Tracers are practical tools to gather information about the subsurface fluid flow in hydrocarbon reservoirs. Typical interwell tracer tests involve injecting and producing tracers from multiple wells to evaluate important parameters such as connectivity, flow paths, fluid-fluid and fluid-rock interactions, and reservoir heterogeneity, among others. The upcoming of nanotechnology enables the development of novel nanoparticle-based tracers to overcome many of the challenges faced by conventional tracers. Among the advantages of nanoparticle-based tracers is the capability to functionalize their surface to yield stability and transportability through the subsurface. In addition, nanoparticles can be engineered to respond to a wide variety of stimuli, including light. The photoacoustic effect is the formation of sound waves following light absorption in a material sample. The medical community has successfully employed photoacoustic nanotracers as contrast agents for photoacoustic tomography imaging. We propose that properly engineered photoacoustic nanoparticles can be used as tracers in oil reservoirs. Our analysis begins by investigating the parameters controlling the conversion of light to acoustic waves, and strategies to optimize such parameters. Next, we analyze different kind of nanoparticles that we deem potential candidates for our subsurface operations. Then, we briefly discuss the excitation sources and make a comparison between continuous wave and pulsed sources. We finish by discussing the research gaps and challenges that must be addressed to incorporate these agents into our operations. At the time of this writing, no other study investigating the feasibility of using photoacoustic nanoparticles for tracer applications was found. Our work paves the way for a new class of passive tracers for oil reservoirs. Photoacoustic nanotracers are easy to detect and quantify and are therefore suitable for continuous in-line monitoring, contributing to the ongoing real-time data efforts in the oil and gas industry.
{"title":"Photoacoustic Nanotracers for Subsurface Applications: Opportunities and Challenges","authors":"J. M. Servin, Hala A. Al-Sadeg, A. Abdel-Fattah","doi":"10.2118/206316-ms","DOIUrl":"https://doi.org/10.2118/206316-ms","url":null,"abstract":"\u0000 Tracers are practical tools to gather information about the subsurface fluid flow in hydrocarbon reservoirs. Typical interwell tracer tests involve injecting and producing tracers from multiple wells to evaluate important parameters such as connectivity, flow paths, fluid-fluid and fluid-rock interactions, and reservoir heterogeneity, among others. The upcoming of nanotechnology enables the development of novel nanoparticle-based tracers to overcome many of the challenges faced by conventional tracers. Among the advantages of nanoparticle-based tracers is the capability to functionalize their surface to yield stability and transportability through the subsurface. In addition, nanoparticles can be engineered to respond to a wide variety of stimuli, including light.\u0000 The photoacoustic effect is the formation of sound waves following light absorption in a material sample. The medical community has successfully employed photoacoustic nanotracers as contrast agents for photoacoustic tomography imaging. We propose that properly engineered photoacoustic nanoparticles can be used as tracers in oil reservoirs. Our analysis begins by investigating the parameters controlling the conversion of light to acoustic waves, and strategies to optimize such parameters. Next, we analyze different kind of nanoparticles that we deem potential candidates for our subsurface operations. Then, we briefly discuss the excitation sources and make a comparison between continuous wave and pulsed sources. We finish by discussing the research gaps and challenges that must be addressed to incorporate these agents into our operations.\u0000 At the time of this writing, no other study investigating the feasibility of using photoacoustic nanoparticles for tracer applications was found. Our work paves the way for a new class of passive tracers for oil reservoirs. Photoacoustic nanotracers are easy to detect and quantify and are therefore suitable for continuous in-line monitoring, contributing to the ongoing real-time data efforts in the oil and gas industry.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"123 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76172716","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Volcanic ash beds are thin layers commonly observed in the Eagle Ford, Niobrara and, Vaca Muerta formations. Because of their differences in composition, sedimentary structures, and diagenetic alteration, they exhibit a significant contrast in mechanical properties with respect to surrounding formation layers. This can impact hydraulic fracturing, affecting fracture propagation and fracture geometry. Quantifying the mechanical properties of ash beds becomes significant; however, it is a challenge with traditional testing methods. Common logging fails to identify the ash beds, and core plug testing is not possible because of their friability. In this study, nanoindentation was used to measure the mechanical properties (Young's modulus, creep, and anisotropy) in Eagle Ford ash beds, and to determine the contrast with the formation matrix properties. Two separate ash beds of high clay and plagioclase composition were epoxied in an aluminum tray and left for 48 hours curing time. Horizontal and vertical samples of ash beds were acquired and mounted on a metal stub, followed by polishing and broad beam ion milling. Adjacent samples were also prepared for high-resolution Scanning Electron Microscope (SEM) microstructural analysis. The Young's modulus in ash beds ranged from 12 to 24 GPa, with the horizontal direction Young's modulus being slightly greater than that of the vertical samples. The Young's modulus contrast with adjacent layers was calculated to be 1:2 with clay-rich zones and 1:4 with calcite rich zones. The creep deformation rate was three times higher for ash beds compared to other zones. Using Backus averaging, it was determined that the presence of ash beds can increase the anisotropy in the formation by 15-25%. SEM results showed a variation in microstructure between the ash beds with evidence of diagenetic conversion of rhyolitic material into clays. Key differences between the two ash beds were due to the presence of plagioclase and the occurrence of porosity within kaolinite. Overall porosity varied between the two ash beds and adjacent carbonate layers showing a significant increase in porosity. Understanding the moduli contrast between adjacent layers can improve the hydraulic fracturing design when ash beds are encountered. In addition, the presence of these beds can lead to proppant embedment and loss in fracture connectivity. These results can be used for improving geomechanical models.
