Ramsin Y. Eyvazzadeh, A. Al-Omair, M. Kanfar, A. Christon
A detailed description of a modified Archie's equation is proposed to accurately quantify water saturation within low resistivity/low contrast pay carbonates. The majority of previous work on low resistivity/low contrast reservoirs focused on clastics, namely, thin beds and/or clay effects on resistivity measurements. Recent publications have highlighted a "non-Archie" behavior in carbonates with complex pore structures. Several theoretical models were introduced, but new practical applications were not derived to solve this issue. Built upon previous theoretical research in a holistic approach, new models and workflows have been developed. Specifically, utilizing a combination of machine learning algorithms, nuclear magnetic resonance (NMR), core and geological data, field specific calibrated equations to compute water saturation (Sw) in complex carbonate formations are presented. Essentially, these new models partition the porosity into pore spaces and calculate their relative contribution to water saturation in each pore space. These calibrated equations robustly produce results that have proven invaluable in pay identification, well placement, and have greatly enhanced the ability to manage these types of reservoirs. This paper initially explains the theory behind the development of the analysis illustrating workflows and validation techniques used to qualify this methodology. A key benefit performing this research is the utilization of machine-learning algorithms to predict NMR derived values in wells that do not have NMR data. Several examples explore where results of this analysis are compared to dynamic testing, formation testing and laboratory measured samples to validate and demonstrate the utility of this new analysis.
{"title":"Low Resistivity Pay Carbonates: A Practical Approach to Quantify Water Saturation Using a Modified Archie's Model","authors":"Ramsin Y. Eyvazzadeh, A. Al-Omair, M. Kanfar, A. Christon","doi":"10.2118/206096-ms","DOIUrl":"https://doi.org/10.2118/206096-ms","url":null,"abstract":"\u0000 A detailed description of a modified Archie's equation is proposed to accurately quantify water saturation within low resistivity/low contrast pay carbonates. The majority of previous work on low resistivity/low contrast reservoirs focused on clastics, namely, thin beds and/or clay effects on resistivity measurements. Recent publications have highlighted a \"non-Archie\" behavior in carbonates with complex pore structures. Several theoretical models were introduced, but new practical applications were not derived to solve this issue.\u0000 Built upon previous theoretical research in a holistic approach, new models and workflows have been developed. Specifically, utilizing a combination of machine learning algorithms, nuclear magnetic resonance (NMR), core and geological data, field specific calibrated equations to compute water saturation (Sw) in complex carbonate formations are presented. Essentially, these new models partition the porosity into pore spaces and calculate their relative contribution to water saturation in each pore space. These calibrated equations robustly produce results that have proven invaluable in pay identification, well placement, and have greatly enhanced the ability to manage these types of reservoirs.\u0000 This paper initially explains the theory behind the development of the analysis illustrating workflows and validation techniques used to qualify this methodology. A key benefit performing this research is the utilization of machine-learning algorithms to predict NMR derived values in wells that do not have NMR data. Several examples explore where results of this analysis are compared to dynamic testing, formation testing and laboratory measured samples to validate and demonstrate the utility of this new analysis.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73541251","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}
Well integrity has become a crucial field with increased focus and being published intensively in industry researches. It is important to maintain the integrity of the individual well to ensure that wells operate as expected for their designated life (or higher) with all risks kept as low as reasonably practicable, or as specified. Machine learning (ML) and artificial intelligence (AI) models are used intensively in oil and gas industry nowadays. ML concept is based on powerful algorithms and robust database. Developing an efficient classification model for well integrity (WI) anomalies is now feasible because of having enormous number of well failures and well barrier integrity tests, and analyses in the database. Circa 9000 dataset points were collected from WI tests performed for 800 wells in Gulf of Suez, Egypt for almost 10 years. Moreover, those data have been quality-controlled and quality-assured by experienced engineers. The data contain different forms of WI failures. The contributing parameter set includes a total of 23 barrier elements. Data were structured and fed into 11 different ML algorithms to build an automated systematic tool for calculating imposed risk category of any well. Comparison analysis for the deployed models was performed to infer the best predictive model that can be relied on. 11 models include both supervised and ensemble learning algorithms such as random forest, support vector machine (SVM), decision tree and scalable boosting techniques. Out of 11 models, the results showed that extreme gradient boosting (XGB), categorical boosting (CatBoost), and decision tree are the most reliable algorithms. Moreover, novel evaluation metrics for confusion matrix of each model have been introduced to overcome the problem of existing metrics which don't consider domain knowledge during model evaluation. The innovated model will help to utilize company resources efficiently and dedicate personnel efforts to wells with the high-risk. As a result, progressive improvements on business, safety, environment, and performance of the business. This paper would be a milestone in the design and creation of the Well Integrity Database Management Program through the combination of integrity and ML.
