Jingtao Zhang, Haipeng Zhang, Donghee Lee, S. Ryu, Seunghee Kim
Various energy recovery, storage, conversion and environmental operations may involve repetitive fluid injection and thus, cyclic drainage–imbibition processes. We conducted an experimental study for which polydimethylsiloxane (PDMS)-based micromodels were fabricated with three different levels of pore-space heterogeneity (coefficient of variation, where COV = 0, 0.25 and 0.5) to represent consolidated and/or partially consolidated sandstones. A total of 10 injection-withdrawal cycles were applied to each micromodel at two different flow rates (0.01 and 0.1 ml min−1). The experimental results were analysed in terms of flow morphology, sweep efficiency, residual saturation, the connection of fluids and the pressure gradient. The pattern of the invasion and displacement of the non-wetting fluid converged more readily in the homogeneous model (COV = 0) as the repetitive drainage–imbibition process continued. The overall sweep efficiency converged between 0.4 and 0.6 at all tested flow rates, regardless of different flow rates and COV in this study. In contrast, the effective sweep efficiency was observed to increase with higher COV at the lower flow rate, while that trend became reversed at the higher flow rate. Similarly, the residual saturation of the non-wetting fluid was largest at COV = 0 for the lower flow rate, but it was the opposite for the higher flow-rate case. However, the Minkowski functionals for the boundary length and connectedness of the non-wetting fluid remained quite constant during repetitive fluid flow. Implications of the study results for porous media-compressed air energy storage (PM-CAES) are discussed as a complementary analysis at the end of this paper. Supplementary material: Figures showing the distribution of water (Fig. S1) and oil (Fig. S2) at the end of each drainage and imbibition step in different microfluidic pore-network models are available at https://doi.org/10.6084/m9.figshare.c.5276814 Thematic collection: This article is part of the Energy Geoscience Series available at: https://www.lyellcollection.org/cc/energy-geoscience-series
各种能量回收、储存、转换和环境操作可能涉及重复的流体注入，从而涉及循环排水吸胀过程。我们进行了一项实验研究，基于聚二甲基硅氧烷(PDMS)的微模型具有三种不同水平的孔隙空间非均质性(变异系数，其中COV = 0, 0.25和0.5)来代表固结和/或部分固结的砂岩。在两种不同的流速(0.01和0.1 ml min - 1)下，每个微模型共进行10个注射-退出周期。从流动形态、波及效率、残余饱和度、流体连通性和压力梯度等方面对实验结果进行了分析。随着重复排吸过程的继续，非润湿流体的侵入和驱替模式更容易在均匀模型(COV = 0)中收敛。在本研究中，无论不同的流量和冠状病毒，在所有测试流量下，总波及效率都收敛在0.4 ~ 0.6之间。相比之下，在低流量下，有效波及效率随冠状病毒数的增加而增加，而在高流量下，这一趋势则相反。同样，当COV = 0时，低流量下非润湿流体的剩余饱和度最大，高流量下则相反。然而，非润湿流体的边界长度和连通性的Minkowski泛函在重复流体流动中保持相当恒定。本文最后对多孔介质压缩空气储能(PM-CAES)的研究结果进行了补充分析。补充资料:不同微流体孔隙网络模型中每个排水和渗吸阶段结束时的水(图S1)和油(图S2)分布图可在https://doi.org/10.6084/m9.figshare.c.5276814上找到。专题合集:这篇文章是能源地球科学系列的一部分，可在https://www.lyellcollection.org/cc/energy-geoscience-series上找到
{"title":"Study on the effect of pore-scale heterogeneity and flow rate during repetitive two-phase fluid flow in microfluidic porous media","authors":"Jingtao Zhang, Haipeng Zhang, Donghee Lee, S. Ryu, Seunghee Kim","doi":"10.1144/petgeo2020-062","DOIUrl":"https://doi.org/10.1144/petgeo2020-062","url":null,"abstract":"Various energy recovery, storage, conversion and environmental operations may involve repetitive fluid injection and thus, cyclic drainage–imbibition processes. We conducted an experimental study for which polydimethylsiloxane (PDMS)-based micromodels were fabricated with three different levels of pore-space heterogeneity (coefficient of variation, where COV = 0, 0.25 and 0.5) to represent consolidated and/or partially consolidated sandstones. A total of 10 injection-withdrawal cycles were applied to each micromodel at two different flow rates (0.01 and 0.1 ml min−1). The experimental results were analysed in terms of flow morphology, sweep efficiency, residual saturation, the connection of fluids and the pressure gradient. The pattern of the invasion and displacement of the non-wetting fluid converged more readily in the homogeneous model (COV = 0) as the repetitive drainage–imbibition process continued. The overall sweep efficiency converged between 0.4 and 0.6 at all tested flow rates, regardless of different flow rates and COV in this study. In contrast, the effective sweep efficiency was observed to increase with higher COV at the lower flow rate, while that trend became reversed at the higher flow rate. Similarly, the residual saturation of the non-wetting fluid was largest at COV = 0 for the lower flow rate, but it was the opposite for the higher flow-rate case. However, the Minkowski functionals for the boundary length and connectedness of the non-wetting fluid remained quite constant during repetitive fluid flow. Implications of the study results for porous media-compressed air energy storage (PM-CAES) are discussed as a complementary analysis at the end of this paper. Supplementary material: Figures showing the distribution of water (Fig. S1) and oil (Fig. S2) at the end of each drainage and imbibition step in different microfluidic pore-network models are available at https://doi.org/10.6084/m9.figshare.c.5276814 Thematic collection: This article is part of the Energy Geoscience Series available at: https://www.lyellcollection.org/cc/energy-geoscience-series","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2021-01-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42011849","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}
