Refracturing is often required in shale and tight gas formations because of inadequate initial HF design or unexpectedly rapid production decline. Water blocking because of fracturing liquid incompatibility, unexpected proppant embedment and crushing, shorter or curved primary fracture length because of premature screen off, general pressure depletion, primary fracture mis-orientation from stress shadowing, unfavourable poroelastic effects limiting the performance of the stimulated volume, and, in general, formation permeability reduction from stress sensitivity may all contribute to unsatisfactory or rapidly declining production. We emphasize the role of geomechanics in candidate screening and review the major factors leading to production decline in unconventional reservoirs. Although the fracture geometry may be altered in a staged fracturing process, the primary focus should be given to the formation permeability enhancement either due to shear dilation or induced fractured network elongation.
{"title":"Refrac Screening Processes in Unconventional Reservoirs, A Geomechanics Perspective","authors":"Yarlong Wang, M. Dusseault","doi":"10.2118/194811-MS","DOIUrl":"https://doi.org/10.2118/194811-MS","url":null,"abstract":"\u0000 Refracturing is often required in shale and tight gas formations because of inadequate initial HF design or unexpectedly rapid production decline. Water blocking because of fracturing liquid incompatibility, unexpected proppant embedment and crushing, shorter or curved primary fracture length because of premature screen off, general pressure depletion, primary fracture mis-orientation from stress shadowing, unfavourable poroelastic effects limiting the performance of the stimulated volume, and, in general, formation permeability reduction from stress sensitivity may all contribute to unsatisfactory or rapidly declining production. We emphasize the role of geomechanics in candidate screening and review the major factors leading to production decline in unconventional reservoirs. Although the fracture geometry may be altered in a staged fracturing process, the primary focus should be given to the formation permeability enhancement either due to shear dilation or induced fractured network elongation.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73907603","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 the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target. Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas. The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio. This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.
{"title":"Effective Waterflood Management of a Giant Clastic Upper Burgan Reservoir Leads to Tripling of Production, Raudhatain Field, North Kuwait","authors":"N. Al-Hajeri, Suresh Chellappan, M. Al-Mufarrej","doi":"10.2118/194846-MS","DOIUrl":"https://doi.org/10.2118/194846-MS","url":null,"abstract":"\u0000 In the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target.\u0000 Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas.\u0000 The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio.\u0000 This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74400766","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 examination and prevention of casing damage is an important work in oil and gas field development projects. Casing damage will directly influence the production of oil and gas, the effect of water injection and the life cycle of oil, gas and water well. With the number of casing damage wells increasing year by year in each oil field, inspections and precautions of casing damage status have become more and more important during development of the filed. With the development of big data technologies, we can predict the casing damage based on historical and real-time data, and optimize the maintenance intervals of casing. In this paper, we proposed a casing damage prediction method based on principal component analysis (PCA) and gradient boosting decision tree (GBDT) algorithm. Building a three-nodes Spark big data platform, we tested our proposed method on a dataset in an oil-field in mid-east China. Firstly, based on data analysis and expertise, selected 10 parameters which affect the casing damage most, including casing outside diameter, wall thickness, perforation density etc. Secondly, using PCA to reduce the dimension of parameters. Thirdly, building the algorithm model of casing damage risk assessment by GBDT, training and optimizing the model parameters. Fourthly, using the proposed model for casing damage prediction. Using precision and AUC(Area Under ROC Curve) to evaluate the proposed method, and compared with traditional methods, including decision tree, logistic regression and Naïve Bayes, the experiment results show that compared with traditional methods, the proposed method gain 86.3% precision and AUC is 1, both higher than traditional methods, which means it has better prediction precision and performance. The proposed method also can apply to predict the probability of a normal well becoming a casing damage well, and finally can provide the decision support for on-site operations. The proposed method using data-driven idea to provide the decision support for oilfield operations, and lay the foundation for the construction of intelligence oilfield.