{"title":"Multi-Class Taxonomy of Well Integrity Anomalies Applying Inductive Learning Algorithms: Analytical Approach for Artificial-Lift Wells","authors":"M. S. Yakoot, A. Ragab, O. Mahmoud","doi":"10.2118/206129-ms","DOIUrl":"https://doi.org/10.2118/206129-ms","url":null,"abstract":"\u0000 Well integrity has become a crucial field with increased focus and being published intensively in industry researches. It is important to maintain the integrity of the individual well to ensure that wells operate as expected for their designated life (or higher) with all risks kept as low as reasonably practicable, or as specified. Machine learning (ML) and artificial intelligence (AI) models are used intensively in oil and gas industry nowadays. ML concept is based on powerful algorithms and robust database. Developing an efficient classification model for well integrity (WI) anomalies is now feasible because of having enormous number of well failures and well barrier integrity tests, and analyses in the database.\u0000 Circa 9000 dataset points were collected from WI tests performed for 800 wells in Gulf of Suez, Egypt for almost 10 years. Moreover, those data have been quality-controlled and quality-assured by experienced engineers. The data contain different forms of WI failures. The contributing parameter set includes a total of 23 barrier elements.\u0000 Data were structured and fed into 11 different ML algorithms to build an automated systematic tool for calculating imposed risk category of any well. Comparison analysis for the deployed models was performed to infer the best predictive model that can be relied on. 11 models include both supervised and ensemble learning algorithms such as random forest, support vector machine (SVM), decision tree and scalable boosting techniques. Out of 11 models, the results showed that extreme gradient boosting (XGB), categorical boosting (CatBoost), and decision tree are the most reliable algorithms. Moreover, novel evaluation metrics for confusion matrix of each model have been introduced to overcome the problem of existing metrics which don't consider domain knowledge during model evaluation.\u0000 The innovated model will help to utilize company resources efficiently and dedicate personnel efforts to wells with the high-risk. As a result, progressive improvements on business, safety, environment, and performance of the business. This paper would be a milestone in the design and creation of the Well Integrity Database Management Program through the combination of integrity and ML.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75713484","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}
Mohamed A. Elkhawaga, Wael A. Elghaney, R. Naidu, Assef Hussen, Ramy Rafaat, K. Baker, Ahmed E. Radwan, J. Heiland
Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely. An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights. In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area. This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing. This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.
{"title":"Impact of High Resolution 3D Geomechanics on Well Optimization in the Southern Gulf of Suez, Egypt","authors":"Mohamed A. Elkhawaga, Wael A. Elghaney, R. Naidu, Assef Hussen, Ramy Rafaat, K. Baker, Ahmed E. Radwan, J. Heiland","doi":"10.2118/206271-ms","DOIUrl":"https://doi.org/10.2118/206271-ms","url":null,"abstract":"\u0000 Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells\u0000 The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely.\u0000 An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights.\u0000 In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area.\u0000 This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing.\u0000 This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74201248","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}
In an era of increasing energy demand, declining oil fields and fluctuating crude oil prices globally, most oil companies are looking forward to implementing cost effective and environmentally sustainable enhanced oil recovery (EOR) techniques such as low salinity waterflooding (LSWF) and microbial EOR (MEOR). The present study numerically investigates the combined influence of simultaneous LSWF and microbial flooding for in-Situ MEOR in tertiary mode within a sandstone core under spatiotemporally fluctuating pH and temperature conditions. The developed black oil model consists of five major coupled submodels: nonlinear heat transport model; ion transport coupled with multiple ion exchange (MIE) involving uncomplexed cations and anions; pH variation with salinity and temperature; coupled reactive transport of injected substrates, Pseudomonas putida