R. Payton, M. Fellgett, B. Clark, D. Chiarella, A. Kingdon, S. Hier‐Majumder
The growing importance of subsurface carbon storage for tackling anthropogenic carbon emissions requires new ideas to improve the rate and cost of carbon capture and storage (CCS) project development and implementation. We assessed sandstones from the UK Geoenergy Observatories (UKGEOS) site in Glasgow, UK and the Wilmslow Sandstone Formation (WSF) in Cumbria, UK at the pore scale to indicate suitability for further assessment as CCS reservoirs. We measured porosity, permeability and other pore geometry characteristics using digital rock physics techniques on microcomputed tomographic images of core material from each site. We found the Glasgow material to be unsuitable for CCS due to very low porosity (up to 1.65%), whereas the WSF material showed connected porosity up to 26.3% and permeabilities up to 6040 mD. Our results support the presence of a percolation threshold at 10% total porosity, introducing near full connectivity. We found total porosity varies with permeability with an exponent of 3.19. This provides a reason to assume near full connectivity in sedimentary samples showing porosities above this threshold without the need for expensive and time-consuming analyses. Supplementary material: Information about the boreholes sampled in this study, additional well logs of boreholes and a summary of the supporting data plotted throughout this article from literature are available at https://doi.org/10.6084/m9.figshare.c.5260074 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":"Pore-scale assessment of subsurface carbon storage potential: implications for the UK Geoenergy Observatories project","authors":"R. Payton, M. Fellgett, B. Clark, D. Chiarella, A. Kingdon, S. Hier‐Majumder","doi":"10.1144/petgeo2020-092","DOIUrl":"https://doi.org/10.1144/petgeo2020-092","url":null,"abstract":"The growing importance of subsurface carbon storage for tackling anthropogenic carbon emissions requires new ideas to improve the rate and cost of carbon capture and storage (CCS) project development and implementation. We assessed sandstones from the UK Geoenergy Observatories (UKGEOS) site in Glasgow, UK and the Wilmslow Sandstone Formation (WSF) in Cumbria, UK at the pore scale to indicate suitability for further assessment as CCS reservoirs. We measured porosity, permeability and other pore geometry characteristics using digital rock physics techniques on microcomputed tomographic images of core material from each site. We found the Glasgow material to be unsuitable for CCS due to very low porosity (up to 1.65%), whereas the WSF material showed connected porosity up to 26.3% and permeabilities up to 6040 mD. Our results support the presence of a percolation threshold at 10% total porosity, introducing near full connectivity. We found total porosity varies with permeability with an exponent of 3.19. This provides a reason to assume near full connectivity in sedimentary samples showing porosities above this threshold without the need for expensive and time-consuming analyses. Supplementary material: Information about the boreholes sampled in this study, additional well logs of boreholes and a summary of the supporting data plotted throughout this article from literature are available at https://doi.org/10.6084/m9.figshare.c.5260074 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":"2021-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45243094","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}
G. Bertolini, A. Hartley, J. Marques, D. Healy, J. Frantz
