract":"In this study, a thermal–hydraulic–mechanical–chemical (THMC) multi-field coupling triaxial cell was used to study systematically the evolution of gas permeability and the deformation characteristics of sandstone. The effects of confining, axial and gas pressure on gas permeability characteristics were fully considered in the test. The gas permeability of sandstone decreases with increasing confining pressure. When the confining pressure is low, the variation of gas permeability is greater than that of gas permeability at high confining pressure. The gas injection pressure significantly affects the gas permeability evolution of sandstone. As the gas injection pressure increases, the gas permeability of sandstone tends to decrease. At the same confining pressure, the gas permeability of the sample during the unloading path is less than the gas permeability of the sample in the loading path. When axial pressure is applied, it has a significant influence on the permeability evolution of sandstone. When the axial pressure is less than 30 MPa, it significantly influences the permeability evolution of sandstone. At axial pressures greater than 30 MPa, the permeability decreases as the axial pressure increases. Finally, the micro-pore/fracture structure of the sample after the gas permeability test was observed using 3D X-ray CT imaging.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-01-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135012935","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. Correia, M. Maleki, Felipe Bruno Mesquita da Silva, A. Davolio, D. Schiozer
The geological features revealed by well production data or 4D Seismic are often neglected in data assimilation or disconnected from the geomodelling tasks through simplifications on static and dynamic data. This work provides a workflow to accurately integrate 4D seismic insights through a forward geomodelling approach and provides prior simulation models calibrated with observed dynamic data. The methodology follows four steps: (1) develop the geological model, (2) generate equiprobable geostatistical realisations based on the multiple stochastic approach, (3) apply the DLHG method (Discretized Latin Hypercube combined with Geostatistics), and (4) validate the geological consistency and uncertainty quantification using the observed dynamic data. The methodology is applied to a real turbiditic reservoir, a heavy oil field in the offshore Campos Basin, Brazil. From the 4D seismic datasets, the following data was available: (1) base survey, (2) monitor-2016, and (3) monitor-2020. The interpreted 4D seismic trends were integrated in the geological model by combining the geometrical modelling technique, for observed structural features, with the objects’ modelling approach, for the observed sand channels. The geostatistical realisations were then combined with dynamic uncertainties through the DLHG method. The quantitative validation based on the NQDS indicator showed that the generated prior simulation models encompass the observed production data. In addition, the match with observed 4D seismic data based on dRMS amplitude maps highlighted the value of adding 4D seismic information. This paper presents a successful forward modelling approach to highlight the value of 4D seismic on the calibration of simulation models prior to data assimilation.
{"title":"Integrated Approach to Improve Simulation Models in an Deepwater Heavy Oil Field with 4D seismic monitoring","authors":"M. Correia, M. Maleki, Felipe Bruno Mesquita da Silva, A. Davolio, D. Schiozer","doi":"10.1144/petgeo2022-048","DOIUrl":"https://doi.org/10.1144/petgeo2022-048","url":null,"abstract":"The geological features revealed by well production data or 4D Seismic are often neglected in data assimilation or disconnected from the geomodelling tasks through simplifications on static and dynamic data. This work provides a workflow to accurately integrate 4D seismic insights through a forward geomodelling approach and provides prior simulation models calibrated with observed dynamic data. The methodology follows four steps: (1) develop the geological model, (2) generate equiprobable geostatistical realisations based on the multiple stochastic approach, (3) apply the DLHG method (Discretized Latin Hypercube combined with Geostatistics), and (4) validate the geological consistency and uncertainty quantification using the observed dynamic data. The methodology is applied to a real turbiditic reservoir, a heavy oil field in the offshore Campos Basin, Brazil. From the 4D seismic datasets, the following data was available: (1) base survey, (2) monitor-2016, and (3) monitor-2020. The interpreted 4D seismic trends were integrated in the geological model by combining the geometrical modelling technique, for observed structural features, with the objects’ modelling approach, for the observed sand channels. The geostatistical realisations were then combined with dynamic uncertainties through the DLHG method. The quantitative validation based on the NQDS indicator showed that the generated prior simulation models encompass the observed production data. In addition, the match with observed 4D seismic data based on dRMS amplitude maps highlighted the value of adding 4D seismic information. This paper presents a successful forward modelling approach to highlight the value of 4D seismic on the calibration of simulation models prior to data assimilation.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2023-01-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44503661","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}
Gisele Nery Camargo, María González, F. Borges, A. Maul, W. Mohriak
Seismic velocity models have significant importance in subsurface studies, notably when applied in structurally challenging areas. In some parts of the Campos Basin, offshore Brazil, the pre-salt reservoir's overburden shows complex structures, mainly due to raft tectonism that positions laterally resulting in interspersed salt domes, carbonate rafts, and siliciclastic sediments. This work used an extensive well database in the Marlim Complex to analyze the raft seismic velocities and their related impacts on pre-salt reservoir models. Based on well data, in combination with detailed seismic interpretation, it was proposed seven alternative velocity scenarios for the rafts. The geological motivations for each scenario are discussed aiming to develop constrained depth models for pre-salt reservoirs. The depth forecast results could be tested by the drilled wells and resulting models are quantitatively compared in terms of depth predictions and gross-rock volumes. The results show that the topography of the target pre-salt reservoirs can vary considerably, even in scenarios where well and geological constraints are considered. This can impact pre-salt geological characterization and field development.