and produced biosurfactants with microbial maximum specific growth rate varying with temperature, salinity and pH; relative permeability and fractional flow curve variations due to interfacial tension reduction and wettability alteration (WA) by LSWF and biofilm deposition. The governing equations are solved using finite difference technique. Operator splitting and bisection methods are adopted to solve the MIE-transport model. The present model is found to be numerically stable and agree well with previously published experimental and analytical results. In the proposed MIE-transport mechanism, decreasing injection water salinity (IWS) from 2.52 to 0.32 M causes enhanced Ca2+ desorption rendering rock surface towards more water wet. Consequently, oil relative permeability (kro) increases with >55% reduction in water fractional flow (fw) at water saturation of 0.5 from the initial oil-wet condition. Further reducing IWS to 0.03 M causes Ca2+ adsorption shifting the surface wettability towards more oil-wet thus increasing fw by 52%. Formation water salinity (FWS) showed minor impact on WA with <5% decrease in fw when FWS is reduced from 3.15 to 1.05 M. During LSAMF, biosurfactant production is enhanced by >63% on reducing IWS from 2.52 to 0.32 M with negligible increase on further reducing IWS and FWS. This might be due to limiting nonisothermal (40 to 55 °C) and nutrient availability conditions. LSAMF caused significant WA, increase in kro with fw reduction by >84%. Though pH increased from 8.0 to 8.9, it showed minor impact on microbial metabolism. Formation damage due to bioplugging observed near injection point is compensated by effective migration of biosurfactants deep within sandstone core. The present study is a novel attempt to show synergistic effect of LSAMF over LSWF in enhancing oil mobility and recovery at core scale by simultaneously addressing complex crude oil-rock-brine chemistry and critical thermodynamic parameters that govern MEOR efficiency within a typical sandstone formation. The present model with relatively lower computational cost and running time improves the predictive
在能源需求不断增加、油田数量不断减少、全球原油价格波动的时代，大多数石油公司都希望采用经济高效、环境可持续的提高采收率(EOR)技术，如低矿化度水驱(LSWF)和微生物提高采收率(MEOR)技术。本研究通过数值模拟研究了在时空波动的pH和温度条件下，砂岩岩心内同时发生LSWF和微生物驱油对第三纪模式下原位MEOR的综合影响。所建立的黑油模型包括五大耦合子模型:非线性热输运模型;离子传输耦合多重离子交换(MIE)，涉及未络合的阳离子和阴离子;pH值随盐度和温度的变化;微生物最大比生长率随温度、盐度和pH值的变化而变化;LSWF和生物膜沉积导致界面张力降低和润湿性改变(WA)的相对渗透率和分数流动曲线变化。采用有限差分法求解控制方程。采用算子分割和二分法求解mie传输模型。该模型在数值上是稳定的，并且与以前发表的实验和分析结果吻合得很好。在提出的mie输运机制中，注入水矿化度(IWS)从2.52 M降低到0.32 M，导致Ca2+解吸增强，使岩石表面更湿润。因此，当含水饱和度为0.5时，与初始油湿状态相比，油相对渗透率(kro)增加，水分流(fw)减少55%以上。进一步降低IWS至0.03 M, Ca2+吸附使表面润湿性更亲油，从而使fw增加52%。地层水盐度(FWS)对WA的影响较小，将IWS从2.52 M降低到0.32 M的影响为63%，进一步降低IWS和FWS的影响可以忽略不计。这可能是由于限制非等温(40至55°C)和营养物质的可用性条件。LSAMF引起了显著的WA, kro增加，fw降低>84%。pH值从8.0增加到8.9，但对微生物代谢的影响较小。在注入点附近观察到的生物堵塞对地层的损害，可以通过生物表面活性剂在砂岩岩心深处的有效运移来补偿。本研究是一项新颖的尝试，旨在通过同时解决典型砂岩地层中复杂的原油-岩石-盐水化学和控制MEOR效率的关键热力学参数，展示LSAMF与LSWF在提高岩心尺度原油流动性和采收率方面的协同效应。该模型具有较低的计算成本和运行时间，提高了预测能力，为成功实现LSAMF预先选择潜在的候选者。
{"title":"Numerical Investigation on Low Salinity Augmented Microbial Flooding LSAMF within a Sandstone Core for Enhanced Oil Recovery Under Nonisothermal and Fluctuating pH Conditions","authors":"S. Chakraborty, S. Govindarajan, S. Gummadi","doi":"10.2118/206098-ms","DOIUrl":"https://doi.org/10.2118/206098-ms","url":null,"abstract":"\u0000 In an era of increasing energy demand, declining oil fields and fluctuating crude oil prices globally, most oil companies are looking forward to implementing cost effective and environmentally sustainable enhanced oil recovery (EOR) techniques such as low salinity waterflooding (LSWF) and microbial EOR (MEOR). The present study numerically investigates the combined influence of simultaneous LSWF and microbial flooding for in-Situ MEOR in tertiary mode within a sandstone core under spatiotemporally fluctuating pH and temperature conditions.\u0000 The developed black oil model consists of five major coupled submodels: nonlinear heat transport model; ion transport coupled with multiple ion exchange (MIE) involving uncomplexed cations and anions; pH variation with salinity and temperature; coupled reactive transport of injected substrates, Pseudomonas putida and produced biosurfactants with microbial maximum specific growth rate varying with temperature, salinity and pH; relative permeability and fractional flow curve variations due to interfacial tension reduction and wettability alteration (WA) by LSWF and biofilm deposition. The governing equations are solved using finite difference technique. Operator splitting and bisection methods are adopted to solve the MIE-transport model.