An analysis of the petrophysical and diagenetic effects of the emplacement of Cretaceous basaltic lava flows (Serra Geral Formation) on aeolian sandstones (Botucatu Formation) has been undertaken on core samples from the Paraná Basin, Brazil. Between 0.1 and 1 m from the contact zone, acoustic wave velocities and porosities in sandstones show a significantly wider scatter than those located >1 m away from the lava contact. Higher P-wave values (average 3759.3 m s−1) occur between 0.1 and 1 m from the lava contact in contrast to those areas >1 m away (average 3376.8 m s−1), whilst the average porosity is 6.5% near the contact (0.1–1 m) and 10.7% away from the contact (>1 m). Petrographical evaluation reveals two diagenetic pathways responsible for modification of the petrophysical properties: early hydrothermal Mg-rich authigenesis (Type 1) and early chemical dissolution (Type 2). Type 3 diagenesis occurs away from the lava–sediment contact (>1 m), with the appearance of poikilitic calcite and smectite. The sandstone samples associated with Type 1 and Type 2 diagenesis display a decrease in porosity and increased acoustic velocities in relation to Type 3, while Type 3 samples show little or no variation in reservoir properties. The lava-induced diagenetic effects at the sandstone–lava contacts (0.1–1 m) may form a baffle or seal to fluids around the margins of the sandstone bodies. Therefore, whilst diagenesis associated with lava emplacement may hinder reservoir quality around the margins, the original reservoir properties are preserved within these large sandstone bodies. Supplementary material: Petrophysical and petrographical data are available at https://doi.org/10.6084/m9.figshare.c.5244473
对巴西巴拉那盆地的岩芯样本进行了白垩纪玄武岩熔岩流（Serra Geral组）在风成砂岩（Botucau组）上侵位的岩石物理和成岩作用分析。介于0.1和1之间 距离接触带m处，砂岩中的声波速度和孔隙率显示出比位于>1处的砂岩明显更宽的散射 m距离熔岩接触处。较高的P波值（平均3759.3 m s−1）出现在0.1和1之间 与那些>1的区域相比，距离熔岩接触面m m（平均3376.8 m s−1），而接触附近的平均孔隙率为6.5%（0.1–1 m） 距离接触10.7%（>1 m） 。岩石学评价揭示了导致岩石物理性质改变的两种成岩途径：早期热液富镁自生（类型1）和早期化学溶解（类型2）。第3类成岩作用发生在远离熔岩-沉积物接触的地方（>1 m） ，外观为方晶方解石和蒙脱石。与类型3相比，与类型1和类型2成岩作用相关的砂岩样品显示出孔隙度降低和声速增加，而类型3样品显示出储层性质几乎没有变化。熔岩在砂岩-熔岩接触处引起的成岩作用（0.1–1 m） 可以对砂岩体边缘周围的流体形成挡板或密封。因此，虽然与熔岩侵位相关的成岩作用可能会阻碍边缘的储层质量，但这些大型砂岩体内保留了原始的储层性质。补充材料：岩石物理和岩石学数据可在https://doi.org/10.6084/m9.figshare.c.5244473
{"title":"The effects of basaltic lava flows on the petrophysical properties and diagenesis of interbedded aeolian sandstones: an example from the Cretaceous Paraná Basin, Brazil","authors":"G. Bertolini, A. Hartley, J. Marques, D. Healy, J. Frantz","doi":"10.1144/petgeo2020-036","DOIUrl":"https://doi.org/10.1144/petgeo2020-036","url":null,"abstract":"An analysis of the petrophysical and diagenetic effects of the emplacement of Cretaceous basaltic lava flows (Serra Geral Formation) on aeolian sandstones (Botucatu Formation) has been undertaken on core samples from the Paraná Basin, Brazil. Between 0.1 and 1 m from the contact zone, acoustic wave velocities and porosities in sandstones show a significantly wider scatter than those located >1 m away from the lava contact. Higher P-wave values (average 3759.3 m s−1) occur between 0.1 and 1 m from the lava contact in contrast to those areas >1 m away (average 3376.8 m s−1), whilst the average porosity is 6.5% near the contact (0.1–1 m) and 10.7% away from the contact (>1 m). Petrographical evaluation reveals two diagenetic pathways responsible for modification of the petrophysical properties: early hydrothermal Mg-rich authigenesis (Type 1) and early chemical dissolution (Type 2). Type 3 diagenesis occurs away from the lava–sediment contact (>1 m), with the appearance of poikilitic calcite and smectite. The sandstone samples associated with Type 1 and Type 2 diagenesis display a decrease in porosity and increased acoustic velocities in relation to Type 3, while Type 3 samples show little or no variation in reservoir properties. The lava-induced diagenetic effects at the sandstone–lava contacts (0.1–1 m) may form a baffle or seal to fluids around the margins of the sandstone bodies. Therefore, whilst diagenesis associated with lava emplacement may hinder reservoir quality around the margins, the original reservoir properties are preserved within these large sandstone bodies. Supplementary material: Petrophysical and petrographical data are available at https://doi.org/10.6084/m9.figshare.c.5244473","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-12-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44361823","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}
Naturally fractured reservoirs are important contributors to global petroleum reserves and production. Existing classification schemes for fractured reservoirs do not adequately differentiate between certain types of fractured reservoirs, leading to difficulty in understanding fundamental controls on reservoir performance and recovery efficiency. Three hundred naturally fractured reservoirs were examined to define a new classification scheme that is independent of the type of fracturing and describes fundamentally different matrix types, rock properties, fluid storage and flow characteristics. This study categorises fractured reservoirs in three groups: (1) Type 1: characterized by a tight matrix where fractures and solution-enhanced fracture porosity