套管损伤检测与预防是油气田开发项目中的一项重要工作。套管损坏将直接影响到油气产量、注水效果和油、气、水井生命周期。随着各油田套管损坏井数量的逐年增加，在油田开发过程中，对套管损坏状况的检查和预防变得越来越重要。随着大数据技术的发展，可以基于历史数据和实时数据预测套管损坏情况，优化套管维修间隔。提出了一种基于主成分分析(PCA)和梯度增强决策树(GBDT)算法的套管损伤预测方法。建立了一个三节点Spark大数据平台，在中国中东某油田的数据集上对本文提出的方法进行了测试。首先，根据数据分析和专业知识，选取了对套管损伤影响最大的10个参数，包括套管外径、壁厚、射孔密度等;其次，利用主成分分析法对参数进行降维。第三，利用GBDT建立套管损伤风险评估算法模型，并对模型参数进行训练和优化。第四，应用该模型进行套管损伤预测。利用精度和ROC曲线下面积(Area Under ROC Curve, AUC)对所提出方法进行评价，并与决策树、逻辑回归和Naïve贝叶斯等传统方法进行比较，实验结果表明，与传统方法相比，所提出方法的精度为86.3%，AUC为1，均高于传统方法，具有更好的预测精度和性能。该方法还可用于正常井变成套管损坏井的概率预测，为现场作业提供决策支持。该方法运用数据驱动思想，为油田作业提供决策支持，为油田智能化建设奠定基础。
{"title":"A Casing Damage Prediction Method Based on Principal Component Analysis and Gradient Boosting Decision Tree Algorithm","authors":"M. Song, Xiangguang Zhou","doi":"10.2118/194956-MS","DOIUrl":"https://doi.org/10.2118/194956-MS","url":null,"abstract":"\u0000 The examination and prevention of casing damage is an important work in oil and gas field development projects. Casing damage will directly influence the production of oil and gas, the effect of water injection and the life cycle of oil, gas and water well. With the number of casing damage wells increasing year by year in each oil field, inspections and precautions of casing damage status have become more and more important during development of the filed. With the development of big data technologies, we can predict the casing damage based on historical and real-time data, and optimize the maintenance intervals of casing.\u0000 In this paper, we proposed a casing damage prediction method based on principal component analysis (PCA) and gradient boosting decision tree (GBDT) algorithm. Building a three-nodes Spark big data platform, we tested our proposed method on a dataset in an oil-field in mid-east China. Firstly, based on data analysis and expertise, selected 10 parameters which affect the casing damage most, including casing outside diameter, wall thickness, perforation density etc. Secondly, using PCA to reduce the dimension of parameters. Thirdly, building the algorithm model of casing damage risk assessment by GBDT, training and optimizing the model parameters. Fourthly, using the proposed model for casing damage prediction.\u0000 Using precision and AUC(Area Under ROC Curve) to evaluate the proposed method, and compared with traditional methods, including decision tree, logistic regression and Naïve Bayes, the experiment results show that compared with traditional methods, the proposed method gain 86.3% precision and AUC is 1, both higher than traditional methods, which means it has better prediction precision and performance. The proposed method also can apply to predict the probability of a normal well becoming a casing damage well, and finally can provide the decision support for on-site operations. The proposed method using data-driven idea to provide the decision support for oilfield operations, and lay the foundation for the construction of intelligence oilfield.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78916434","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}
S. Batarseh, D. S. R. Alerigi, Omar Al Obaid, Haitham A. Othman
Establishing communication between the wellbore and hydrocarbon-bearing formations is critical to ensure optimal production. Laser is a new technology that utilizes the power of light to perforate rocks. The technology is non-damaging, safe (non-explosive), and affords precise control over the perforation's geometry (size and shape). The process creates an enhanced tunnel that improves the flow and increases production. The technology has been successfully demonstrated in the lab environment. The results are used to develop a field deployment strategy. In the field, the laser source will be mounted on a coiled tubing unit on the surface and transmitted downhole via optical fibers. Downhole, the beam is out-coupled and directed to the target using an optical bottom hole assembly (oBHA). This tool combines optical and mechanical components to control the beam and produce multipole shots per foot as needed to create the desired perforation network. High-power laser perforation is the next new intelligent perforation generation that will change current well perforation. Laser-rock interaction drives in the transformation of electromagnetic energy into thermal energy. This results in a highly localized and controllable temperature surge that can melt or vaporize the rocks. These properties make the technology a unique alternative to current perforation techniques based on shaped charge guns. The thermal process induced by the laser enhances the flow properties of the rock, especially in tight formations. Laser perforation has been tested on all types for rocks including unconventional tight sands. This has been proven through extensive pre- and post-perforation characterization over the last two decades. This work presents the development and evolution of the high-power laser tools for subsurface applications. These tools provide innovative and non-damaging alternatives to current downhole technologies. In the lab, the laser technology has been proven to improve the flow properties; thus, it can improve communication between the wellbore and formation. To achieve this efficiently in the field, it is necessary to develop different tool designs and configurations, manufacture prototypes, conduct extensive tests, and optimize each part before upscale for field operations. The laser source is mounted in a coil tubing rig at the surface; the coil contains the optical fiber cable used to convey the energy to the downhole tool. The tool combines mechanical and optical components to transform, control, and direct the laser beam. The design and configuration of each tool assembly varies depending on the targeted application. For example, the perforation tool converts and splits the beam into several horizontal beams; whereas the drilling tool emits a straight beam with controlled size for deeper penetration. They also incorporate purging capabilities to circulate fluids to clean the hole from the debris and carry the cuttings. The entire assembly must be