{"title":"Challenges for seismic velocity modelling of rafts and impacts for pre-salt depth estimations","authors":"Gisele Nery Camargo, María González, F. Borges, A. Maul, W. Mohriak","doi":"10.1144/petgeo2022-033","DOIUrl":"https://doi.org/10.1144/petgeo2022-033","url":null,"abstract":"Seismic velocity models have significant importance in subsurface studies, notably when applied in structurally challenging areas. In some parts of the Campos Basin, offshore Brazil, the pre-salt reservoir's overburden shows complex structures, mainly due to raft tectonism that positions laterally resulting in interspersed salt domes, carbonate rafts, and siliciclastic sediments. This work used an extensive well database in the Marlim Complex to analyze the raft seismic velocities and their related impacts on pre-salt reservoir models. Based on well data, in combination with detailed seismic interpretation, it was proposed seven alternative velocity scenarios for the rafts. The geological motivations for each scenario are discussed aiming to develop constrained depth models for pre-salt reservoirs. The depth forecast results could be tested by the drilled wells and resulting models are quantitatively compared in terms of depth predictions and gross-rock volumes. The results show that the topography of the target pre-salt reservoirs can vary considerably, even in scenarios where well and geological constraints are considered. This can impact pre-salt geological characterization and field development.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2022-11-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42424808","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}
Drilling infill wells into a heavily depleted reservoir poses several challenges which can lead to increased time, cost and risk. Data acquisition, including gathering formation pressure data, can be severely compromised, complicating real-time decisions and pore pressure interpretation. Fracture gradients, usually constrained by data acquired outside the reservoir, need to be estimated using a different approach through a depleted reservoir. The Jasmine HPHT Field in the UK Central North Sea can be used to illustrate some of these challenges and describe some practical solutions. A qualitative approach to estimating the level of reservoir depletion from formation gas measurements has been developed for the Jasmine Field, comparing pre-depletion gas trends against those obtained during the infill drilling campaign. The methods described here to estimate depleted fracture gradients using modelled and observed stress paths coupled to the pore pressure reduction were found to fit with well observations and have helped inform operational decisions to manage severe lost circulation events. A strategy to acquire data in memory while drilling has proved successful and has allowed lost circulation events to be managed safely. Managed Pressure Drilling has opened up narrow drilling windows and has reduced the number of hole sizes and liners required to drill these infill wells. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/topic/collections/geopressure
{"title":"Jasmine: The challenges of delivering infill wells in a variably depleted HPHT field","authors":"Brian A. MacLeod","doi":"10.1144/petgeo2022-019","DOIUrl":"https://doi.org/10.1144/petgeo2022-019","url":null,"abstract":"Drilling infill wells into a heavily depleted reservoir poses several challenges which can lead to increased time, cost and risk. Data acquisition, including gathering formation pressure data, can be severely compromised, complicating real-time decisions and pore pressure interpretation. Fracture gradients, usually constrained by data acquired outside the reservoir, need to be estimated using a different approach through a depleted reservoir. The Jasmine HPHT Field in the UK Central North Sea can be used to illustrate some of these challenges and describe some practical solutions. A qualitative approach to estimating the level of reservoir depletion from formation gas measurements has been developed for the Jasmine Field, comparing pre-depletion gas trends against those obtained during the infill drilling campaign. The methods described here to estimate depleted fracture gradients using modelled and observed stress paths coupled to the pore pressure reduction were found to fit with well observations and have helped inform operational decisions to manage severe lost circulation events. A strategy to acquire data in memory while drilling has proved successful and has allowed lost circulation events to be managed safely. Managed Pressure Drilling has opened up narrow drilling windows and has reduced the number of hole sizes and liners required to drill these infill wells.\u0000 \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":"2022-11-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41842560","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}