provide both storage capacity and fluid-flow pathways; (2) Type 2: characterized by a macroporous matrix which provides the primary storage capacity where fractures and solution-enhanced fracture porosity provide essential fluid-flow pathways; and (3) Type 3: characterized by a microporous matrix which provides all storage capacity where fractures only provide essential fluid-flow pathways. Differentiation is made between controls imparted by inherent natural conditions, such as rock and fluid properties and natural drive mechanisms, and human controls, such as choice of development scheme and reservoir management practices. The classification scheme presented here is based on reservoir and production characteristics of naturally fractured reservoirs and represents a refinement of existing schemes. This refinement allows accurate comparisons to be made between analogous fractured reservoirs, and trends and outliers in reservoir performance to be identified. Case histories provided herein demonstrate the practical application of this new classification scheme and the benefits that arise when applying it to the understanding of naturally fractured reservoirs.
{"title":"Optimising development and production of naturally fractured reservoirs using a large empirical dataset","authors":"Shaoqing Sun, D. A. Pollitt","doi":"10.1144/petgeo2020-079","DOIUrl":"https://doi.org/10.1144/petgeo2020-079","url":null,"abstract":"Naturally fractured reservoirs are important contributors to global petroleum reserves and production. Existing classification schemes for fractured reservoirs do not adequately differentiate between certain types of fractured reservoirs, leading to difficulty in understanding fundamental controls on reservoir performance and recovery efficiency. Three hundred naturally fractured reservoirs were examined to define a new classification scheme that is independent of the type of fracturing and describes fundamentally different matrix types, rock properties, fluid storage and flow characteristics. This study categorises fractured reservoirs in three groups: (1) Type 1: characterized by a tight matrix where fractures and solution-enhanced fracture porosity provide both storage capacity and fluid-flow pathways; (2) Type 2: characterized by a macroporous matrix which provides the primary storage capacity where fractures and solution-enhanced fracture porosity provide essential fluid-flow pathways; and (3) Type 3: characterized by a microporous matrix which provides all storage capacity where fractures only provide essential fluid-flow pathways. Differentiation is made between controls imparted by inherent natural conditions, such as rock and fluid properties and natural drive mechanisms, and human controls, such as choice of development scheme and reservoir management practices. The classification scheme presented here is based on reservoir and production characteristics of naturally fractured reservoirs and represents a refinement of existing schemes. This refinement allows accurate comparisons to be made between analogous fractured reservoirs, and trends and outliers in reservoir performance to be identified. Case histories provided herein demonstrate the practical application of this new classification scheme and the benefits that arise when applying it to the understanding of naturally fractured reservoirs.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"27 1","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"64015547","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}
Regarding the first issue highlighted by Power and Murray (2020), Bretan et al. (2020) presented a meta-analysis of 38 datasets to attempt to synthesise observations made independently by many different authors. As such, it is inappropriate to include all of the data for every example. References to the original publications are given where available, and we discussed the relative reliability of the various studies. As Power andMurray (2020) mention, confidentiality restrictions place limits on what can be published. Murray et al. (2020) acknowledged the same issue in their contribution to SP496: ‘In addition to the six case studies presented, more than 87 additional hydrocarbon accumulations from 36 additional fields have been analysed. The full details of these accumulations cannot be published because of confidentially restrictions’. Regarding the second issue, Power and Murray (2020) raise points of interpretation of the original analysis of Oseberg Sør by Fristad et al. (1997). This case study was only given extra prominence in our paper because it is an oft-quoted and groundbreaking example of the SGR method. Although the work is now nearly 25 years old we will endeavour to answer Power and Murray’s points.