{"title":"Laser Gun: The Next Perforation Technology","authors":"S. Batarseh, D. S. R. Alerigi, Omar Al Obaid, Haitham A. Othman","doi":"10.2118/194775-MS","DOIUrl":"https://doi.org/10.2118/194775-MS","url":null,"abstract":"\u0000 Establishing communication between the wellbore and hydrocarbon-bearing formations is critical to ensure optimal production. Laser is a new technology that utilizes the power of light to perforate rocks. The technology is non-damaging, safe (non-explosive), and affords precise control over the perforation's geometry (size and shape). The process creates an enhanced tunnel that improves the flow and increases production. The technology has been successfully demonstrated in the lab environment. The results are used to develop a field deployment strategy. In the field, the laser source will be mounted on a coiled tubing unit on the surface and transmitted downhole via optical fibers. Downhole, the beam is out-coupled and directed to the target using an optical bottom hole assembly (oBHA). This tool combines optical and mechanical components to control the beam and produce multipole shots per foot as needed to create the desired perforation network. High-power laser perforation is the next new intelligent perforation generation that will change current well perforation.\u0000 Laser-rock interaction drives in the transformation of electromagnetic energy into thermal energy. This results in a highly localized and controllable temperature surge that can melt or vaporize the rocks. These properties make the technology a unique alternative to current perforation techniques based on shaped charge guns. The thermal process induced by the laser enhances the flow properties of the rock, especially in tight formations. Laser perforation has been tested on all types for rocks including unconventional tight sands. This has been proven through extensive pre- and post-perforation characterization over the last two decades.\u0000 This work presents the development and evolution of the high-power laser tools for subsurface applications. These tools provide innovative and non-damaging alternatives to current downhole technologies. In the lab, the laser technology has been proven to improve the flow properties; thus, it can improve communication between the wellbore and formation. To achieve this efficiently in the field, it is necessary to develop different tool designs and configurations, manufacture prototypes, conduct extensive tests, and optimize each part before upscale for field operations.\u0000 The laser source is mounted in a coil tubing rig at the surface; the coil contains the optical fiber cable used to convey the energy to the downhole tool. The tool combines mechanical and optical components to transform, control, and direct the laser beam. The design and configuration of each tool assembly varies depending on the targeted application. For example, the perforation tool converts and splits the beam into several horizontal beams; whereas the drilling tool emits a straight beam with controlled size for deeper penetration. They also incorporate purging capabilities to circulate fluids to clean the hole from the debris and carry the cuttings. The entire assembly must be ","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72666476","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}
Performance evaluations of oil and gas assets are crucial for continuously improving operational efficiency in the mainstream petroleum industry. The success of such evaluations is largely driven by the analysis of the data accumulated during the asset's operational cycle. Usually, the amount of data stored in the databases dramatically exceeds the ability to approach the analysis with traditional spreadsheet-based tools or linear modeling. In this study we use data mining with multivariate predictive analytics and monetize on the value of data by transforming the inferred information into knowledge and further into rigorous business decisions. With the expansion of the Digital Oil Field and transformation into the 4th Industrial Revolution, the oil and gas industry is acquiring tremendous amounts of data that come from disparate sources in a variety of origins, time scales, structures and quality. The underlying variable root-cause relationships are highly non-linear and non-intuitive, and simplistic linear regression methods are suboptimal. We approach the challenge by developing a data-driven workflow that integrates components of artificial intelligence, machine learning and pattern recognition to enhance quantitative understanding of complex data. The sanitized aggregated data set combines 470 horizontal wells, covering 15 numerical (e.g., stimulation interval length, production rates) and categorical (e.g., target zone, proppant type) predictors and the total produced BOE, as the response variable. The objective is to predict an optimal set of variables that maximize the production. We utilize an integrated analytics platform that enables a variety of sophisticated statistical operations on large-scale data: a) comprehensive data QA/QC for outliers, consistency and missing entries; b) Exploratory Data Analysis and visualization; c) feature selection, screening and ranking; d) building and training of multiple machine learning (ML) models for multi-variate regression (e.g. generalized linear model, deep learning, decision tree, random forest and gradient boosted machine); and e) response optimization of an identified "best-performing" ML model for highest prediction accuracy. Our study introduces the initiative to establish concepts best practices for predictive and prescriptive analytics in domains of reservoir simulation, description and asset management. Given the unique volume and information richness of operational data, acquired over decades of production history, the anticipated applications of predictive analytics could expand to drilling optimization, smart data aggregation, well stimulation and equipment maintenance.