\u0000 The present model is found to be numerically stable and agree well with previously published experimental and analytical results. In the proposed MIE-transport mechanism, decreasing injection water salinity (IWS) from 2.52 to 0.32 M causes enhanced Ca2+ desorption rendering rock surface towards more water wet. Consequently, oil relative permeability (kro) increases with >55% reduction in water fractional flow (fw) at water saturation of 0.5 from the initial oil-wet condition. Further reducing IWS to 0.03 M causes Ca2+ adsorption shifting the surface wettability towards more oil-wet thus increasing fw by 52%. Formation water salinity (FWS) showed minor impact on WA with <5% decrease in fw when FWS is reduced from 3.15 to 1.05 M. During LSAMF, biosurfactant production is enhanced by >63% on reducing IWS from 2.52 to 0.32 M with negligible increase on further reducing IWS and FWS. This might be due to limiting nonisothermal (40 to 55 °C) and nutrient availability conditions. LSAMF caused significant WA, increase in kro with fw reduction by >84%. Though pH increased from 8.0 to 8.9, it showed minor impact on microbial metabolism. Formation damage due to bioplugging observed near injection point is compensated by effective migration of biosurfactants deep within sandstone core.\u0000 The present study is a novel attempt to show synergistic effect of LSAMF over LSWF in enhancing oil mobility and recovery at core scale by simultaneously addressing complex crude oil-rock-brine chemistry and critical thermodynamic parameters that govern MEOR efficiency within a typical sandstone formation. The present model with relatively lower computational cost and running time improves the predictive ","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"154 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74282618","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}
Zulkuf Azizoglu, Z. Heidari, Leonardo Goncalves, Lucas Abreu Blanes de Oliveira, Moacyr Silva Do Nascimento Neto
Broadband dielectric dispersion measurements are attractive options for assessment of water-filled pore volume, especially when quantifying salt concentration is challenging. However, conventional models for interpretation of dielectric measurements such as Complex Refractive Index Model (CRIM) and Maxwell Garnett (MG) model require oversimplifying assumptions about pore structure and distribution of constituting fluids/minerals. Therefore, dielectric-based estimates of water saturation are often not reliable in the presence of complex pore structure, rock composition, and rock fabric (i.e., spatial distribution of solid/fluid components). The objectives of this paper are (a) to propose a simple workflow for interpretation of dielectric permittivity measurements in log-scale domain, which takes the impacts of complex pore geometry and distribution of minerals into account, (b) to experimentally verify the reliability of the introduced workflow in the core-scale domain, and (c) to apply the introduced workflow for well-log-based assessment of water saturation. The dielectric permittivity model includes tortuosity-dependent parameters to honor the complexity of the pore structure and rock fabric for interpretation of broadband dielectric dispersion measurements. We estimate tortuosity-dependent parameters for each rock type from dielectric permittivity measurements conducted on core samples. To verify the reliability of dielectric-based water saturation model, we conduct experimental measurements on core plugs taken from a carbonate formation with complex pore structures. We also introduce a workflow for applying the introduced model to dielectric dispersion well logs for depth-by-depth assessment of water saturation. The tortuosity-dependent parameters in log-scale domain can be estimated either via experimental core-scale calibration, well logs in fully water-saturated zones, or pore-scale evaluation in each rock type. The first approach is adopted in this paper. We successfully applied the introduced model on core samples and well logs from a pre-salt formation in Santos Basin. In the core-scale domain, the estimated water saturation using the introduced model resulted in an average relative error of less than 11% (compared to gravimetric measurements). The introduced workflow improved water saturation estimates by 91% compared to CRIM. Results confirmed the reliability of the new dielectric model. In application to well logs, we observed significant improvements in water saturation estimates compared to cases where a conventional effective medium model (i.e., CRIM) was used. The documented results from both core-scale and well-log-scale applications of the introduced method emphasize on the importance of honoring pore structure in the interpretation of dielectric measurements.
