A. Cadix, S. Meeker, Swati Kaushik, Elodie Haumesser, G. Ovarlez
Fluid loss control additives are critical constituents in a cement slurry formulation to ensure even cement placement and ultimately satisfactory zonal isolation. Many technological options have been developed over the past decades to design fluid loss control additives for cementing. The most popular technologies as of today are either based on water soluble polymers or colloidal particles like latexes. As an alternative approach, in this paper we introduce a new technology based on associative or "sticky" microgels. These microgels are able to associate with one another at elevated concentration but, more surprisingly, are also able to associate under shear in the dilute regime during a filtration process. As a consequence these additives demonstrate outstanding performance as fluid loss control agents. This study focuses first on standard API filtration tests using sticky microgels, and on how their behavior in application differs from traditional systems, in particular water-based soluble polymers such as cellulosic derivatives or synthetic polymers. Our investigations then focus on the working mechanism of the microgel system by analyzing adsorption on the cement surface, rheology, and filter cake structure using Mercury Intrusion Porosimetry (MIP). Finally the behavior of sticky microgels in model filtration tests is explored with either filtration against porous ceramic discs or using microfluidic chips allowing a direct visualization of microgels during filtration. This study demonstrates that associative microgels are not controlling fluid loss through a simple size match between particles and pores within the filter cake but rather through shear-induced aggregation. Microfluidic observations reveal that aggregation occurs irreversibly as microgels are forced through the pores as the filtration process occurs. The shear-induced associated gels are particularly effective at reducing dramatically the filter cake permeability and allowing gas migration control. Interestingly the shear-induced aggregation of associative μgels seems to confer self-adaptive properties of the fluid loss additives with respect to the pore network to be clogged. Indeed, formation of shear aggregated gels larger than the individual microgels can be used to limit fluid loss even if the pore sizes are much larger than the individual microgels.
{"title":"Associative Microgels, New Self Adaptive Systems to Control Fluid Loss in Well Cementing","authors":"A. Cadix, S. Meeker, Swati Kaushik, Elodie Haumesser, G. Ovarlez","doi":"10.2118/207472-ms","DOIUrl":"https://doi.org/10.2118/207472-ms","url":null,"abstract":"\u0000 Fluid loss control additives are critical constituents in a cement slurry formulation to ensure even cement placement and ultimately satisfactory zonal isolation. Many technological options have been developed over the past decades to design fluid loss control additives for cementing. The most popular technologies as of today are either based on water soluble polymers or colloidal particles like latexes. As an alternative approach, in this paper we introduce a new technology based on associative or \"sticky\" microgels. These microgels are able to associate with one another at elevated concentration but, more surprisingly, are also able to associate under shear in the dilute regime during a filtration process. As a consequence these additives demonstrate outstanding performance as fluid loss control agents.\u0000 This study focuses first on standard API filtration tests using sticky microgels, and on how their behavior in application differs from traditional systems, in particular water-based soluble polymers such as cellulosic derivatives or synthetic polymers. Our investigations then focus on the working mechanism of the microgel system by analyzing adsorption on the cement surface, rheology, and filter cake structure using Mercury Intrusion Porosimetry (MIP). Finally the behavior of sticky microgels in model filtration tests is explored with either filtration against porous ceramic discs or using microfluidic chips allowing a direct visualization of microgels during filtration.\u0000 This study demonstrates that associative microgels are not controlling fluid loss through a simple size match between particles and pores within the filter cake but rather through shear-induced aggregation. Microfluidic observations reveal that aggregation occurs irreversibly as microgels are forced through the pores as the filtration process occurs. The shear-induced associated gels are particularly effective at reducing dramatically the filter cake permeability and allowing gas migration control. Interestingly the shear-induced aggregation of associative μgels seems to confer self-adaptive properties of the fluid loss additives with respect to the pore network to be clogged. Indeed, formation of shear aggregated gels larger than the individual microgels can be used to limit fluid loss even if the pore sizes are much larger than the individual microgels.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90294727","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 demonstrates the Saudi Aramco Khurais Facility (KhPD) successful commissioning of the A Fully Integrated Pipelines Management System, in an effort to enhance its environmental emission performance. The project team conducted an assessment conceptually right from the beginning, to ensure that the value creations from this initiative can be realized, and the project remain cost effective and safely executed while meeting environmental objectives. Following successful deployment, the Khurais team carried out post installation performance assessment to ensure the outcomes and objectives from this project has been impacted positively. This paper covers the fully implemented solution to manage pipelines assets and enchantments followed by Saudi Aramco Khurais producing facility (KhCPF) Objectives: Share how a corrosion challenge of multi-phase flow within pipelines led to installation of a comprehensive solution to Pipeline Management Systems (common header connects all compressors) and how it was resolved through integration between two different systems. In addition, highlight how this approach enhanced the pipelines reliability, safety and most important the big environmental impact that helped Saudi Aramco to reduce its carbon footprint.