{"title":"Application of Automated Machine Learning for Multi-Variate Prediction of Well Production","authors":"M. Maučec, S. Garni","doi":"10.2118/195022-MS","DOIUrl":"https://doi.org/10.2118/195022-MS","url":null,"abstract":"\u0000 Performance evaluations of oil and gas assets are crucial for continuously improving operational efficiency in the mainstream petroleum industry. The success of such evaluations is largely driven by the analysis of the data accumulated during the asset's operational cycle. Usually, the amount of data stored in the databases dramatically exceeds the ability to approach the analysis with traditional spreadsheet-based tools or linear modeling. In this study we use data mining with multivariate predictive analytics and monetize on the value of data by transforming the inferred information into knowledge and further into rigorous business decisions.\u0000 With the expansion of the Digital Oil Field and transformation into the 4th Industrial Revolution, the oil and gas industry is acquiring tremendous amounts of data that come from disparate sources in a variety of origins, time scales, structures and quality. The underlying variable root-cause relationships are highly non-linear and non-intuitive, and simplistic linear regression methods are suboptimal. We approach the challenge by developing a data-driven workflow that integrates components of artificial intelligence, machine learning and pattern recognition to enhance quantitative understanding of complex data.\u0000 The sanitized aggregated data set combines 470 horizontal wells, covering 15 numerical (e.g., stimulation interval length, production rates) and categorical (e.g., target zone, proppant type) predictors and the total produced BOE, as the response variable. The objective is to predict an optimal set of variables that maximize the production. We utilize an integrated analytics platform that enables a variety of sophisticated statistical operations on large-scale data: a) comprehensive data QA/QC for outliers, consistency and missing entries; b) Exploratory Data Analysis and visualization; c) feature selection, screening and ranking; d) building and training of multiple machine learning (ML) models for multi-variate regression (e.g. generalized linear model, deep learning, decision tree, random forest and gradient boosted machine); and e) response optimization of an identified \"best-performing\" ML model for highest prediction accuracy.\u0000 Our study introduces the initiative to establish concepts best practices for predictive and prescriptive analytics in domains of reservoir simulation, description and asset management. Given the unique volume and information richness of operational data, acquired over decades of production history, the anticipated applications of predictive analytics could expand to drilling optimization, smart data aggregation, well stimulation and equipment maintenance.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77574417","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 is often performed using resin-coated proppants to minimize proppant flowback during hydrocarbon production, whether the resin is precoated or coated on-the-fly as the treatment is pumped. Resin-fracturing fluid interaction can have a negative effect on fluid stability or resin consolidation, or both. This paper examines the effects of resin-fluid interactions on fluid stability, proppant consolidation strength, and strategies to mitigate the effects. Components of resins can change the fracturing fluid stability by interacting with crosslinker or breaker, or by changing the fluid pH. To offset the effect of a resin, the breaker/crosslinker/buffer concentration should be tuned while pumping resin-coated proppant. Similarly, resin-fluid interaction can decrease consolidation strength by disturbing resin-curing kinetics or reducing grain-to-grain contact, which can increase the possibility of proppant flowback during production. The influence of resins on fracturing fluid stability was evaluated by conducting rheology testing. The effect of fracturing fluids on the consolidation strength of resin was evaluated by comparing unconfined compressive strength (UCS) of proppant packs. The stability of zirconate and borate crosslinked guar fluids, when treated with coated on the fly liquid resin-coated proppant (LRCP), was lower than non-treated fluids at 260°F as a result of breaker activation by the resin components. The desired fluid stability was attained by lowering breaker concentration in liquid resin-treated fluid. During another round of testing, a second type of LRCP, based on different chemical functionality, increased the stability of synthetic polymer fluid at 400°F. Likewise, a rise in fluid stability was observed when guar fluid was treated with resin pre-coated proppant (RCP) at 200 and 250°F. The improved fluid stability is associated with reduction in active breaker concentration in the presence of furan resin and RCP. The UCS value of the proppant pack prepared from fracturing fluid-treated RCP was ~16 to 45% lower than the proppant pack without this fluid treatment. Additionally, the UCS value of proppant pack prepared using fracturing fluid-treated LRCP decreased by ~30%. However, the measured UCS value of LRCP pack with fracturing fluid exposure was higher than the RCP pack measured value even without exposure to this fluid. Incorporating LRCP instead of using RCP during fracturing operations could address the proppant flowback issue and possibly result in higher conductivity of propped fractures. It could help ensure economic production rates and prevent costs associated wellbore cleanup, downhole tool damage, erosion and damage to the tubular, chokes, valves and separators, and refracturing of the well. Ultimately, it could help maintain a lower cost per barrel of oil equivalent (BOE).
{"title":"Effects of Resin-Fluid Interaction on Fracturing Fluid Stability, Proppant Flowback, and Preventive Control Methods","authors":"S. Songire, Chetana Prakash, Ravikant S. Belakshe","doi":"10.2118/194959-MS","DOIUrl":"https://doi.org/10.2118/194959-MS","url":null,"abstract":"\u0000 Hydraulic fracturing is often performed using resin-coated proppants to minimize proppant flowback during hydrocarbon production, whether the resin is precoated or coated on-the-fly as the treatment is pumped. Resin-fracturing fluid interaction can have a negative effect on fluid stability or resin consolidation, or both. This paper examines the effects of resin-fluid interactions on fluid stability, proppant consolidation strength, and strategies to mitigate the effects.\u0000 Components of resins can change the fracturing fluid stability by interacting with crosslinker or breaker, or by changing the fluid pH. To offset the effect of a resin, the breaker/crosslinker/buffer concentration should be tuned while pumping resin-coated proppant. Similarly, resin-fluid interaction can decrease consolidation strength by disturbing resin-curing kinetics or reducing grain-to-grain contact, which can increase the possibility of proppant flowback during production. The influence of resins on fracturing fluid stability was evaluated by conducting rheology testing. The effect of fracturing fluids on the consolidation strength of resin was evaluated by comparing unconfined compressive strength (UCS) of proppant packs.