{"title":"Manuscript Title: Mechanical and Microstructural Studies of Volcanic Ash Beds in Unconventional Reservoirs","authors":"J. C. Acosta, M. Curtis, C. Sondergeld, C. Rai","doi":"10.2118/206227-ms","DOIUrl":"https://doi.org/10.2118/206227-ms","url":null,"abstract":"\u0000 Volcanic ash beds are thin layers commonly observed in the Eagle Ford, Niobrara and, Vaca Muerta formations. Because of their differences in composition, sedimentary structures, and diagenetic alteration, they exhibit a significant contrast in mechanical properties with respect to surrounding formation layers. This can impact hydraulic fracturing, affecting fracture propagation and fracture geometry. Quantifying the mechanical properties of ash beds becomes significant; however, it is a challenge with traditional testing methods. Common logging fails to identify the ash beds, and core plug testing is not possible because of their friability.\u0000 In this study, nanoindentation was used to measure the mechanical properties (Young's modulus, creep, and anisotropy) in Eagle Ford ash beds, and to determine the contrast with the formation matrix properties. Two separate ash beds of high clay and plagioclase composition were epoxied in an aluminum tray and left for 48 hours curing time. Horizontal and vertical samples of ash beds were acquired and mounted on a metal stub, followed by polishing and broad beam ion milling. Adjacent samples were also prepared for high-resolution Scanning Electron Microscope (SEM) microstructural analysis.\u0000 The Young's modulus in ash beds ranged from 12 to 24 GPa, with the horizontal direction Young's modulus being slightly greater than that of the vertical samples. The Young's modulus contrast with adjacent layers was calculated to be 1:2 with clay-rich zones and 1:4 with calcite rich zones. The creep deformation rate was three times higher for ash beds compared to other zones. Using Backus averaging, it was determined that the presence of ash beds can increase the anisotropy in the formation by 15-25%. SEM results showed a variation in microstructure between the ash beds with evidence of diagenetic conversion of rhyolitic material into clays. Key differences between the two ash beds were due to the presence of plagioclase and the occurrence of porosity within kaolinite. Overall porosity varied between the two ash beds and adjacent carbonate layers showing a significant increase in porosity.\u0000 Understanding the moduli contrast between adjacent layers can improve the hydraulic fracturing design when ash beds are encountered. In addition, the presence of these beds can lead to proppant embedment and loss in fracture connectivity. These results can be used for improving geomechanical models.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"144 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77447932","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Robust estimation of rock properties, such as porosity and density, from geophysical data, i.e. seismic and well logs, is essential in the process of subsurface modeling and reservoir engineering workflows. Such properties are accurately measured in a well; however, due to high cost of drilling, such direct measurements are limited in amount and sparse in space within a study area. On the contrary, 3D seismic data illuminates the subsurface of the study area throughoutly by seismic wave propagation; however, the connection between seismic signals and rock properties is implicit and unknown, causing rock property estimation from seismic only to be a challenging task and of high uncertainty. An integration of 3D seismic with sparse wells is expected to eliminate such uncertainty and improve the accuracy of static reservoir property estimation. This paper investigates the application of a semi-supervised learning workflow to estimate porosity from a 3D seismic survey and 36 wells over a fluvio-deltaic Triasic gas field. The workflow is performed in various scenarios, including purely from seismic amplitude, incorporating a rough 6-layer deposition model as a constraint, and training with varying numbers of wells. Good match is observed between the machine prediction and the well logs, which verifies the capability of such semi-supervised learning in providing reliable seismic-well integration and delivering robust porosity modeling. It is concluded that the use of available additional information helps effectively constrain the learning process and thus leads to significantly improved lateral continuity and reduced artifacts in the machine learning prediction. The semi-supervised learning can be readily extended for estimating more properties and allows nearly one- click solution to obtain 3D rock property distribution in a study area where seismic and well data is available.