{"title":"An Innovative IR 4.0 Solution Against Leaks Utilizing a Fully Integrated Pipelines Management System","authors":"Abdulkarim F. Wathnani, Badr Hussain","doi":"10.2118/207997-ms","DOIUrl":"https://doi.org/10.2118/207997-ms","url":null,"abstract":"\u0000 This paper demonstrates the Saudi Aramco Khurais Facility (KhPD) successful commissioning of the A Fully Integrated Pipelines Management System, in an effort to enhance its environmental emission performance. The project team conducted an assessment conceptually right from the beginning, to ensure that the value creations from this initiative can be realized, and the project remain cost effective and safely executed while meeting environmental objectives. Following successful deployment, the Khurais team carried out post installation performance assessment to ensure the outcomes and objectives from this project has been impacted positively. This paper covers the fully implemented solution to manage pipelines assets and enchantments followed by Saudi Aramco Khurais producing facility (KhCPF) Objectives: Share how a corrosion challenge of multi-phase flow within pipelines led to installation of a comprehensive solution to Pipeline Management Systems (common header connects all compressors) and how it was resolved through integration between two different systems. In addition, highlight how this approach enhanced the pipelines reliability, safety and most important the big environmental impact that helped Saudi Aramco to reduce its carbon footprint.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78693994","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}
John Lovell, Dalia Abdallah, R. Fonseca, M. Grutters, Sameer Punnapala, Omar Kulbrandstad, D. Meza, Jorge Baez
Asphaltene deposition presents a significant flow assurance to oil production in many parts of the Middle East and beyond. Until recently, there had been no intervention-free approach to monitor deposition in the asphaltene affected wells. This prompted ADNOC to sponsor MicroSilicon to develop of an intervention less real-time sensor device to monitor asphaltene deposition. This new state-of-the-art device is currently installed and automatically collecting data at the wellhead and nearby facilities of an ADNOC operated field. Historic ways of measuring asphaltene in oil relied upon laboratory processes that extracted the asphaltene using a combination of solvents and gravimetric techniques. Paramagnetic techniques offer a potentially simpler alternative because it is known that the spins per gram of an oil is a constant property of that oil, at least when the oil is at constant temperature and pressure. Taking the device to the field means that any interpretation needs to be made independent of these properties. Additionally, the fluid entering the sensor is multiphase and subject to varying temperature and pressure which raises challenges for the conversion of raw spectroscopic data into asphaltene quantity and particle size. These challenges were addressed with a combination of hardware, software and cloud-based machine learning technologies. Oil from over two dozen wells has been sampled in real-time and confirmed that the asphaltene percentage does not just vary from well to well but is also a dynamic aspect of production, with some wells having relatively constant levels and others showing consistent variation. One other well was placed on continuous observation and showed a decrease in asphaltene level following a choke change at the surface. Diagnostic data enhanced by machine learning complements the asphaltene measurement and provides a much more complete picture of the flow assurance challenge than had been previously been available.