{"title":"Assessment of Water Saturation Using Dielectric Permittivity Measurements in Formations with Complex Pore Structure: Application to the Core- and Log- Scale Domains","authors":"Zulkuf Azizoglu, Z. Heidari, Leonardo Goncalves, Lucas Abreu Blanes de Oliveira, Moacyr Silva Do Nascimento Neto","doi":"10.2118/205987-ms","DOIUrl":"https://doi.org/10.2118/205987-ms","url":null,"abstract":"\u0000 Broadband dielectric dispersion measurements are attractive options for assessment of water-filled pore volume, especially when quantifying salt concentration is challenging. However, conventional models for interpretation of dielectric measurements such as Complex Refractive Index Model (CRIM) and Maxwell Garnett (MG) model require oversimplifying assumptions about pore structure and distribution of constituting fluids/minerals. Therefore, dielectric-based estimates of water saturation are often not reliable in the presence of complex pore structure, rock composition, and rock fabric (i.e., spatial distribution of solid/fluid components). The objectives of this paper are (a) to propose a simple workflow for interpretation of dielectric permittivity measurements in log-scale domain, which takes the impacts of complex pore geometry and distribution of minerals into account, (b) to experimentally verify the reliability of the introduced workflow in the core-scale domain, and (c) to apply the introduced workflow for well-log-based assessment of water saturation.\u0000 The dielectric permittivity model includes tortuosity-dependent parameters to honor the complexity of the pore structure and rock fabric for interpretation of broadband dielectric dispersion measurements. We estimate tortuosity-dependent parameters for each rock type from dielectric permittivity measurements conducted on core samples. To verify the reliability of dielectric-based water saturation model, we conduct experimental measurements on core plugs taken from a carbonate formation with complex pore structures. We also introduce a workflow for applying the introduced model to dielectric dispersion well logs for depth-by-depth assessment of water saturation. The tortuosity-dependent parameters in log-scale domain can be estimated either via experimental core-scale calibration, well logs in fully water-saturated zones, or pore-scale evaluation in each rock type. The first approach is adopted in this paper.\u0000 We successfully applied the introduced model on core samples and well logs from a pre-salt formation in Santos Basin. In the core-scale domain, the estimated water saturation using the introduced model resulted in an average relative error of less than 11% (compared to gravimetric measurements). The introduced workflow improved water saturation estimates by 91% compared to CRIM. Results confirmed the reliability of the new dielectric model. In application to well logs, we observed significant improvements in water saturation estimates compared to cases where a conventional effective medium model (i.e., CRIM) was used. The documented results from both core-scale and well-log-scale applications of the introduced method emphasize on the importance of honoring pore structure in the interpretation of dielectric measurements.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74857920","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}
Muhammad Abdulhadi, Hani Mohd Said, Ahmad Uzair Zubbir, Evelyn Ling, M. Nasir, Imran Anoar, Abdul Rahman Abdul Rahim, Rohani Elias, Paul Sanchez, Rizam Sharif, Zamri Abdul Ghapor, Nurhanim Ismail, Yoong Hau Kew
The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.
{"title":"Cost-Effective Development of Shallow and Poorer Quality Gas Reservoir in Mature Field","authors":"Muhammad Abdulhadi, Hani Mohd Said, Ahmad Uzair Zubbir, Evelyn Ling, M. Nasir, Imran Anoar, Abdul Rahman Abdul Rahim, Rohani Elias, Paul Sanchez, Rizam Sharif, Zamri Abdul Ghapor, Nurhanim Ismail, Yoong Hau Kew","doi":"10.2118/206315-ms","DOIUrl":"https://doi.org/10.2118/206315-ms","url":null,"abstract":"The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76477037","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}
This paper aims to present user experience survey results of innovative software assessment technologies available in the market aimed in evaluating risks of industrial-related ergonomic hazards. The scope covers industrial ergonomics softwares currently available for purchase where time-limited free trial is offered, particularly those that utilize 3D Motion Capture Assessment which relies on kinematic inputs aided by non-invasive computer technology and artificial intelligence, and makes use of pre-determined weightings based on biomechanical risk factors. In light of the inclusion criterion, six industrial ergonomics softwares were considered. User field trials were conducted during January to September 2020 among 10 Occupational Health Subject Matter Experts (OH SME) coming from seven oil and gas Group Companies. Each OH SME attended a product demonstration by the shortlisted software vendor, participated in software trial at their respective workplaces, and provided feedback on the software's usability by filling out a survey questionnaire. OH SME responses were then collected for further qualitative analyses. Three of the eligible softwares relied on photo snapshot capturing work activity where subsequent analysis is done through competent professional judgment of qualitative risk. Another three were dependent on 3D Motion Capture Assessment where upper and lower limb motions of employees are digitally captured, recorded, and analyzed. Two of the softwares utilized sensors attached to different parts of employee's body, while one relied on Android/Smartphone snapshot of work activity and analyzed by the software's algorithm. Analyses of OH SME feedback revealed majority of them (n = 7) preferred using 3D Motion Capture Assessment over professional judgment of qualitative risk as an effective tool in evaluation of industrial work-related ergonomic risks. 