Deformation bands are usually responsible for up to 3 orders of magnitude reduction in permeability perpendicularly to the structure planes, while the fault core represent a reduction of up to 7 orders of magnitude in cross-fault permeability, imposing large anisotropies to fluid flow. As deformation bands occur distributed along the damage zone, they impact not only the across-fault flow, but also the along-fault flow. The fault core is usually represented by fault transmissibility multipliers (TMs), along the fault planes, using well established workflows. However, there is a lack of methods to represent fault damage zones in any direction and grid cell sizes. In this context, we proposed new methods to: (1) estimate the deformation intensity in damage zones; (2) calculate their most representative value within the cell domain; (3) calculate the equivalent permeability of a cell containing oblique deformation bands. The workflow is applied to the 3D numerical model of the Santa Helena High, in Rio do Peixe Basin, NE Brazil. We performed streamline simulations in 4 models to evaluate the impact of fault damage zones and the fault core in fluid flow. Our models show that the fault core and damage zone negatively affected the performance of the reservoir. Supplementary material: Appendix A, describing the method developed to estimate the deformation intensity in damage zones, and Appendix B, describing the method develop to calculate the equivalent permeability, are available at https://doi.org/10.6084/m9.figshare.c.6251469
变形带通常使垂直于构造面的渗透率降低3个数量级，而断层核则使断层间渗透率降低7个数量级，使流体流动具有较大的各向异性。变形带沿破坏带分布，不仅影响断层间流动，而且影响断层顺行流动。故障核通常由故障传递率乘法器(TMs)表示，沿着故障平面，使用完善的工作流程。然而，缺乏在任意方向和网格大小上表示断层损伤区的方法。在此背景下，我们提出了新的方法:(1)估计损伤区域的变形强度;(2)计算它们在胞域内最具代表性的值;(3)计算含斜变形带单元的等效渗透率。该工作流程应用于巴西东北部里约热内卢do Peixe盆地Santa Helena High的三维数值模型。利用4个模型进行流线模拟，评价断层破坏带和断层核对流体流动的影响。我们的模型表明，断层核和损伤带对储层的性能有负面影响。补充资料:附录A描述了用于估计损伤区变形强度的方法，附录B描述了用于计算等效渗透率的方法，可在https://doi.org/10.6084/m9.figshare.c.6251469上获得
{"title":"3D numerical modeling and simulation of the impact of fault zones on fluid flow in sandstones of the Rio do Peixe Basin, NE Brazil","authors":"R. Stohler, F. Nogueira, C. L. Mello, J. Souza","doi":"10.1144/petgeo2022-024","DOIUrl":"https://doi.org/10.1144/petgeo2022-024","url":null,"abstract":"Deformation bands are usually responsible for up to 3 orders of magnitude reduction in permeability perpendicularly to the structure planes, while the fault core represent a reduction of up to 7 orders of magnitude in cross-fault permeability, imposing large anisotropies to fluid flow. As deformation bands occur distributed along the damage zone, they impact not only the across-fault flow, but also the along-fault flow. The fault core is usually represented by fault transmissibility multipliers (TMs), along the fault planes, using well established workflows. However, there is a lack of methods to represent fault damage zones in any direction and grid cell sizes. In this context, we proposed new methods to: (1) estimate the deformation intensity in damage zones; (2) calculate their most representative value within the cell domain; (3) calculate the equivalent permeability of a cell containing oblique deformation bands. The workflow is applied to the 3D numerical model of the Santa Helena High, in Rio do Peixe Basin, NE Brazil. We performed streamline simulations in 4 models to evaluate the impact of fault damage zones and the fault core in fluid flow. Our models show that the fault core and damage zone negatively affected the performance of the reservoir.\u0000 \u0000 Supplementary material:\u0000 Appendix A, describing the method developed to estimate the deformation intensity in damage zones, and Appendix B, describing the method develop to calculate the equivalent permeability, are available at\u0000 https://doi.org/10.6084/m9.figshare.c.6251469\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2022-10-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49036511","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}
Ben A. Kilhams, Lauren Chedburn, Lucinda K. Layfield, N. Schofield, Ingelin Løkling Lunde, L. Kennan, Hollie G. Romain, D. Jolley, C. Eide
The sub-basalt domain of the Norwegian continental shelf (NCS) is one of the last remaining hydrocarbon exploration frontiers in Europe. While there is an established geological and tectonic framework, little has been published that addresses the remaining hydrocarbon exploration risks/uncertainties. Unlike the Faroe Shetland Basin and Rockall Trough, at the time of writing, there are currently no industry-drilled sub-basalt well penetrations on the Norwegian continental shelf. Numerous potential Mesozoic sub-basalt hydrocarbon plays exist on the NCS but, due to the lack of industry-drilled sub-basalt penetrations, there is a perceived large exploration risk. By using cross-border analogues, basin modelling workflows and integration of available seismic data the main uncertainties across