{"title":"Using Semi-Supervised Convolutional Neural Networks for Porosity Modeling Over a Fluvio-Deltaic Triassic Gas Field","authors":"H. Di, A. Abubakar","doi":"10.2118/205841-ms","DOIUrl":"https://doi.org/10.2118/205841-ms","url":null,"abstract":"\u0000 Robust estimation of rock properties, such as porosity and density, from geophysical data, i.e. seismic and well logs, is essential in the process of subsurface modeling and reservoir engineering workflows. Such properties are accurately measured in a well; however, due to high cost of drilling, such direct measurements are limited in amount and sparse in space within a study area. On the contrary, 3D seismic data illuminates the subsurface of the study area throughoutly by seismic wave propagation; however, the connection between seismic signals and rock properties is implicit and unknown, causing rock property estimation from seismic only to be a challenging task and of high uncertainty. An integration of 3D seismic with sparse wells is expected to eliminate such uncertainty and improve the accuracy of static reservoir property estimation.\u0000 This paper investigates the application of a semi-supervised learning workflow to estimate porosity from a 3D seismic survey and 36 wells over a fluvio-deltaic Triasic gas field. The workflow is performed in various scenarios, including purely from seismic amplitude, incorporating a rough 6-layer deposition model as a constraint, and training with varying numbers of wells. Good match is observed between the machine prediction and the well logs, which verifies the capability of such semi-supervised learning in providing reliable seismic-well integration and delivering robust porosity modeling. It is concluded that the use of available additional information helps effectively constrain the learning process and thus leads to significantly improved lateral continuity and reduced artifacts in the machine learning prediction. The semi-supervised learning can be readily extended for estimating more properties and allows nearly one- click solution to obtain 3D rock property distribution in a study area where seismic and well data is available.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85340921","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sebastian Ramiro-Ramirez, P. Flemings, Athma R. Bhandari, O. Jimba
We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.
{"title":"Steady-State Liquid Permeability Measurements in Samples from the Bakken Formation, Williston Basin, USA","authors":"Sebastian Ramiro-Ramirez, P. Flemings, Athma R. Bhandari, O. Jimba","doi":"10.2118/206382-ms","DOIUrl":"https://doi.org/10.2118/206382-ms","url":null,"abstract":"\u0000 We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79268555","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ming Qu, Tuo Liang, J. Hou, Wei-Peng Wu, Yuchen Wen, Lixiao Xiao
Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide due to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. In this work, we synthesize the amphiphilic molybdenum disulfide nanosheets through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of active sites over the surfaces of MoS2 nanosheets. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS2 nanosheets) are approximate 67 nm in width and 1.4 nm in thickness. The effects of ultralow concentration ODA-MoS2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the core flooding experiments were also conducted to reveal the adsorption rules and the oil displacement effects of ultralow concentration ODA-MoS2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 hrs after 50 mg/L ODA-MoS2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 µm can be formed after the addition of ODA-MoS2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% is achieved. Finally, the production performance of ultralow concentration of ODA-MoS2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed.