{"title":"Reply to Discussion on ‘A knowledge database of hanging-wall traps that are dependent on fault-rock seal’, Geological Society, London, Special Publication, 496, 209–222, https://doi.org/10.1144/SP496-2018-157","authors":"P. Bretan, G. Yielding, E. Sverdrup","doi":"10.1144/petgeo2020-101","DOIUrl":"https://doi.org/10.1144/petgeo2020-101","url":null,"abstract":"Regarding the first issue highlighted by Power and Murray (2020), Bretan et al. (2020) presented a meta-analysis of 38 datasets to attempt to synthesise observations made independently by many different authors. As such, it is inappropriate to include all of the data for every example. References to the original publications are given where available, and we discussed the relative reliability of the various studies. As Power andMurray (2020) mention, confidentiality restrictions place limits on what can be published. Murray et al. (2020) acknowledged the same issue in their contribution to SP496: ‘In addition to the six case studies presented, more than 87 additional hydrocarbon accumulations from 36 additional fields have been analysed. The full details of these accumulations cannot be published because of confidentially restrictions’. Regarding the second issue, Power and Murray (2020) raise points of interpretation of the original analysis of Oseberg Sør by Fristad et al. (1997). This case study was only given extra prominence in our paper because it is an oft-quoted and groundbreaking example of the SGR method. Although the work is now nearly 25 years old we will endeavour to answer Power and Murray’s points.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-12-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46629273","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 discussion responds to the paper by Bretan et al. (2020), specifically mentioning two issues. The first has to do with open science and the accessibility of datasets so that other scientists and the public can test and re-evaluate the work done by others. The second issue we raise concerns a specific conclusion presented in the paper, namely the implied assertion that fault-rock seal is the only explanation for observed pressure differentials between two nearby wells in the Oseberg Sør Field (Norwegian North Sea). The paper by Bretan et al. (2020) tabulates thirty-eight hanging wall hydrocarbon accumulations which the authors stated are dependent on some form of fault seal. The locations and a limited amount of supporting data for seventeen of the thirty-eight accumulations are available, but the data that are available are insufficient in most cases to allow for the analysis and conclusions to be verified independently. We acknowledge that in some cases, it is impossible to publish all the data that were used because of confidentiality restrictions. However, many important data that are easy to publish are not available, and we wish to call for a more widespread release of key data when possible. The Oseberg Sør Field is the only case study from the ‘knowledge database’ that is presented with sufficient data to allow an attempt at replication of the paper’s premises. This discussion summarizes attempts to replicate the conclusions for the Oseberg Sør Field and presents some concerns with the inclusion of this field in the table of fault seal cases. The analysis of Oseberg Sør that is presented elaborates on Fristad et al. (1997) and Yielding et al. (1997). The data in these papers are summarized in Table 1. The most notable addition from Bretan et al. (2020) is a structure contour map. A conclusion of these three papers is that a fault-rock seal on Fault-1 supports a pressure differential of 7.2 bars (refer to the map in Bretan et al. (2020) for the location of Fault-1).