the NCS are outlined including charge timing, structural definition, and details of reservoir presence. Generically the Late Cretaceous and Middle Jurassic intervals are potential plays which may be present on the Norwegian Margin. However, there is considerable uncertainty on their depth and preservation. Although significant challenges and uncertainties remain, the authors believe that the integration of well results, consideration of basin modelling driven heat flow estimates and new 3D seismic data may open sub-basalt opportunities for a new exploration frontier on the NCS. Thematic collection: This article is part of the New learning from exploration and development in 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":"Challenges and opportunities for hydrocarbon exploration within the Mesozoic sub-basalt plays of the Norwegian Atlantic Margin","authors":"Ben A. Kilhams, Lauren Chedburn, Lucinda K. Layfield, N. Schofield, Ingelin Løkling Lunde, L. Kennan, Hollie G. Romain, D. Jolley, C. Eide","doi":"10.1144/petgeo2022-022","DOIUrl":"https://doi.org/10.1144/petgeo2022-022","url":null,"abstract":"The sub-basalt domain of the Norwegian continental shelf (NCS) is one of the last remaining hydrocarbon exploration frontiers in Europe. While there is an established geological and tectonic framework, little has been published that addresses the remaining hydrocarbon exploration risks/uncertainties. Unlike the Faroe Shetland Basin and Rockall Trough, at the time of writing, there are currently no industry-drilled sub-basalt well penetrations on the Norwegian continental shelf. Numerous potential Mesozoic sub-basalt hydrocarbon plays exist on the NCS but, due to the lack of industry-drilled sub-basalt penetrations, there is a perceived large exploration risk. By using cross-border analogues, basin modelling workflows and integration of available seismic data the main uncertainties across the NCS are outlined including charge timing, structural definition, and details of reservoir presence. Generically the Late Cretaceous and Middle Jurassic intervals are potential plays which may be present on the Norwegian Margin. However, there is considerable uncertainty on their depth and preservation. Although significant challenges and uncertainties remain, the authors believe that the integration of well results, consideration of basin modelling driven heat flow estimates and new 3D seismic data may open sub-basalt opportunities for a new exploration frontier on the NCS.\u0000 \u0000 Thematic collection:\u0000 This article is part of the New learning from exploration and development in 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":"2022-10-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44855222","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}
Nora Holden, J. Osmond, M. Mulrooney, A. Braathen, E. Skurtveit, Anja Sundal
Faults play an essential role at many potential CO 2 storage sites because they can act as conduits or barriers to fluid flow. To contribute to the evaluation of the Aurora storage site in the northern North Sea, we perform a structural characterization and assessment of across-fault seals that displace the Lower Jurassic storage complex. We find that first-order faults are predominately N–S-striking, and W-dipping, with throws greater than the thickness of the primary seal (>85 m). In contrast, second-order faults have lower throws (15–50 m) and variable strike and dip directions. Due to the dip of the storage complex, injected CO 2 is likely to migrate northwards before encountering the first-order Svartalv Fault Zone on its footwall side, which juxtaposes the storage units against younger sand-rich units. However, shale gouge ratio values exceed 0.30 at the depth of the storage complex, suggesting that a fault membrane seal may be present. Furthermore, second-order NE-dipping faults create juxtaposition seals and, in places, small-scale structural traps (24–48 m) along the Svartalv Fault Zone. Overall, we suggest that faults within the Aurora storage site could provide barriers to plume migration allowing more CO 2 to become trapped, thereby increasing the storage capacity. This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