{"title":"Ultralow Concentration of Amphiphilic Molybdenum Disulfide Nanosheets for Enhanced Oil Recovery-Research and Field Application","authors":"Ming Qu, Tuo Liang, J. Hou, Wei-Peng Wu, Yuchen Wen, Lixiao Xiao","doi":"10.2118/206260-ms","DOIUrl":"https://doi.org/10.2118/206260-ms","url":null,"abstract":"\u0000 Recently, spherical nanoparticles have been studied to enhance oil recovery (EOR) worldwide due to their remarkable properties. However, there is a lack of studies of nanosheets on EOR. In this work, we synthesize the amphiphilic molybdenum disulfide nanosheets through a straightforward hydrothermal method. The octadecyl amine (ODA) molecules were grafted onto the surfaces of molybdenum disulfide nanosheets due to the presence of active sites over the surfaces of MoS2 nanosheets. The synthesized amphiphilic molybdenum disulfide nanosheets (ODA-MoS2 nanosheets) are approximate 67 nm in width and 1.4 nm in thickness. The effects of ultralow concentration ODA-MoS2 nanosheets on the dynamic wettability change of solid surfaces and emulsion stability were also studied and discussed. Besides, the core flooding experiments were also conducted to reveal the adsorption rules and the oil displacement effects of ultralow concentration ODA-MoS2 nanosheets. Experimental results indicate that the oil-wet solid surface (a contact angle of 130°) can transform into the neutral-wet solid surface (a contact angle of 90°) within 120 hrs after 50 mg/L ODA-MoS2 nanosheets treatment. In addition, micro-scale emulsions in size of 2 µm can be formed after the addition of ODA-MoS2 nanosheets by adsorbing onto the oil-water interfaces. The desorption energy of a single ODA-MoS2 nanosheet from the oil-water interface to the bulk phase is proposed. When the concentration of ODA-MoS2 nanosheets is 50 mg/L, the emulsions are the most stable. Core flooding results demonstrate that the ultimate residue of ODA-MoS2 nanosheets in porous media is less than 11%, and the highest increased oil recovery of around 16.26% is achieved. Finally, the production performance of ultralow concentration of ODA-MoS2 nanofluid (50 mg/L) in the application of Daqing Oilfield is summarized and discussed.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"133 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79366343","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Casing design and the associated load assumptions have evolved considerably over the last 30 years. The objective of this paper is to trace the history, evolution and future of casing design by means of the type of load cases and the assumptions made for them as it evolved from the early 1960's to the modern load case requirements for wells drilled in the 2020's. The vast majority of tubular failures in oil & gas wells are not attributable to computational errors in calculating design loads, but rather are due to a shortfall in considering the appropriate load scenarios. One common shortfall includes making incorrect or oversimplified assumptions for the initial and final temperature and pressure conditions. There is no industry standard for casing or tubing design loads, but there is an industry accepted standard process for the calculation of the stress on tubulars once the load cases are determined. Each operating company may use a different set of load assumptions depending on the well type and risk assessment. This work also keeps in view the major computational tools used during each step change of the casing design evolution: slide rule/nomographs, HP 41C calculators, PC DOS and Windows programs, and the latest Cloud-Native paradigm with REST API's within a microservices architecture. A REST API (also known as RESTful API) is an Application Programming Interface (API) that conforms to the constraints of Representational State Transfer (REST) architectural style commonly used in current Cloud computing technology. The scope will also include ongoing research and development to address shortcomings of previous load case assumptions and calculations for extended reach and HPHT wells, closely spaced wells, and geothermal wells. Modern wells and modern casing design load cases are in a constant state of evolution and casing failures will occur unless engineers and their tools also evolve.
在过去的30年里，套管设计和相关的载荷假设发生了很大的变化。本文的目的是追溯套管设计的历史、演变和未来，通过载荷箱的类型和对它们所做的假设，从20世纪60年代初到20世纪20年代钻井的现代载荷箱要求。油气井中绝大多数的管失效不是由于计算设计载荷时的计算错误，而是由于没有考虑到适当的载荷情况。一个常见的不足包括对初始和最终温度和压力条件做出不正确或过于简化的假设。套管或油管的设计载荷没有行业标准，但一旦确定载荷情况，就有一个行业公认的计算管柱应力的标准过程。每家运营公司可能会根据井的类型和风险评估使用不同的负荷假设。这项工作还关注了在外壳设计演变的每一步变化中使用的主要计算工具:计算尺/nomographs、HP 41C计算器、PC DOS和Windows程序，以及在微服务架构中使用REST API的最新Cloud-Native范例。REST API(也称为RESTful API)是一种应用程序编程接口(API)，它符合当前云计算技术中常用的具象状态传输(Representational State Transfer, REST)架构风格的约束。该范围还将包括正在进行的研究和开发，以解决以前大位移井和高温高压井、紧密井和地热井的负载情况假设和计算的缺点。现代油井和现代套管设计载荷情况处于不断发展的状态，除非工程师和他们的工具也在发展，否则套管失效将会发生。