\u0000 The stability of zirconate and borate crosslinked guar fluids, when treated with coated on the fly liquid resin-coated proppant (LRCP), was lower than non-treated fluids at 260°F as a result of breaker activation by the resin components. The desired fluid stability was attained by lowering breaker concentration in liquid resin-treated fluid. During another round of testing, a second type of LRCP, based on different chemical functionality, increased the stability of synthetic polymer fluid at 400°F. Likewise, a rise in fluid stability was observed when guar fluid was treated with resin pre-coated proppant (RCP) at 200 and 250°F. The improved fluid stability is associated with reduction in active breaker concentration in the presence of furan resin and RCP. The UCS value of the proppant pack prepared from fracturing fluid-treated RCP was ~16 to 45% lower than the proppant pack without this fluid treatment. Additionally, the UCS value of proppant pack prepared using fracturing fluid-treated LRCP decreased by ~30%. However, the measured UCS value of LRCP pack with fracturing fluid exposure was higher than the RCP pack measured value even without exposure to this fluid.\u0000 Incorporating LRCP instead of using RCP during fracturing operations could address the proppant flowback issue and possibly result in higher conductivity of propped fractures. It could help ensure economic production rates and prevent costs associated wellbore cleanup, downhole tool damage, erosion and damage to the tubular, chokes, valves and separators, and refracturing of the well. Ultimately, it could help maintain a lower cost per barrel of oil equivalent (BOE).","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79251533","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}
Z. Al-Yazeedi, Y. Al-Zaabi, Mahmood Al-Oraimi, Wafa Al-Kiyumi, Ashwaq Al-Rawahi, Kifah Al-Tobi, Ali Amor Algheithy
Water flood WF accounts for 40% of Petroleum Development Oman PDO's oil production and volumes. A proper WF management is a key to realize that. This project aims to standardize and simplify WF performance review process, which is very important part of WF management. The current condition of WF performance review vary from field to another in term of frequency of conducting the reviews i.e, once a year, quarterly which resulted in missing the opportunities to improve the WF performance on the right time. Different in house tools and databases are used to prepare the technical materials for the review meeting. As a result, different fields have different way of presenting the technical materials to the reviewers across the company, so no standard pattern review template available and multiple sources for data are used. The field petroleum engineer takes up to 4 hours to prepare the technical material for one pattern review and usually senior or high skills PE requires generating different type of plots. When the Pattern review conducted almost 4 hours for the individual petroleum engineers spent during one pattern review. The proposed counter measures for this project were to replace the review frequency to exception or requirement base to ensure no missed opportunities. As well as standardizing the technical materials for WF pattern review using a single tool/source. The standard template has to fit all patterns in a field. It has to be accessible, with good visualization, and secured storage A Successful pilot run in one of the water flood fields in North Oman with 30+ WF patterns and has demonstrated the following results; standard review template developed within one source data platform. The pattern review was conducted on exceptional based which was a proactive approach. The PE team managed to generate extra optimization opportunities which resulted in proven an increased in oil production of +30 m3/d from 5 patterns. PE saved 3.5 hours/ pattern in preparation. The reviewers appreciated the improvement of quality of the technical materials, which create direct focus on issues identified based on exception. All the technical material were easy to generate by any less experience engineers. To maintain sustainability of the achieved improvements, some lean tools have been used. These tools are summarized in the following points; Standard operating procedures (SOP); two SOPs were generated, one to set up the tool and the other to do the review.Visual management (VM); was also generated to keep track the pattern review and ensure healthy WFM and.Leader Standard Work (LSW); it was completed to ensure sustainability through leader ship support.
{"title":"Standardize/Simplify Water Flood Pattern Reviews","authors":"Z. Al-Yazeedi, Y. Al-Zaabi, Mahmood Al-Oraimi, Wafa Al-Kiyumi, Ashwaq Al-Rawahi, Kifah Al-Tobi, Ali Amor Algheithy","doi":"10.2118/195077-MS","DOIUrl":"https://doi.org/10.2118/195077-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Water flood WF accounts for 40% of Petroleum Development Oman PDO's oil production and volumes. A proper WF management is a key to realize that. This project aims to standardize and simplify WF performance review process, which is very important part of WF management.\u0000 \u0000 \u0000 \u0000 The current condition of WF performance review vary from field to another in term of frequency of conducting the reviews i.e, once a year, quarterly which resulted in missing the opportunities to improve the WF performance on the right time.\u0000 Different in house tools and databases are used to prepare the technical materials for the review meeting. As a result, different fields have different way of presenting the technical materials to the reviewers across the company, so no standard pattern review template available and multiple sources for data are used. The field petroleum engineer takes up to 4 hours to prepare the technical material for one pattern review and usually senior or high skills PE requires generating different type of plots. When the Pattern review conducted almost 4 hours for the individual petroleum engineers spent during one pattern review.\u0000 The proposed counter measures for this project were to replace the review frequency to exception or requirement base to ensure no missed opportunities. As well as standardizing the technical materials for WF pattern review using a single tool/source. The standard template has to fit all patterns in a field. It has to be accessible, with good visualization, and secured storage\u0000 A Successful pilot run in one of the water flood fields in North Oman with 30+ WF patterns and has demonstrated the following results; standard review template developed within one source data platform. The pattern review was conducted on exceptional based which was a proactive approach. The PE team managed to generate extra optimization opportunities which resulted in proven an increased in oil production of +30 m3/d from 5 patterns. PE saved 3.5 hours/ pattern in preparation. The reviewers appreciated the improvement of quality of the technical materials, which create direct focus on issues identified based on exception. All the technical material were easy to generate by any less experience engineers.\u0000 To maintain sustainability of the achieved improvements, some lean tools have been used. These tools are summarized in the following points; Standard operating procedures (SOP); two SOPs were generated, one to set up the tool and the other to do the review.Visual management (VM); was also generated to keep track the pattern review and ensure healthy WFM and.Leader Standard Work (LSW); it was completed to ensure sustainability through leader ship support.\u0000","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79297205","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}