{"title":"Interpretation Challenges and Solutions for Real-Time Asphaltene Paramagnetic Sensing at the Wellhead","authors":"John Lovell, Dalia Abdallah, R. Fonseca, M. Grutters, Sameer Punnapala, Omar Kulbrandstad, D. Meza, Jorge Baez","doi":"10.2118/207553-ms","DOIUrl":"https://doi.org/10.2118/207553-ms","url":null,"abstract":"\u0000 Asphaltene deposition presents a significant flow assurance to oil production in many parts of the Middle East and beyond. Until recently, there had been no intervention-free approach to monitor deposition in the asphaltene affected wells. This prompted ADNOC to sponsor MicroSilicon to develop of an intervention less real-time sensor device to monitor asphaltene deposition. This new state-of-the-art device is currently installed and automatically collecting data at the wellhead and nearby facilities of an ADNOC operated field.\u0000 Historic ways of measuring asphaltene in oil relied upon laboratory processes that extracted the asphaltene using a combination of solvents and gravimetric techniques. Paramagnetic techniques offer a potentially simpler alternative because it is known that the spins per gram of an oil is a constant property of that oil, at least when the oil is at constant temperature and pressure. Taking the device to the field means that any interpretation needs to be made independent of these properties. Additionally, the fluid entering the sensor is multiphase and subject to varying temperature and pressure which raises challenges for the conversion of raw spectroscopic data into asphaltene quantity and particle size. These challenges were addressed with a combination of hardware, software and cloud-based machine learning technologies.\u0000 Oil from over two dozen wells has been sampled in real-time and confirmed that the asphaltene percentage does not just vary from well to well but is also a dynamic aspect of production, with some wells having relatively constant levels and others showing consistent variation. One other well was placed on continuous observation and showed a decrease in asphaltene level following a choke change at the surface. Diagnostic data enhanced by machine learning complements the asphaltene measurement and provides a much more complete picture of the flow assurance challenge than had been previously been available.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86924538","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}
Mohammed Amr Aly, P. Anastasi, G. Fighera, Ernesto Della Rossa
Ensemble approaches are increasingly used for history matching also with large scale models. However, the iterative nature and the high computational resources required, demands careful and consistent parameterization of the initial ensemble of models, to avoid repeated and time-consuming attempts before an acceptable match is achieved. The objective of this work is to introduce ensemble-based data analytic techniques to validate the starting ensemble and early identify potential parameterization problems, with significant time saving. These techniques are based on the same definition of the mismatch between the initial ensemble simulation results and the historical data used by ensemble algorithms. In fact, a notion of distance among ensemble realizations can be introduced using the mismatch, opening the possibility to use statistical analytic techniques like Multi-Dimensional Scaling and Generalized Sensitivity. In this way a clear and immediate view of ensemble behavior can be quickly explored. Combining these views with advanced correlation analysis, a fast assessment of ensemble consistency with observed data and physical understanding of the reservoir is then possible. The application of the proposed methodology to real cases of ensemble history matching studies, shows that the approach is very effective in identifying if a specific initial ensemble has an adequate parameterization to start a successful computational loop of data assimilation. Insufficient variability, due to a poor capturing of the reservoir performance, can be investigated both at field and well scales by data analytics computations. The information contained in ensemble mismatches of relevant quantities like water-breakthrough and Gas-Oil-ratio is then evaluated in a systematic way. The analysis often reveals where and which uncertainties have not enough variability to explain historical data. It also allows to detect what is the role of apparently inconsistent parameters. In principle it is possible to activate the heavy iterative computation also with an initial ensemble where the analytics tools show potential difficulties and problems. However, experiences with large scale models point out that the possibility to obtain a good match in these situations is very low, leading to a time-consuming revision of the entire process. On the contrary, if the ensemble is validated, the iterative large-scale computations achieve a good calibration with a consistency that enables predictive ability. As a new interesting feature of the proposed methodology, ensemble advanced data analytics techniques are able to give clues and suggestions regarding which parameters could be source of potential history matching problems in advance. In this way it is possible anticipate directly on initial ensemble the uncertainties revision for example modifying ranges, introducing new parameters and better tuning other ensemble factors, like localization and observations tolerances that contro