{"title":"History, Evolution, and Future of Casing Design Theory and Practice","authors":"John Howard, R. Trevisan, A. McSpadden, S. Glover","doi":"10.2118/206183-ms","DOIUrl":"https://doi.org/10.2118/206183-ms","url":null,"abstract":"\u0000 Casing design and the associated load assumptions have evolved considerably over the last 30 years. The objective of this paper is to trace the history, evolution and future of casing design by means of the type of load cases and the assumptions made for them as it evolved from the early 1960's to the modern load case requirements for wells drilled in the 2020's. The vast majority of tubular failures in oil & gas wells are not attributable to computational errors in calculating design loads, but rather are due to a shortfall in considering the appropriate load scenarios. One common shortfall includes making incorrect or oversimplified assumptions for the initial and final temperature and pressure conditions. There is no industry standard for casing or tubing design loads, but there is an industry accepted standard process for the calculation of the stress on tubulars once the load cases are determined. Each operating company may use a different set of load assumptions depending on the well type and risk assessment.\u0000 This work also keeps in view the major computational tools used during each step change of the casing design evolution: slide rule/nomographs, HP 41C calculators, PC DOS and Windows programs, and the latest Cloud-Native paradigm with REST API's within a microservices architecture. A REST API (also known as RESTful API) is an Application Programming Interface (API) that conforms to the constraints of Representational State Transfer (REST) architectural style commonly used in current Cloud computing technology. The scope will also include ongoing research and development to address shortcomings of previous load case assumptions and calculations for extended reach and HPHT wells, closely spaced wells, and geothermal wells.\u0000 Modern wells and modern casing design load cases are in a constant state of evolution and casing failures will occur unless engineers and their tools also evolve.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85835139","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The sophisticated molecular imaging methods, atomic force microscopy (AFM) and scanning tunneling microscopy (STM), have been utilized to image individual asphaltene molecules, both their atoms and bonds, and their electronic structure. The stunning images have confirmed previous results and have all but resolved the long-standing uncertainties regarding asphaltene molecular architecture. Asphaltenes are also known to have a strong propensity to aggregate. The dominante asphaltene molecular structure and hierarchical nanocolloidal structures have been resolved and codified in the Yen-Mullins model. Use of this model in a simple polymer solution theory has given the first equation of state (EoS) for asphaltene gradients in oilfield reservoirs, the Flory-Huggins-Zuo EoS. With this EoS it is now possible to address reservoir connectivity in new ways; equilibrated asphaltenes imply reservoir connectivity. For reservoirs with disequilibrium of contained fluids, there is often a fluid process occurring in geologic time that precludes equilibrium. The collection of processes leading to equilibrium and those that preclude equilibrium constitute a new technical discipline, reservoir fluid geodynamics (RFG). Several reservoirs are reviewed employing RFG evaluation of connectivity via asphaltene thermodynamics. RFG processes in reservoris often include diffusion, RFG models incorporating simple solution to the diffusion equation coupled with quasi-equilibrium with the FHZ EoS are shown to apply for timelines up to 50 million years, the age of charge in a reservoir. When gas (or condensates) diffuse into oil, the asphaltenes are destabilized and can convect to the base of the reservoir. Increasing asphaltene onset pressure as well as viscous oil and tar mats can be consequences. Depending on specifics of the process, either gooey tar or coal-like asphaltene deposits can form. In addition, the asphaltene structures illuminated by AFM are now being used to account for interfacial properties using simple thermodynamics. At long last, asphaltenes are no longer the enigmatic component of crude oil, instead the resolution of asphaltene structures and dynamics has led to new thermodynamic applications in reservoirs, the new discipline RFG, and a new understanding of tar mats.