这个讨论回应了Bretan et al.(2020)的论文，特别提到了两个问题。第一个与开放科学和数据集的可访问性有关，这样其他科学家和公众就可以测试和重新评估其他人的工作。我们提出的第二个问题与论文中提出的一个具体结论有关，即暗示断层岩密封是Oseberg Sør油田(挪威北海)附近两口井之间观察到的压力差的唯一解释。Bretan等人(2020)的论文列出了38个上盘油气聚集，作者认为这些油气聚集依赖于某种形式的断层封闭性。38个积累点中有17个的地点和数量有限的支持数据是可用的，但在大多数情况下，可用的数据不足以使分析和结论得到独立核实。我们承认，在某些情况下，由于保密限制，不可能公布所使用的所有数据。然而，许多容易发布的重要数据无法获得，我们希望呼吁在可能的情况下更广泛地发布关键数据。Oseberg Sør油田是“知识数据库”中唯一一个具有足够数据的案例研究，可以尝试复制本文的前提。本文总结了在Oseberg Sør油田复制上述结论的尝试，并提出了将该油田纳入断层封闭性案例表的一些问题。所提出的Oseberg Sør的分析详细阐述了Fristad等人(1997)和yield等人(1997)。这些论文的数据汇总在表1中。Bretan等人(2020)最值得注意的补充是结构等高线图。这三篇论文的结论是，1号断层上的断层岩密封支撑着7.2巴的压差(关于1号断层的位置，请参阅Bretan et al.(2020)的地图)。
{"title":"Discussion on ‘A knowledge database of hanging-wall traps that are dependent on fault-rock seal’, Geological Society, London, Special Publications, 496, 209–222, https://doi.org/10.1144/SP496-2018-157","authors":"W. Power, T. Murray","doi":"10.1144/petgeo2020-081","DOIUrl":"https://doi.org/10.1144/petgeo2020-081","url":null,"abstract":"This discussion responds to the paper by Bretan et al. (2020), specifically mentioning two issues. The first has to do with open science and the accessibility of datasets so that other scientists and the public can test and re-evaluate the work done by others. The second issue we raise concerns a specific conclusion presented in the paper, namely the implied assertion that fault-rock seal is the only explanation for observed pressure differentials between two nearby wells in the Oseberg Sør Field (Norwegian North Sea). The paper by Bretan et al. (2020) tabulates thirty-eight hanging wall hydrocarbon accumulations which the authors stated are dependent on some form of fault seal. The locations and a limited amount of supporting data for seventeen of the thirty-eight accumulations are available, but the data that are available are insufficient in most cases to allow for the analysis and conclusions to be verified independently. We acknowledge that in some cases, it is impossible to publish all the data that were used because of confidentiality restrictions. However, many important data that are easy to publish are not available, and we wish to call for a more widespread release of key data when possible. The Oseberg Sør Field is the only case study from the ‘knowledge database’ that is presented with sufficient data to allow an attempt at replication of the paper’s premises. This discussion summarizes attempts to replicate the conclusions for the Oseberg Sør Field and presents some concerns with the inclusion of this field in the table of fault seal cases. The analysis of Oseberg Sør that is presented elaborates on Fristad et al. (1997) and Yielding et al. (1997). The data in these papers are summarized in Table 1. The most notable addition from Bretan et al. (2020) is a structure contour map. A conclusion of these three papers is that a fault-rock seal on Fault-1 supports a pressure differential of 7.2 bars (refer to the map in Bretan et al. (2020) for the location of Fault-1).","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-12-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46733750","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}
Kachalla Aliyuda, J. Howell, A. Hartley, Aliyuda Ali
A number of geological and engineering parameters influence and control the performance and ultimate recovery from an oil reservoir. These are commonly interlinked and the relative importance of each can be difficult to unravel. These variables include geological parameters such as depositional environment, which has long been considered to be a key factor influencing the production characteristics of fields. However, quantifying the importance of any single factor, such as depositional environment, is complicated by the impact of the other variables (geological and engineering) and their numerous interdependencies. The main aim of this study is to unravel the impact of the depositional environment and primary facies architecture on reservoir performance using an empirical study of oilfields from the Norwegian Continental Shelf. A database of 91 fields, with a total of 7.8 Bbbl (billion barrels) of oil in place, has been built. Within this a total of 93 clastic reservoirs were classified into three gross depositional environments: continental, paralic/shallow marine and deep marine. The reservoirs were further classified into eight depositional environments in order to provide further granularity and to capture their depositional complexities. A further 28 parameters which capture other aspects that also impact production behaviour, such as reservoir depth, fluid type and structural complexity, were recorded for each reservoir. Principal component analysis (PCA) was utilized to explore the importance of sedimentological-dependent variables in the dataset, and to determine the parameters that have the strongest influence on the overall variability of the dataset. PCA revealed that parameters associated with field size and depth of burial had the most influence on recovery factor. Gross depositional environment and other stratigraphic-dependent parameters were the most significant geological factors. Fluid properties, such as API gravity and average gas/oil ratio, were unexpectedly among the less important parameters.