Low salinity water flooding (LSWF) as an enhanced oil recovery method (EOR) has attracted increased attention from oil companies due to its numerous benefits and advantages. It has been confirmed in several studies and laboratory experiments that LSWF has improved oil recovery. However, the underlying mechanism responsible for such an impact is still debatable. All previous studies focused on a geochemical process where fluid-fluid interaction has been overlooked. Recently, some studies have indicated that brine-crude oil (micro-dispersion) interactions play dominant roles in improved oil recovery in carbonate rocks. Nevertheless, at the moment, no commercial simulator can mimic this mechanism from the perspective of fluid interactions. In this work, we investigated whether micro-dispersion is applicable in commercial reservoir simulators through the history matching of two carbonate coreflood experiments. In this part of the investigation, three aspects will be addressed. (i) Develop a correlation of the link between the mechanism (micro-dispersion) in the lab and numerical simulation. (ii) Predict the low salinity relative permeability curves. (iii) History match the experimental data. This paper presents an integrated method of simulating low salinity water floods in carbonate rocks. Two different approaches have been applied to the history matching of unsteady state coreflood experiments. First, numerical simulation was performed to extract the high salinity relative permeability curves (KrHS) of the secondary mode for both experiments. Then, the findings from the first approach and the experimental results were used to develop a new approach for predicting the low salinity relative permeability (KrLS) curves. The new approach was not only used to predict KrLs curves through micro-dispersion but also used as input to history match the tertiary low salinity water floods. An excellent match was obtained using both the numerical simulation model and the new approach for the oil recovery and pressure drop profile, where two different relative permeability sets were generated in this study for each coreflood. The first observation promotes the premise that a history match of a coreflood can be obtained using different sets of relative permeability curves. In contrast, the Corey exponents, residual oil saturations and endpoints are essential parameters in the history matching of LSWF. The results obtained in this study will help to understand the modelling process involved during oil recovery by LSWF and introduce a new approach to model the effect of LSWF.
{"title":"A New Approach to Simulate Low Salinity Water Flooding in Carbonate Reservoir","authors":"Abdulla Aljaberi, M. Sohrabi","doi":"10.2118/195081-MS","DOIUrl":"https://doi.org/10.2118/195081-MS","url":null,"abstract":"\u0000 Low salinity water flooding (LSWF) as an enhanced oil recovery method (EOR) has attracted increased attention from oil companies due to its numerous benefits and advantages. It has been confirmed in several studies and laboratory experiments that LSWF has improved oil recovery. However, the underlying mechanism responsible for such an impact is still debatable. All previous studies focused on a geochemical process where fluid-fluid interaction has been overlooked. Recently, some studies have indicated that brine-crude oil (micro-dispersion) interactions play dominant roles in improved oil recovery in carbonate rocks. Nevertheless, at the moment, no commercial simulator can mimic this mechanism from the perspective of fluid interactions. In this work, we investigated whether micro-dispersion is applicable in commercial reservoir simulators through the history matching of two carbonate coreflood experiments. In this part of the investigation, three aspects will be addressed. (i) Develop a correlation of the link between the mechanism (micro-dispersion) in the lab and numerical simulation. (ii) Predict the low salinity relative permeability curves. (iii) History match the experimental data. This paper presents an integrated method of simulating low salinity water floods in carbonate rocks.\u0000 Two different approaches have been applied to the history matching of unsteady state coreflood experiments. First, numerical simulation was performed to extract the high salinity relative permeability curves (KrHS) of the secondary mode for both experiments. Then, the findings from the first approach and the experimental results were used to develop a new approach for predicting the low salinity relative permeability (KrLS) curves. The new approach was not only used to predict KrLs curves through micro-dispersion but also used as input to history match the tertiary low salinity water floods. An excellent match was obtained using both the numerical simulation model and the new approach for the oil recovery and pressure drop profile, where two different relative permeability sets were generated in this study for each coreflood. The first observation promotes the premise that a history match of a coreflood can be obtained using different sets of relative permeability curves. In contrast, the Corey exponents, residual oil saturations and endpoints are essential parameters in the history matching of LSWF. The results obtained in this study will help to understand the modelling process involved during oil recovery by LSWF and introduce a new approach to model the effect of LSWF.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85919618","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 development of CO2 separation technologies will enable the monetization of undeveloped gas fields with a high level of CO2, thus providing commercial enterprises a superior competitive edge for future international field acquisitions. The cryogenic distillation system has been identified as one of bulk CO2 separation technologies for high CO2 removal from natural gas. It is a more favourable CO2 separation technology than chemical or physical absorption due to its independence from absorbents, which require a greater footprint, weight and energy. It is targeted for bulk CO2 removal from the natural gas stream 80% down to 20%, and it must be efficient and cost-effective to ensure that the overall economics of a development are positive. In-house process simulation software was used to model a cryogenic distillation column system, while an experimentally validated thermodynamic model was used to verify the phase behaviour of the components, potential CO2 solidification and hydrate formation at the operating pressure and temperature