{"title":"Ensemble Data Analytics Approaches for Fast Parametrization Screening and Validation","authors":"Mohammed Amr Aly, P. Anastasi, G. Fighera, Ernesto Della Rossa","doi":"10.2118/207215-ms","DOIUrl":"https://doi.org/10.2118/207215-ms","url":null,"abstract":"\u0000 Ensemble approaches are increasingly used for history matching also with large scale models. However, the iterative nature and the high computational resources required, demands careful and consistent parameterization of the initial ensemble of models, to avoid repeated and time-consuming attempts before an acceptable match is achieved. The objective of this work is to introduce ensemble-based data analytic techniques to validate the starting ensemble and early identify potential parameterization problems, with significant time saving.\u0000 These techniques are based on the same definition of the mismatch between the initial ensemble simulation results and the historical data used by ensemble algorithms. In fact, a notion of distance among ensemble realizations can be introduced using the mismatch, opening the possibility to use statistical analytic techniques like Multi-Dimensional Scaling and Generalized Sensitivity. In this way a clear and immediate view of ensemble behavior can be quickly explored. Combining these views with advanced correlation analysis, a fast assessment of ensemble consistency with observed data and physical understanding of the reservoir is then possible.\u0000 The application of the proposed methodology to real cases of ensemble history matching studies, shows that the approach is very effective in identifying if a specific initial ensemble has an adequate parameterization to start a successful computational loop of data assimilation. Insufficient variability, due to a poor capturing of the reservoir performance, can be investigated both at field and well scales by data analytics computations. The information contained in ensemble mismatches of relevant quantities like water-breakthrough and Gas-Oil-ratio is then evaluated in a systematic way. The analysis often reveals where and which uncertainties have not enough variability to explain historical data. It also allows to detect what is the role of apparently inconsistent parameters. In principle it is possible to activate the heavy iterative computation also with an initial ensemble where the analytics tools show potential difficulties and problems. However, experiences with large scale models point out that the possibility to obtain a good match in these situations is very low, leading to a time-consuming revision of the entire process. On the contrary, if the ensemble is validated, the iterative large-scale computations achieve a good calibration with a consistency that enables predictive ability.\u0000 As a new interesting feature of the proposed methodology, ensemble advanced data analytics techniques are able to give clues and suggestions regarding which parameters could be source of potential history matching problems in advance. In this way it is possible anticipate directly on initial ensemble the uncertainties revision for example modifying ranges, introducing new parameters and better tuning other ensemble factors, like localization and observations tolerances that contro","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87408258","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}
M. Grutters, Sameer Punnapala, Dalia Abdallah, Z. Cristea, Hossam El Din Mohamed El Nagger, Sivashankar Anbumani, Rabah Sennad, Hasan Jamil Bakri
Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up. Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string. The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.
{"title":"Asphaltene Mitigation in Giant Carbonate Abu Dhabi Fields: A Techno-Economic Comparison Between Continuous Injection and Formation Squeeze","authors":"M. Grutters, Sameer Punnapala, Dalia Abdallah, Z. Cristea, Hossam El Din Mohamed El Nagger, Sivashankar Anbumani, Rabah Sennad, Hasan Jamil Bakri","doi":"10.2118/207993-ms","DOIUrl":"https://doi.org/10.2118/207993-ms","url":null,"abstract":"\u0000 Asphaltene deposition is a serious and re-occurring flow assurance problem in several of the ADNOC onshore oilfields. Fluids are intrinsically unstable with respect to asphaltene precipitation, and operating conditions are such that severe deposition occurs in the wellbore. Wells in ADNOC are generally not equipped with downhole chemical injection lines for continuous inhibition, and protection of the wells require frequent shut-in and intervention by wireline and coiled tubing to inspect and clean up.\u0000 Since some of the mature fields are under EOR recovery strategies, like miscible hydrocarbon WAG and CO2 flood, which exacerbates the asphaltene precipitation and deposition problems, a more robust mitigation strategy is required. In this paper the results of two different mitigation strategies will be discussed; continuous injection of asphaltene inhibitor via a capillary line in the tubular and asphaltene inhibitor formation squeeze. Three asphaltene inhibitors from different suppliers were pre-qualified and selected for field trial. Each inhibitor was selected for a formation squeeze in both one horizontal and one vertical well, and one of the inhibitors was applied via thru-tubing capillary string.