{"title":"Stratigraphic controls on hydrocarbon recovery in clastic reservoirs of the Norwegian Continental Shelf","authors":"Kachalla Aliyuda, J. Howell, A. Hartley, Aliyuda Ali","doi":"10.1144/petgeo2019-133","DOIUrl":"https://doi.org/10.1144/petgeo2019-133","url":null,"abstract":"A number of geological and engineering parameters influence and control the performance and ultimate recovery from an oil reservoir. These are commonly interlinked and the relative importance of each can be difficult to unravel. These variables include geological parameters such as depositional environment, which has long been considered to be a key factor influencing the production characteristics of fields. However, quantifying the importance of any single factor, such as depositional environment, is complicated by the impact of the other variables (geological and engineering) and their numerous interdependencies. The main aim of this study is to unravel the impact of the depositional environment and primary facies architecture on reservoir performance using an empirical study of oilfields from the Norwegian Continental Shelf. A database of 91 fields, with a total of 7.8 Bbbl (billion barrels) of oil in place, has been built. Within this a total of 93 clastic reservoirs were classified into three gross depositional environments: continental, paralic/shallow marine and deep marine. The reservoirs were further classified into eight depositional environments in order to provide further granularity and to capture their depositional complexities. A further 28 parameters which capture other aspects that also impact production behaviour, such as reservoir depth, fluid type and structural complexity, were recorded for each reservoir. Principal component analysis (PCA) was utilized to explore the importance of sedimentological-dependent variables in the dataset, and to determine the parameters that have the strongest influence on the overall variability of the dataset. PCA revealed that parameters associated with field size and depth of burial had the most influence on recovery factor. Gross depositional environment and other stratigraphic-dependent parameters were the most significant geological factors. Fluid properties, such as API gravity and average gas/oil ratio, were unexpectedly among the less important parameters.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-10-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45728575","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}
E. Michie, Andy P. Cooke, I. Kaminskaite, J. C. Stead, G. Plenderleith, S. D. Tobiss, Q. Fisher, G. Yielding, B. Freeman
A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from seven countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c. 400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, and maximum burial depth, as well as the depth at the time of faulting. The results indicate which factors may have had the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019
{"title":"Key controls on the hydraulic properties of fault rocks in carbonates","authors":"E. Michie, Andy P. Cooke, I. Kaminskaite, J. C. Stead, G. Plenderleith, S. D. Tobiss, Q. Fisher, G. Yielding, B. Freeman","doi":"10.1144/petgeo2020-034","DOIUrl":"https://doi.org/10.1144/petgeo2020-034","url":null,"abstract":"A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from seven countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c. 400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, and maximum burial depth, as well as the depth at the time of faulting. The results indicate which factors may have had the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2020-034","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43425293","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}
T. Schröckenfuchs, V. Schuller, A. Zamolyi, E. Mekonnen, B. Grasemann
In order to calibrate equations for fault seal capacities to a specific basin, faults were analysed using core material from several Neogene hydrocarbon fields in the Vienna Basin, Austria. All studied specimens are siliciclastic rocks that were sampled from a depth interval of <2000 m, and share a similar depth at time of faulting, diagenetic conditions and maximum burial depth. Laboratory results showed a permeability reduction in all fault rocks compared to the host rocks. Both the highest and the lowest fault seal capacities were observed in the same fault rock type with a low phyllosilicate and clay content, and classifying as cataclastic deformation bands. Investigating the strong permeability variations within these fault rocks, microscopic analyses revealed that the fault seal potential is strongly linked to the detrital dolomite content in the host rock. Grain-size reduction processes occur preferably in the dolomite grains, accompanied by cementation. Our study suggests that – in addition to using standard fault seal analysis algorithms – accounting for host rock composition and grain-size reduction therein might help to further constrain fault seal behaviour in shallow depths. Fault seal mechanisms need to be understood on field, formation and micro scales before drawing conclusions for a full basin calibration. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019