3D Motion Capture Assessment provided accurate measurements of employee joint postures and postural angles. The tool ensured consistency in risk scoring for a particular industrial-related work activity as the calculation is standardized. The tool's algorithm is aligned with globally accepted assessment tools in evaluating ergonomic risks which enhances its validity. OH SMEs have expressed concerns on use of Android/Smartphone in Critical Infrastructure and Coastal Protection Authority facilities, training time needed in learning the software, and repetitive use of motion sensors among different employees which may lead to personal hygiene issues. 3D Motion Capture Assessment is a novel ergonomics software tool that can be used in real-time and accurate evaluation of ergonomic risks arising from industrial work-related activities. It can replace observational assessment of a work activity that may be prone to professional judgment errors. However, more validation and reliability studies need to be done in future as well as determining association between ergonomics risk scores obtained
{"title":"User Experience Survey of Innovative Softwares in Evaluation of Industrial-Related Ergonomic Hazards: A Focus on 3D Motion Capture Assessment","authors":"Bufford Advincula","doi":"10.2118/205850-ms","DOIUrl":"https://doi.org/10.2118/205850-ms","url":null,"abstract":"\u0000 This paper aims to present user experience survey results of innovative software assessment technologies available in the market aimed in evaluating risks of industrial-related ergonomic hazards. The scope covers industrial ergonomics softwares currently available for purchase where time-limited free trial is offered, particularly those that utilize 3D Motion Capture Assessment which relies on kinematic inputs aided by non-invasive computer technology and artificial intelligence, and makes use of pre-determined weightings based on biomechanical risk factors.\u0000 In light of the inclusion criterion, six industrial ergonomics softwares were considered. User field trials were conducted during January to September 2020 among 10 Occupational Health Subject Matter Experts (OH SME) coming from seven oil and gas Group Companies. Each OH SME attended a product demonstration by the shortlisted software vendor, participated in software trial at their respective workplaces, and provided feedback on the software's usability by filling out a survey questionnaire. OH SME responses were then collected for further qualitative analyses.\u0000 Three of the eligible softwares relied on photo snapshot capturing work activity where subsequent analysis is done through competent professional judgment of qualitative risk. Another three were dependent on 3D Motion Capture Assessment where upper and lower limb motions of employees are digitally captured, recorded, and analyzed. Two of the softwares utilized sensors attached to different parts of employee's body, while one relied on Android/Smartphone snapshot of work activity and analyzed by the software's algorithm. Analyses of OH SME feedback revealed majority of them (n = 7) preferred using 3D Motion Capture Assessment over professional judgment of qualitative risk as an effective tool in evaluation of industrial work-related ergonomic risks. 3D Motion Capture Assessment provided accurate measurements of employee joint postures and postural angles. The tool ensured consistency in risk scoring for a particular industrial-related work activity as the calculation is standardized. The tool's algorithm is aligned with globally accepted assessment tools in evaluating ergonomic risks which enhances its validity. OH SMEs have expressed concerns on use of Android/Smartphone in Critical Infrastructure and Coastal Protection Authority facilities, training time needed in learning the software, and repetitive use of motion sensors among different employees which may lead to personal hygiene issues.\u0000 3D Motion Capture Assessment is a novel ergonomics software tool that can be used in real-time and accurate evaluation of ergonomic risks arising from industrial work-related activities. It can replace observational assessment of a work activity that may be prone to professional judgment errors. However, more validation and reliability studies need to be done in future as well as determining association between ergonomics risk scores obtained ","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 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":"77599556","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}
K. Maksyutin, Anna Zalevina, P. Sorokin, V. Rukavishnikov, Artem Boev, P. Kharitontseva, V. Solovev, Arina Portniagina, Alexey Lukin
A major Russian oil company is currently carrying through an ambitious program aimed at transforming corporate E&P business model. The new model involving product-based approach to exploration and production will require young professionals with new skills and mindsets beyond regular university curricula. To proactively satisfy this demand, the company joined forces with one of its partner universities to champion Engineers of the Future, a training initiative aimed at senior students about to graduate and join the company. Engineers of the Future offer a fresh perspective and approach to training young professionals, mixing conventional training with problem-based and game-based learning to deliver a unique combination of hard and soft skills required by company's new operating paradigm. Program graduates are expected to make a great addition to corporate product teams, enabling the company to achieve its challenging strategic goals.