conditions. This modelling encompassed critical operating conditions such as high operating pressure and low operating temperature. This is crucial especially at lower temperature and blowdown condition to prevent piping and equipment blockage which might lead to catastrophic equipment failure. A pilot scale cryogenic distillation unit was studied in this paper with pre-mixed feed consists of CO2 and natural gas to investigate separation performance as well as to examine the operational aspects of the technology. Efforts should be made to reduce energy consumption for such applications. In this paper, pinch analysis tool is utilized to analyse and optimized the Heat Exchanger Network (HEN) of the Cryogenic Distillation System for bulk CO2 separation. Column operating pressure, condenser and reboiler temperatures and feed conditions were varied to examine the effect on energy consumptions and for comparison with process simulation results. It was found that condenser duty decreased by 50% while reboiler duty increased by 100% when operating pressure was increased from 35 bar to 50 bar to achieve the same product specification. Substantial energy reduction for external cooling was attained through pinch technology by taking advantage of the Joule-Thomson effect when expanding high pressure liquid CO2 stream to a lower pressure. Optimal operating conditions, the effect of impurities and alternative refrigeration systems are identified as current gaps in this study. Operational issues were identified and mitigated in this study, which will further the understanding and scaling-up of commercial plants, particularly blowdown study and CO2 solid and hydrate formations and potential mitigations.
{"title":"Process Integration and Optimization of CO2 Removal from Natural Gas Using Cryogenic Distillation System","authors":"Amiza Surmi","doi":"10.2118/194937-MS","DOIUrl":"https://doi.org/10.2118/194937-MS","url":null,"abstract":"\u0000 The development of CO2 separation technologies will enable the monetization of undeveloped gas fields with a high level of CO2, thus providing commercial enterprises a superior competitive edge for future international field acquisitions. The cryogenic distillation system has been identified as one of bulk CO2 separation technologies for high CO2 removal from natural gas. It is a more favourable CO2 separation technology than chemical or physical absorption due to its independence from absorbents, which require a greater footprint, weight and energy. It is targeted for bulk CO2 removal from the natural gas stream 80% down to 20%, and it must be efficient and cost-effective to ensure that the overall economics of a development are positive.\u0000 In-house process simulation software was used to model a cryogenic distillation column system, while an experimentally validated thermodynamic model was used to verify the phase behaviour of the components, potential CO2 solidification and hydrate formation at the operating pressure and temperature conditions. This modelling encompassed critical operating conditions such as high operating pressure and low operating temperature. This is crucial especially at lower temperature and blowdown condition to prevent piping and equipment blockage which might lead to catastrophic equipment failure.\u0000 A pilot scale cryogenic distillation unit was studied in this paper with pre-mixed feed consists of CO2 and natural gas to investigate separation performance as well as to examine the operational aspects of the technology. Efforts should be made to reduce energy consumption for such applications. In this paper, pinch analysis tool is utilized to analyse and optimized the Heat Exchanger Network (HEN) of the Cryogenic Distillation System for bulk CO2 separation. Column operating pressure, condenser and reboiler temperatures and feed conditions were varied to examine the effect on energy consumptions and for comparison with process simulation results. It was found that condenser duty decreased by 50% while reboiler duty increased by 100% when operating pressure was increased from 35 bar to 50 bar to achieve the same product specification. Substantial energy reduction for external cooling was attained through pinch technology by taking advantage of the Joule-Thomson effect when expanding high pressure liquid CO2 stream to a lower pressure. Optimal operating conditions, the effect of impurities and alternative refrigeration systems are identified as current gaps in this study.\u0000 Operational issues were identified and mitigated in this study, which will further the understanding and scaling-up of commercial plants, particularly blowdown study and CO2 solid and hydrate formations and potential mitigations.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85436571","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}
Nahr Umr reservoirs in Bahrain Field consist of three reservoirs (Cab, Cc and Cd) that vary from calcareous silt stones to sand stones. They are the second major producing zones in Bahrain Field and are overlain by Mauddud limestone reservoir separated by 8 - 10' shale. All these reservoirs have been on production since early thirties and Mauddud reservoir has been under gas injection since 1938. These reservoirs with diverse fluid contents and hydro-dynamically different systems communicate with each other through the extensive faulting. Based on a dynamic model, it shows significant amount of flux already had transfered from the Mauddud reservoir to Cab due to gravity drainage gas injection project in the faulted crestal part of the Mauddud reservoir. Furthermore, the high recovery in Nahr Umr Cab reservoir indicates of acting as drainage point from Mauddud supported by the differential pressure in some areas. For such mature reservoirs with a long production history, identifying by-passed oil, underperforming areas, areas under communication, locating infill wells and upgrading the reserves are challenging tasks. This paper describes the application of a practical process (1) Development of a systematic workflow for production optimization and reservoir analysis; (2) Identifying and highlighting reservoir trends, patterns and anomalies; (3) Locating the under performing wells/areas, and recommend solutions (4) Identifying essential patterns for consideration in overall development plan. The challenge was to evaluate large data sets in a short time and cost-effective manner. The technique uses a streamlined workflow of reservoir assessment processes, which require data gathering, formatting and validation through combining the data with several processes associated with both the static and the dynamic model of the reservoir. Quick interpretations of these models generate opportunity regions, re-completion candidates, and new infill potential in the reservoir. Based on the processes run in the Nahr Umr zones it was possible to understand the reservoir performance and main issues associated with field development. Utilizing these techniques, the recently completed development drilling program was suitably adopted to realize an efficient reservoir management process for developing the field with the objectives of decreasing decline rate and increasing the recovery.