\u0000 The field trials showed that continuous injection in remote wells with no real-time surveillance options (e.g. gauges, flow meters) is technically challenging. The continuous injection trial via the capillary string was stopped due to technical challenges. From the six formation squeezes four were confirmed to be effective. Three out of fours squeezes significantly extended the production cycle, from approximately 1.4 to 6 times the normal uninhibited flow period. The most successful squeezes were in the vertical wells. The results of the trial were used to model the economic benefit of formation squeeze, compared to a ‘do-nothing’ approach where the wells are subject to shut-in and cleanup once the production rates drop below a threshold value. The model clearly indicates that the squeezes applied in ADNOC Onshore are only cost-effective if it extends the normal flow period by approximately three times. However, a net gain can be achieved already if the formation squeeze extends the flow cycle by 15 to 20%, due to reduction of shut-in days required for intervention. Therefore, the results in this paper illustrate that an asphaltene inhibitor formation squeeze can be an attractive mitigation strategy, both technically and economically.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82640605","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}
H. Sheibani, R. Wulandari, Roeland van Gilst, Hawraa Al Lawati, Al Mutasem Abri, Humaid Maqbali, Fatma Zaabi
Recovery Factor Improvement (RFI) is a process to check the hydrocarbon production efficiency by incorporating the actual static and dynamic field data, as well as the way how the field being operated. This has been a common process within Shell's portfolio since 2018 (Ref; Muggeridge et al., 2013 & Smalley et al., 2009). The approach has been developed to stimulate the identification of new opportunities to increase the recovery from the existing fields and to aid the maturation of these opportunities into the Opportunity Realization Process. There are four (4) factors that affected overall reservoir recovery factor, they are: Pressure efficiency; related to which pressure can be reduced in the reservoir as dictated by the relevant facilities and wells.Drainage Efficiency; the proportion of the in-place hydrocarbon that is pressure-connected directly to at least one producing well on a production timescale.The "secondary pay" efficiency; takes into account the volumes of poorer quality rock in which the gas remains at pressure above the lowest pressure just outside the wellbore (Pf) when the reservoir is abandoned.Cut-off Efficiency; the proportion of hydrocarbon that is lost due to non-production of the tail.This approach was applied in the dry gas Natih Reservoir fields in the PDO concession area. Before the implementation of RFI, the average recovery factor for Natih was around 70%. This was considered low for a homogenous-dry gas reservoir. The targeted Natih fields were benchmarked against each other with a total of 11 fields with similar reservoir properties. Post the benchmarking exercise, the expected field recovery factor is approximately ~90-93%. The team managed to map out the opportunities to achieve the targeted RF and identified the road map activities. The activities are mainly related to: production optimization: retubing, re-stimulation reduce drainage: infill drilling, horizontal well reduce the field intake through compression The outcome of the mapping was then further analyzed through integrated framework to be matured as a firm-project. The new proposed activities are expected to add around 9% additional recovery to the existing fields. There will be a remaining activities which will be studied in the future, example infill wells and intelligent completions. These will close the gap to TQ and add other addition RF of 11-13%. As conclusion, the RFI was seen as a structured approach to better understanding the field recovery factor based on the integrated surface and subsurface data with a robust analysis to trigger opportunity identification linked to RFI elements. It is similar concept as sweating the asset by generating limit diagram for each recovery mechanism & the road map to achieve the maximum limit. This paper will highlight the Natih Fields RFI analysis, highlighting the key learning and challenges.
采收率提高(RFI)是通过结合实际的静态和动态油田数据以及油田的操作方式来检查油气生产效率的过程。自2018年以来，这一直是壳牌投资组合中的一个常见过程。Muggeridge et al.， 2013; Smalley et al.， 2009)。开发该方法的目的是促进对新机会的识别，以提高现有油田的采收率，并帮助这些机会的成熟进入机会实现过程。影响整体油藏采收率的因素有4个，分别是:压力效率;与此相关的压力可以根据相关设施和井的要求降低。排水效率;在一个生产时间尺度上，与至少一口生产井直接压力连接的原位烃的比例。“二次支付”效率;考虑到当放弃储层时，气体保持在高于井外最低压力(Pf)的质量较差岩石的体积。截止效率;由于尾部不生产而损失的碳氢化合物的比例。该方法应用于PDO特许区的Natih干气储层。在实施RFI之前，Natih的平均采收率约为70%。对于均质干气储层来说，这被认为是较低的。目标Natih油田与11个具有相似储层性质的油田进行了基准测试。在进行基准测试后，预期的采收率约为90-93%。该小组设法规划出实现目标射频的机会，并确定了路线图活动。这些活动主要涉及:优化产量、换油管、再增产、减少排水、填充钻井、水平井、通过压缩减少油田进水量。然后，通过综合框架进一步分析绘制结果，使其成为一个成熟的公司项目。新的活动预计将使现有油田的采收率增加约9%。还有一些活动将在未来进行研究，例如填充井和智能完井。这些将缩小与TQ的差距，并增加11-13%的其他附加RF。综上所述，RFI被视为一种结构化的方法，可以更好地理解基于地面和地下综合数据的油田采收率，并通过强大的分析来触发与RFI元素相关的机会识别。这类似于通过为每个恢复机制生成极限图和实现最大极限的路线图来使资产出汗的概念。本文将重点介绍Natih Fields的RFI分析，重点介绍关键的学习和挑战。