{"title":"Engineers of the Future: Student Training Program for the New Business Model","authors":"K. Maksyutin, Anna Zalevina, P. Sorokin, V. Rukavishnikov, Artem Boev, P. Kharitontseva, V. Solovev, Arina Portniagina, Alexey Lukin","doi":"10.2118/206130-ms","DOIUrl":"https://doi.org/10.2118/206130-ms","url":null,"abstract":"\u0000 A major Russian oil company is currently carrying through an ambitious program aimed at transforming corporate E&P business model. The new model involving product-based approach to exploration and production will require young professionals with new skills and mindsets beyond regular university curricula. To proactively satisfy this demand, the company joined forces with one of its partner universities to champion Engineers of the Future, a training initiative aimed at senior students about to graduate and join the company.\u0000 Engineers of the Future offer a fresh perspective and approach to training young professionals, mixing conventional training with problem-based and game-based learning to deliver a unique combination of hard and soft skills required by company's new operating paradigm. Program graduates are expected to make a great addition to corporate product teams, enabling the company to achieve its challenging strategic goals.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79408649","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}
Hydraulic fracturing stimulation of unconventional wells employing large volumes of sand in low viscosity fluids provides propped fracture conductivity in less than 25% of the created fracture area, primarily because of poor sand transport mechanics. The remaining unpropped area is at best only marginally productive using the conventional sand/slickwater hydraulic fracturing process alone. Near-neutrally buoyant proppants (NBPs, ASG 1.055) have proven to be highly effective in accessing production from fracture area that is otherwise left unpropped. Fracture models illustrate the propped fracture area of designs incorporating NBPs is improved to over 85% of the created fracture area. Production simulations of typical slickwater and sand frac designs supplemented with NBPs at 3% by weight of sand distributed evenly throughout the slurry stages show cumulative production increases of 20% to greater than 50% compared to the large volume slickwater/sand treatments without NBPs. Efforts have been directed to justification of the incremental expense involved with the NBP applications and assessment of the associated value-added economic metrics, including the value of the realized incremental production vs. time, the payback time for recovery of the incremental costs, and Return on Investment (ROI). For example, in a 2018 trial of NBP wells in the Middle Bakken formation of North Dakota, the production uplift observed for NBP wells achieved payback of the incremental costs in an average of 26 days; the 1-year cumulative oil production of the NBP wells averaged 69,632 barrels greater than control wells, resulting in a 25% uplift compared to the offset control wells. The Year 1 Return on Investment (ROI) for the drilling and completion costs of the first Middle Bakken well with NBP was 97% versus 64% for the sand-only control wells. Controlled multi-stage horizontal completions of wells with sand-only have been evaluated against wells utilizing NBPs in the application have been executed within several unconventional plays, including the Permian and Williston basins. The performance of the NBP wells have consistently validated the production uplift predictions of the production simulation models. The case studies analyzed herein expand the economic assessment of the NBP stimulation designs by including production analyses quantitative comparison of Net Present Value, production decline rates, and projected EURs of the NBP wells and non-NBP offset wells.
{"title":"Incorporation of Neutrally Buoyant Proppants in Horizontal Unconventional Wells to Increase Propped Fracture Area Results for Substantially Improved Well Productivity and Economics","authors":"H. Brannon, N. Hoffman","doi":"10.2118/205845-ms","DOIUrl":"https://doi.org/10.2118/205845-ms","url":null,"abstract":"\u0000 Hydraulic fracturing stimulation of unconventional wells employing large volumes of sand in low viscosity fluids provides propped fracture conductivity in less than 25% of the created fracture area, primarily because of poor sand transport mechanics. The remaining unpropped area is at best only marginally productive using the conventional sand/slickwater hydraulic fracturing process alone. Near-neutrally buoyant proppants (NBPs, ASG 1.055) have proven to be highly effective in accessing production from fracture area that is otherwise left unpropped. Fracture models illustrate the propped fracture area of designs incorporating NBPs is improved to over 85% of the created fracture area. Production simulations of typical slickwater and sand frac designs supplemented with NBPs at 3% by weight of sand distributed evenly throughout the slurry stages show cumulative production increases of 20% to greater than 50% compared to the large volume slickwater/sand treatments without NBPs.\u0000 Efforts have been directed to justification of the incremental expense involved with the NBP applications and assessment of the associated value-added economic metrics, including the value of the realized incremental production vs. time, the payback time for recovery of the incremental costs, and Return on Investment (ROI). For example, in a 2018 trial of NBP wells in the Middle Bakken formation of North Dakota, the production uplift observed for NBP wells achieved payback of the incremental costs in an average of 26 days; the 1-year cumulative oil production of the NBP wells averaged 69,632 barrels greater than control wells, resulting in a 25% uplift compared to the offset control wells. The Year 1 Return on Investment (ROI) for the drilling and completion costs of the first Middle Bakken well with NBP was 97% versus 64% for the sand-only control wells.\u0000 Controlled multi-stage horizontal completions of wells with sand-only have been evaluated against wells utilizing NBPs in the application have been executed within several unconventional plays, including the Permian and Williston basins. The performance of the NBP wells have consistently validated the production uplift predictions of the production simulation models. The case studies analyzed herein expand the economic assessment of the NBP stimulation designs by including production analyses quantitative comparison of Net Present Value, production decline rates, and projected EURs of the NBP wells and non-NBP offset wells.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72802027","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}