巴林油田的Nahr Umr储层包括三个储层(Cab、Cc和Cd)，从钙质粉砂岩到砂岩。它们是巴林油田的第二大产油区，上覆Mauddud灰岩储层，由8 - 10′页岩隔开。所有这些储层自30年代初以来一直在生产，Mauddud储层自1938年以来一直在注气。这些储层具有不同的流体含量和不同的水动力系统，通过广泛的断裂相互沟通。动态模型表明，由于在Mauddud储层断层顶部进行了重力抽采注气工程，已经从Mauddud储层向Cab输送了大量的通量。此外，Nahr Umr Cab储层的高采收率表明，在某些地区，它在压差的支持下充当了Mauddud的排水点。对于这些具有较长生产历史的成熟油藏来说，识别旁路油、欠发达区、连通区、定位填充井和提升储量是一项具有挑战性的任务。本文介绍了一个实际应用过程(1)开发了一个系统的生产优化和储层分析工作流程;(2)识别和突出储层趋势、模式和异常;(3)找出表现不佳的井/区域，并提出解决方案。(4)确定总体开发计划中考虑的基本模式。挑战在于如何在短时间内以具有成本效益的方式评估大型数据集。该技术使用了一个简化的油藏评估流程，该流程需要通过将数据与与油藏静态和动态模型相关的几个过程相结合来收集、格式化和验证数据。对这些模型的快速解释可以生成机会区域、重新完井候选区域以及储层中的新填充潜力。基于在Nahr Umr区域运行的过程，可以了解储层的动态以及与油田开发相关的主要问题。利用这些技术，适当地采用了最近完成的开发钻井方案，以实现有效的油藏管理过程，以开发油田，降低递减率，提高采收率。
{"title":"Reservoir Optimization and Monitoring Challenges in Nahr Umr Reservoirs of Bahrain Field","authors":"A. Al-Muftah, M. Hameed, M. Mansoor","doi":"10.2118/194814-MS","DOIUrl":"https://doi.org/10.2118/194814-MS","url":null,"abstract":"\u0000 Nahr Umr reservoirs in Bahrain Field consist of three reservoirs (Cab, Cc and Cd) that vary from calcareous silt stones to sand stones. They are the second major producing zones in Bahrain Field and are overlain by Mauddud limestone reservoir separated by 8 - 10' shale. All these reservoirs have been on production since early thirties and Mauddud reservoir has been under gas injection since 1938. These reservoirs with diverse fluid contents and hydro-dynamically different systems communicate with each other through the extensive faulting. Based on a dynamic model, it shows significant amount of flux already had transfered from the Mauddud reservoir to Cab due to gravity drainage gas injection project in the faulted crestal part of the Mauddud reservoir. Furthermore, the high recovery in Nahr Umr Cab reservoir indicates of acting as drainage point from Mauddud supported by the differential pressure in some areas. For such mature reservoirs with a long production history, identifying by-passed oil, underperforming areas, areas under communication, locating infill wells and upgrading the reserves are challenging tasks.\u0000 This paper describes the application of a practical process (1) Development of a systematic workflow for production optimization and reservoir analysis; (2) Identifying and highlighting reservoir trends, patterns and anomalies; (3) Locating the under performing wells/areas, and recommend solutions (4) Identifying essential patterns for consideration in overall development plan. The challenge was to evaluate large data sets in a short time and cost-effective manner.\u0000 The technique uses a streamlined workflow of reservoir assessment processes, which require data gathering, formatting and validation through combining the data with several processes associated with both the static and the dynamic model of the reservoir. Quick interpretations of these models generate opportunity regions, re-completion candidates, and new infill potential in the reservoir. Based on the processes run in the Nahr Umr zones it was possible to understand the reservoir performance and main issues associated with field development. Utilizing these techniques, the recently completed development drilling program was suitably adopted to realize an efficient reservoir management process for developing the field with the objectives of decreasing decline rate and increasing the recovery.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80373759","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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