{"title":"Recovery Factor Improvement; A Success Story of Improving 10% of RF in Greater Natih Reservoirs, North of Oman","authors":"H. Sheibani, R. Wulandari, Roeland van Gilst, Hawraa Al Lawati, Al Mutasem Abri, Humaid Maqbali, Fatma Zaabi","doi":"10.2118/208071-ms","DOIUrl":"https://doi.org/10.2118/208071-ms","url":null,"abstract":"\u0000 Recovery Factor Improvement (RFI) is a process to check the hydrocarbon production efficiency by incorporating the actual static and dynamic field data, as well as the way how the field being operated. This has been a common process within Shell's portfolio since 2018 (Ref; Muggeridge et al., 2013 & Smalley et al., 2009). The approach has been developed to stimulate the identification of new opportunities to increase the recovery from the existing fields and to aid the maturation of these opportunities into the Opportunity Realization Process.\u0000 There are four (4) factors that affected overall reservoir recovery factor, they are: Pressure efficiency; related to which pressure can be reduced in the reservoir as dictated by the relevant facilities and wells.Drainage Efficiency; the proportion of the in-place hydrocarbon that is pressure-connected directly to at least one producing well on a production timescale.The \"secondary pay\" efficiency; takes into account the volumes of poorer quality rock in which the gas remains at pressure above the lowest pressure just outside the wellbore (Pf) when the reservoir is abandoned.Cut-off Efficiency; the proportion of hydrocarbon that is lost due to non-production of the tail.This approach was applied in the dry gas Natih Reservoir fields in the PDO concession area. Before the implementation of RFI, the average recovery factor for Natih was around 70%. This was considered low for a homogenous-dry gas reservoir. The targeted Natih fields were benchmarked against each other with a total of 11 fields with similar reservoir properties. Post the benchmarking exercise, the expected field recovery factor is approximately ~90-93%. The team managed to map out the opportunities to achieve the targeted RF and identified the road map activities. The activities are mainly related to: production optimization: retubing, re-stimulation reduce drainage: infill drilling, horizontal well reduce the field intake through compression\u0000 The outcome of the mapping was then further analyzed through integrated framework to be matured as a firm-project. The new proposed activities are expected to add around 9% additional recovery to the existing fields. There will be a remaining activities which will be studied in the future, example infill wells and intelligent completions. These will close the gap to TQ and add other addition RF of 11-13%.\u0000 As conclusion, the RFI was seen as a structured approach to better understanding the field recovery factor based on the integrated surface and subsurface data with a robust analysis to trigger opportunity identification linked to RFI elements. It is similar concept as sweating the asset by generating limit diagram for each recovery mechanism & the road map to achieve the maximum limit. This paper will highlight the Natih Fields RFI analysis, highlighting the key learning and challenges.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83289891","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 challenging times of 2020 and inconsistency with the background of a low-oil-price environment, innovative ideas needed to give a second life to all available resources such as unconventional, shallow, depleted, mature, heavy oil and by bypassed oil with a cost-effective manner (usually innovation created to fit needs). U-shaped well a combined with pigging lifting (conceptual study for new artificial lift method) is one of the selected scenarios studied under the objective of innovative, low-cost techniques to overcome many projects challenges. U shaped well accompanied with a new pigging artificial lift method are new concept studied in this lab work. Conceptual model presents many benefits of this new application such as solving most of the current wells and production challenges. The study reflects more well control with two paths, better well stimulation, low fracturing pressure and double rates, inject and lift chemical for clean without intervention, double well life "additional strings", new recompletions without rig, two horizontal side used for production or injection, step change for reservoir monitoring, improving artificial lift performance and allow creating Pigging lift "New artificial lift concept". U shaped well accompanied with a new pigging artificial lift method study shows the following progress: 1. Additional down hole barrier from the deepest point and additional open side keep the well under control more over minimize the existing well control killing procedures with low cost and risk in addition to discarding the CT operations for killing or prepare the well for W/O. 2. Decreasing stimulation pressures needs (double injection rates) and overcome the existing accessibility challenges 3. Allowing pull heading stimulation w/less displacement time and high rate and chimerical batch pumping from one side to another increase well life and eliminate PKRs risk as chimerical batches will be pigger, easier and faster. 4. Additional down hole monitoring system allowing uniform stimulation and discarding the CT operations for well stimulation and cleaning, 5. Avoiding post stimulation damage throughout fast clean-up 6. Ability to stimulate from one side with artificial lift from other side Avoiding the corrosion and erosion by faster operations 7. Allow faster plug and perf. multistage fracturing technology and overcome the unconventional well fracturing which required rate and pressure 8. Eliminate rig usage to pull the frac string to run completions 9. Step change for reservoir mentoring without S/D and real-time Logging, Sampling The deployment of U Shaped Well allows new artificial lift concept (Pigging lift) to apply. This new approach led to improved wells performance also raising efficiency of the use of the existing resources besides saving time and in return cost. This approach helps in improving well utilization and efficiency levels.