Harshad Patil, I. Knight, Svein Hovland, E. Dietrich, S. Boutalbi, Jerib Leal, Rick Gonzalez, Greg Matherne
Until recently many of the wells on US land that were drilled using Managed Pressure Drilling (MPD) technology utilized one size fits all equipment designed for the offshore market. Since the cost and personnel requirements needed to run the offshore manifolds became a challenge due to market conditions and Covid-19 restrictions, the drillers sought a cost effective and simpler system to conduct their day-to- day operations. The challenge was to drill long laterals in Permian and Haynesville without losing the necessary MPD functionality that proved beneficial to reduce the risks associated with safety and to enhance drilling efficiency. For the MPD control system experts, the task was to correctly identify and automate MPD system’s functionality that would be of greatest use to the drillers to sustain their drilling performance. The concept of developing an easier to operate control system was undertaken wherein system accuracy and precision was maintained at the forefront of the development process. Electric motors/actuators and necessary drivers that could work directly on rig power were selected and tested. Control system logic that operates the chokes was modified to quickly adapt to the changes in drilling conditions, maintaining the necessary accuracy. This was done by studying and understanding drillers activities and behaviors like automated pump ramp down speed during connections, pipe movement during tripping etc. Specific MPD engineering charts, simple to decipher graphs, and necessary calculation tables were developed for the drillers to use for managing bottomhole pressures. Calculations which included specific schedules for spotting weighted pills were provided to maintain simplicity of the operations and something the drillers could easily execute. Today, many drillers are using this MPD solution to drill long laterals (Hovland et.al 2020). This trend is slowly leading to reduction of rig MPD personnel, especially during Covid-19, while the drillers are getting familiar with and operating MPD systems. A few of the crucial items that have allowed the drillers to run MPD on their own include MPD controls connected to drilling automation systems and the subsequent continuous revision of these controls based on understanding drillers tasks and needs. The use of electric motors enabled quick adoption to the changing drilling conditions while making connections, tripping etc. The furnished MPD calculations and graphs that drillers could follow for applying required MPD choke pressures kept MPD adaption simpler. The modifications made to the MPD choke controls geared towards facilitating necessary automation enabled the drillers to get trained in few days and operate the MPD systems while maintaining the same level of speed and performance.
{"title":"Simplified Solution for Managed Pressure Drilling - System that Drillers Can Operate","authors":"Harshad Patil, I. Knight, Svein Hovland, E. Dietrich, S. Boutalbi, Jerib Leal, Rick Gonzalez, Greg Matherne","doi":"10.2118/205855-ms","DOIUrl":"https://doi.org/10.2118/205855-ms","url":null,"abstract":"\u0000 Until recently many of the wells on US land that were drilled using Managed Pressure Drilling (MPD) technology utilized one size fits all equipment designed for the offshore market. Since the cost and personnel requirements needed to run the offshore manifolds became a challenge due to market conditions and Covid-19 restrictions, the drillers sought a cost effective and simpler system to conduct their day-to- day operations. The challenge was to drill long laterals in Permian and Haynesville without losing the necessary MPD functionality that proved beneficial to reduce the risks associated with safety and to enhance drilling efficiency. For the MPD control system experts, the task was to correctly identify and automate MPD system’s functionality that would be of greatest use to the drillers to sustain their drilling performance.\u0000 The concept of developing an easier to operate control system was undertaken wherein system accuracy and precision was maintained at the forefront of the development process. Electric motors/actuators and necessary drivers that could work directly on rig power were selected and tested. Control system logic that operates the chokes was modified to quickly adapt to the changes in drilling conditions, maintaining the necessary accuracy. This was done by studying and understanding drillers activities and behaviors like automated pump ramp down speed during connections, pipe movement during tripping etc. Specific MPD engineering charts, simple to decipher graphs, and necessary calculation tables were developed for the drillers to use for managing bottomhole pressures. Calculations which included specific schedules for spotting weighted pills were provided to maintain simplicity of the operations and something the drillers could easily execute.\u0000 Today, many drillers are using this MPD solution to drill long laterals (Hovland et.al 2020). This trend is slowly leading to reduction of rig MPD personnel, especially during Covid-19, while the drillers are getting familiar with and operating MPD systems. A few of the crucial items that have allowed the drillers to run MPD on their own include MPD controls connected to drilling automation systems and the subsequent continuous revision of these controls based on understanding drillers tasks and needs. The use of electric motors enabled quick adoption to the changing drilling conditions while making connections, tripping etc.\u0000 The furnished MPD calculations and graphs that drillers could follow for applying required MPD choke pressures kept MPD adaption simpler. The modifications made to the MPD choke controls geared towards facilitating necessary automation enabled the drillers to get trained in few days and operate the MPD systems while maintaining the same level of speed and performance.","PeriodicalId":10965,"journal":{"name":"Day 3 Thu, September 23, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72815457","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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