{"title":"Structural characterization and across-fault seal assessment of the Aurora CO\u0000 2\u0000 storage site, northern North Sea","authors":"Nora Holden, J. Osmond, M. Mulrooney, A. Braathen, E. Skurtveit, Anja Sundal","doi":"10.1144/petgeo2022-036","DOIUrl":"https://doi.org/10.1144/petgeo2022-036","url":null,"abstract":"\u0000 Faults play an essential role at many potential CO\u0000 2\u0000 storage sites because they can act as conduits or barriers to fluid flow. To contribute to the evaluation of the Aurora storage site in the northern North Sea, we perform a structural characterization and assessment of across-fault seals that displace the Lower Jurassic storage complex. We find that first-order faults are predominately N–S-striking, and W-dipping, with throws greater than the thickness of the primary seal (>85 m). In contrast, second-order faults have lower throws (15–50 m) and variable strike and dip directions. Due to the dip of the storage complex, injected CO\u0000 2\u0000 is likely to migrate northwards before encountering the first-order Svartalv Fault Zone on its footwall side, which juxtaposes the storage units against younger sand-rich units. However, shale gouge ratio values exceed 0.30 at the depth of the storage complex, suggesting that a fault membrane seal may be present. Furthermore, second-order NE-dipping faults create juxtaposition seals and, in places, small-scale structural traps (24–48 m) along the Svartalv Fault Zone. Overall, we suggest that faults within the Aurora storage site could provide barriers to plume migration allowing more CO\u0000 2\u0000 to become trapped, thereby increasing the storage capacity.\u0000 \u0000 \u0000 This article is part of the Energy Geoscience Series available at\u0000 https://www.lyellcollection.org/cc/energy-geoscience-series\u0000","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2022-09-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44840668","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}
Fracture pressure models are used to create pre-drill fracture pressure/depth plots essential to the design of drilling and casing programs in oil and gas wells, and future development of carbon capture and underground storage. Some of these models include an empirical term (stress ratio) which relates effective horizontal stress to effective vertical stress. Based on the literature, stress ratio is assumed to vary with compaction and can be calculated from Poisson's ratio (ν). An alternative to models which utilize the stress ratio term is a model which relates fracture pressure to a constant fraction of the vertical stress. This paper demonstrates that a constant fraction of vertical stress is equivalent to a stress ratio which increases slightly with depth.Estimation of how the ν changes with compaction is complicated by the multiple methods which are commonly employed to measure ν. The available static and dynamic ν data suggest a substantial decrease in ν with porosity reduction. Evaluation of in situ ν data from leak-off tests (LOTS) and associated fluid pressure data in Tertiary Basins indicates that in situ ν does not decline as rapidly as indicated by the other methods of ν determination. In situ ν data indicate that calibration of stress ratio from traditional ν methods is not appropriate and may substantially underestimate fracture pressure (Fp).Fracture pressure models which utilize a constant fraction of vertical stress or estimate stress ratio empirically from LOT data should be employed for pre-drill estimation of fracture pressure.Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure
{"title":"Fracture Pressure, Leak-Off Tests and Poisson's Ratio","authors":"R. Lahann, R. Swarbrick","doi":"10.1144/petgeo2021-103","DOIUrl":"https://doi.org/10.1144/petgeo2021-103","url":null,"abstract":"Fracture pressure models are used to create pre-drill fracture pressure/depth plots essential to the design of drilling and casing programs in oil and gas wells, and future development of carbon capture and underground storage. Some of these models include an empirical term (stress ratio) which relates effective horizontal stress to effective vertical stress. Based on the literature, stress ratio is assumed to vary with compaction and can be calculated from Poisson's ratio (ν). An alternative to models which utilize the stress ratio term is a model which relates fracture pressure to a constant fraction of the vertical stress. This paper demonstrates that a constant fraction of vertical stress is equivalent to a stress ratio which increases slightly with depth.Estimation of how the ν changes with compaction is complicated by the multiple methods which are commonly employed to measure ν. The available static and dynamic ν data suggest a substantial decrease in ν with porosity reduction. Evaluation of in situ ν data from leak-off tests (LOTS) and associated fluid pressure data in Tertiary Basins indicates that in situ ν does not decline as rapidly as indicated by the other methods of ν determination. In situ ν data indicate that calibration of stress ratio from traditional ν methods is not appropriate and may substantially underestimate fracture pressure (Fp).Fracture pressure models which utilize a constant fraction of vertical stress or estimate stress ratio empirically from LOT data should be employed for pre-drill estimation of fracture pressure.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":null,"pages":null},"PeriodicalIF":1.7,"publicationDate":"2022-07-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41392704","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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