{"title":"Influence of host rock composition on permeability reduction in shallow fault zones – implications for fault seal analysis (Vienna Basin, Austria)","authors":"T. Schröckenfuchs, V. Schuller, A. Zamolyi, E. Mekonnen, B. Grasemann","doi":"10.1144/petgeo2020-014","DOIUrl":"https://doi.org/10.1144/petgeo2020-014","url":null,"abstract":"In order to calibrate equations for fault seal capacities to a specific basin, faults were analysed using core material from several Neogene hydrocarbon fields in the Vienna Basin, Austria. All studied specimens are siliciclastic rocks that were sampled from a depth interval of <2000 m, and share a similar depth at time of faulting, diagenetic conditions and maximum burial depth. Laboratory results showed a permeability reduction in all fault rocks compared to the host rocks. Both the highest and the lowest fault seal capacities were observed in the same fault rock type with a low phyllosilicate and clay content, and classifying as cataclastic deformation bands. Investigating the strong permeability variations within these fault rocks, microscopic analyses revealed that the fault seal potential is strongly linked to the detrital dolomite content in the host rock. Grain-size reduction processes occur preferably in the dolomite grains, accompanied by cementation. Our study suggests that – in addition to using standard fault seal analysis algorithms – accounting for host rock composition and grain-size reduction therein might help to further constrain fault seal behaviour in shallow depths. Fault seal mechanisms need to be understood on field, formation and micro scales before drawing conclusions for a full basin calibration. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-09-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2020-014","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43550906","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}
Bed-scale heterogeneity in channelized deep-water reservoirs can significantly influence reservoir performance, but reservoir simulation typically requires cell sizes much greater than the scale of intra-channel element architecture. Here, bed- to geobody-scale simulations elucidate the influence of bed-scale architecture and channel element stacking on flow and connectivity, informing full-field reservoir model development and evaluation. Models consist of two channel element segments, each 300 m (985 ft) wide by 14 m (45 ft) thick and 550 m (1805 ft) long, stacked in 12 different stacking arrangements. Bed-scale architecture is captured in six deterministic element fills, highlighting interbedded sandstone and mudstone (thin bed) presence (homogeneous v. heterogeneous elements), position (symmetrical v. asymmetrical), and proportion (low v. high element net-to-gross). Each model is flow simulated to illuminate how element stacking and intra-element heterogeneity impacts reservoir performance. Thin bed presence and position have the greatest impact on reservoir connectivity/performance when elements are laterally offset; impacts are minimal when elements are vertically aligned. Impacts are exacerbated when the thin-bed proportion is increased. Where bed-scale architecture is represented, complex flow behaviours generate a significant variability in production timing and the cumulative volumes produced. Simulations consisting of a homogenous element architecture fail to capture complex flow behaviours, producing comparatively optimistic results.
{"title":"The influence of inter- and intra-channel architecture on deep-water turbidite reservoir performance","authors":"C. Meirovitz, L. Stright, S. Hubbard, B. Romans","doi":"10.1144/petgeo2020-005","DOIUrl":"https://doi.org/10.1144/petgeo2020-005","url":null,"abstract":"Bed-scale heterogeneity in channelized deep-water reservoirs can significantly influence reservoir performance, but reservoir simulation typically requires cell sizes much greater than the scale of intra-channel element architecture. Here, bed- to geobody-scale simulations elucidate the influence of bed-scale architecture and channel element stacking on flow and connectivity, informing full-field reservoir model development and evaluation. Models consist of two channel element segments, each 300 m (985 ft) wide by 14 m (45 ft) thick and 550 m (1805 ft) long, stacked in 12 different stacking arrangements. Bed-scale architecture is captured in six deterministic element fills, highlighting interbedded sandstone and mudstone (thin bed) presence (homogeneous v. heterogeneous elements), position (symmetrical v. asymmetrical), and proportion (low v. high element net-to-gross). Each model is flow simulated to illuminate how element stacking and intra-element heterogeneity impacts reservoir performance. Thin bed presence and position have the greatest impact on reservoir connectivity/performance when elements are laterally offset; impacts are minimal when elements are vertically aligned. Impacts are exacerbated when the thin-bed proportion is increased. Where bed-scale architecture is represented, complex flow behaviours generate a significant variability in production timing and the cumulative volumes produced. Simulations consisting of a homogenous element architecture fail to capture complex flow behaviours, producing comparatively optimistic results.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-08-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2020-005","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47690721","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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