{"title":"Asphaltenes: Fundamental Principles to Oilfield Applications","authors":"O. Mullins, A. Pomerantz, Yunlong Zhang","doi":"10.2118/206091-ms","DOIUrl":"https://doi.org/10.2118/206091-ms","url":null,"abstract":"\u0000 The sophisticated molecular imaging methods, atomic force microscopy (AFM) and scanning tunneling microscopy (STM), have been utilized to image individual asphaltene molecules, both their atoms and bonds, and their electronic structure. The stunning images have confirmed previous results and have all but resolved the long-standing uncertainties regarding asphaltene molecular architecture. Asphaltenes are also known to have a strong propensity to aggregate. The dominante asphaltene molecular structure and hierarchical nanocolloidal structures have been resolved and codified in the Yen-Mullins model. Use of this model in a simple polymer solution theory has given the first equation of state (EoS) for asphaltene gradients in oilfield reservoirs, the Flory-Huggins-Zuo EoS. With this EoS it is now possible to address reservoir connectivity in new ways; equilibrated asphaltenes imply reservoir connectivity. For reservoirs with disequilibrium of contained fluids, there is often a fluid process occurring in geologic time that precludes equilibrium. The collection of processes leading to equilibrium and those that preclude equilibrium constitute a new technical discipline, reservoir fluid geodynamics (RFG). Several reservoirs are reviewed employing RFG evaluation of connectivity via asphaltene thermodynamics. RFG processes in reservoris often include diffusion, RFG models incorporating simple solution to the diffusion equation coupled with quasi-equilibrium with the FHZ EoS are shown to apply for timelines up to 50 million years, the age of charge in a reservoir. When gas (or condensates) diffuse into oil, the asphaltenes are destabilized and can convect to the base of the reservoir. Increasing asphaltene onset pressure as well as viscous oil and tar mats can be consequences. Depending on specifics of the process, either gooey tar or coal-like asphaltene deposits can form. In addition, the asphaltene structures illuminated by AFM are now being used to account for interfacial properties using simple thermodynamics. At long last, asphaltenes are no longer the enigmatic component of crude oil, instead the resolution of asphaltene structures and dynamics has led to new thermodynamic applications in reservoirs, the new discipline RFG, and a new understanding of tar mats.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84844352","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. Tegelaar, P. Nederlof, C. Kloucha, Osemoahu A. Omobude, H. Al Harbi
Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry. Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity. As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper: Assessment of vertical compartmentalization and fault transmissibility of four stacked reservoirs in a highly fractured zone. Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. Identify opportunities for production monitoring. Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas
{"title":"Reservoir Architecture and Fluid Connectivity in an Abu Dhabi Oil Accumulation","authors":"E. Tegelaar, P. Nederlof, C. Kloucha, Osemoahu A. Omobude, H. Al Harbi","doi":"10.2118/206214-ms","DOIUrl":"https://doi.org/10.2118/206214-ms","url":null,"abstract":"\u0000 Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry.\u0000 Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity.\u0000 As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper:\u0000 Assessment of vertical compartmentalization and fault transmissibility of four stacked reservoirs in a highly fractured zone. Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. Identify opportunities for production monitoring. Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas ","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83732144","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
V. Cheverda, V. Lisitsa, M. Protasov, G. Reshetova, A. Ledyaev, D. Petrov, V. Shilikov
To develop the optimal strategy for developing a hydrocarbon field, one should know in fine detail its geological structure. More and more attention has been paid to cavernous-fractured reservoirs within the carbonate environment in the last decades. This article presents a technology for three-dimensional computing images of such reservoirs using scattered seismic waves. To verify it, we built a particular synthetic model, a digital twin of one of the licensed objects in the north of Eastern Siberia. One distinctive feature of this digital twin is the representation of faults not as some ideal slip surfaces but as three-dimensional geological bodies filled with tectonic breccias. To simulate such breccias and the geometry of these bodies, we performed a series of numerical experiments based on the discrete elements technique. The purpose of these experiments is the simulation of the geomechanical processes of fault formation. For the digital twin constructed, we performed full-scale 3D seismic modeling, which made it possible to conduct fully controlled numerical experiments on the construction of wave images and, on this basis, to propose an optimal seismic data processing graph.
{"title":"Reconstruction of the Reservoir Fine Structure by Using Scattering Attributes","authors":"V. Cheverda, V. Lisitsa, M. Protasov, G. Reshetova, A. Ledyaev, D. Petrov, V. Shilikov","doi":"10.2118/206083-ms","DOIUrl":"https://doi.org/10.2118/206083-ms","url":null,"abstract":"\u0000 To develop the optimal strategy for developing a hydrocarbon field, one should know in fine detail its geological structure. More and more attention has been paid to cavernous-fractured reservoirs within the carbonate environment in the last decades. This article presents a technology for three-dimensional computing images of such reservoirs using scattered seismic waves. To verify it, we built a particular synthetic model, a digital twin of one of the licensed objects in the north of Eastern Siberia.\u0000 One distinctive feature of this digital twin is the representation of faults not as some ideal slip surfaces but as three-dimensional geological bodies filled with tectonic breccias. To simulate such breccias and the geometry of these bodies, we performed a series of numerical experiments based on the discrete elements technique. The purpose of these experiments is the simulation of the geomechanical processes of fault formation.\u0000 For the digital twin constructed, we performed full-scale 3D seismic modeling, which made it possible to conduct fully controlled numerical experiments on the construction of wave images and, on this basis, to propose an optimal seismic data processing graph.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89633631","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Rock heterogeneities, such as variations in pore distribution, pore throat diameter, and initial permeability, significantly affect the outcome of carbonate matrix stimulation treatments. A better understanding of the influence of these parameters on stimulation and diversion, especially for the performance of self-diverting acids, is needed for efficient stimulation designs. Carbonate rock samples from six outcrop formations, with permeability ranging from 2 to 150 md, were used in the study. Large blocks were acquired for each outcrop, and several 1.5×6-in. core plugs were drilled from these blocks. Pore structure in each outcrop was characterized by high-pressure mercury injection (HPMI) porosimetry and flowing fraction measured with nondestructive tracer tests. Pore volume to breakthrough (PVbt) for a viscoelastic self-diverting (VES) acid was determined at 150°F for injection rates ranging from 1 to 10 cm3/min. The diversion ability for the VES acid was evaluated by (1) the increase in pressure during VES acid injection and (2) the pore volumes this higher pressure was maintained. The results show that flowing fractions measured by injection of either KCl (potassium chloride) tracer in deionized water or a dilute polymer solution is an effective means for characterizing the pore structure and for predicting the pore volume to breakthrough and diversion performance of VES acids. High-permeability grainstones such as Indiana Limestone, where most of the rock porosity is accessible to aqueous fluids (high flowing fraction), have the largest pore volume to breakthrough and the largest relative pressure buildup during injection of VES acids. Low-permeability rocks with heterogeneous porosity (low flowing fraction) have lower pore volume to breakthrough and had a relatively low-pressure build-up. The results are summarized in a master-curve, which facilitates prediction of pore volume to breakthrough of VES acids from rock properties that can be measured by non-destructive techniques. Correlations for PVbt and the diversion ability of the VES acid are presented, so that the performance of these acid systems can be estimated for formation rocks where direct measuremets of PVbt or diversion are not be practical.
{"title":"Rock Heterogeneity Effects on Fluid Diversion During Stimulation Treatment","authors":"Tiurma Theresa Sibarani, M. Ziauddin","doi":"10.2118/206095-ms","DOIUrl":"https://doi.org/10.2118/206095-ms","url":null,"abstract":"\u0000 Rock heterogeneities, such as variations in pore distribution, pore throat diameter, and initial permeability, significantly affect the outcome of carbonate matrix stimulation treatments. A better understanding of the influence of these parameters on stimulation and diversion, especially for the performance of self-diverting acids, is needed for efficient stimulation designs.\u0000 Carbonate rock samples from six outcrop formations, with permeability ranging from 2 to 150 md, were used in the study. Large blocks were acquired for each outcrop, and several 1.5×6-in. core plugs were drilled from these blocks. Pore structure in each outcrop was characterized by high-pressure mercury injection (HPMI) porosimetry and flowing fraction measured with nondestructive tracer tests. Pore volume to breakthrough (PVbt) for a viscoelastic self-diverting (VES) acid was determined at 150°F for injection rates ranging from 1 to 10 cm3/min. The diversion ability for the VES acid was evaluated by (1) the increase in pressure during VES acid injection and (2) the pore volumes this higher pressure was maintained.\u0000 The results show that flowing fractions measured by injection of either KCl (potassium chloride) tracer in deionized water or a dilute polymer solution is an effective means for characterizing the pore structure and for predicting the pore volume to breakthrough and diversion performance of VES acids. High-permeability grainstones such as Indiana Limestone, where most of the rock porosity is accessible to aqueous fluids (high flowing fraction), have the largest pore volume to breakthrough and the largest relative pressure buildup during injection of VES acids. Low-permeability rocks with heterogeneous porosity (low flowing fraction) have lower pore volume to breakthrough and had a relatively low-pressure build-up. The results are summarized in a master-curve, which facilitates prediction of pore volume to breakthrough of VES acids from rock properties that can be measured by non-destructive techniques. Correlations for PVbt and the diversion ability of the VES acid are presented, so that the performance of these acid systems can be estimated for formation rocks where direct measuremets of PVbt or diversion are not be practical.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87918802","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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