{"title":"Modern Drilling and Completion in Contradiction of New Artificial Lift Method Concept","authors":"G. Hegazy","doi":"10.2118/207258-ms","DOIUrl":"https://doi.org/10.2118/207258-ms","url":null,"abstract":"\u0000 In challenging times of 2020 and inconsistency with the background of a low-oil-price environment, innovative ideas needed to give a second life to all available resources such as unconventional, shallow, depleted, mature, heavy oil and by bypassed oil with a cost-effective manner (usually innovation created to fit needs). U-shaped well a combined with pigging lifting (conceptual study for new artificial lift method) is one of the selected scenarios studied under the objective of innovative, low-cost techniques to overcome many projects challenges.\u0000 U shaped well accompanied with a new pigging artificial lift method are new concept studied in this lab work. Conceptual model presents many benefits of this new application such as solving most of the current wells and production challenges. The study reflects more well control with two paths, better well stimulation, low fracturing pressure and double rates, inject and lift chemical for clean without intervention, double well life \"additional strings\", new recompletions without rig, two horizontal side used for production or injection, step change for reservoir monitoring, improving artificial lift performance and allow creating Pigging lift \"New artificial lift concept\".\u0000 U shaped well accompanied with a new pigging artificial lift method study shows the following progress: 1. Additional down hole barrier from the deepest point and additional open side keep the well under control more over minimize the existing well control killing procedures with low cost and risk in addition to discarding the CT operations for killing or prepare the well for W/O. 2. Decreasing stimulation pressures needs (double injection rates) and overcome the existing accessibility challenges 3. Allowing pull heading stimulation w/less displacement time and high rate and chimerical batch pumping from one side to another increase well life and eliminate PKRs risk as chimerical batches will be pigger, easier and faster. 4. Additional down hole monitoring system allowing uniform stimulation and discarding the CT operations for well stimulation and cleaning, 5. Avoiding post stimulation damage throughout fast clean-up 6. Ability to stimulate from one side with artificial lift from other side Avoiding the corrosion and erosion by faster operations 7. Allow faster plug and perf. multistage fracturing technology and overcome the unconventional well fracturing which required rate and pressure 8. Eliminate rig usage to pull the frac string to run completions 9. Step change for reservoir mentoring without S/D and real-time Logging, Sampling\u0000 The deployment of U Shaped Well allows new artificial lift concept (Pigging lift) to apply. This new approach led to improved wells performance also raising efficiency of the use of the existing resources besides saving time and in return cost. This approach helps in improving well utilization and efficiency levels.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91528853","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 covers practical demulsifer and wash water approach followed by Saudi Aramco Khurais producing facility to optimize the chemical and water consumption. This Paper is intended to: Share practical demulsifer and wash water optimization approach. Highlight how this approach enhanced the separation process and how it already helped Saudi Aramco to meet the product quality with minimal operating costs by optimizing operating parameters in the field. The basic idea of the optimization is to relax the oil - emulsified water separation in HPPT by allowing water carry over to the downstream equipment and vessels through minimizing the demulsifer dosage on the production header to increase the retention time. The optimization process includes manipulating different key parameters (controlled variables) which are demulsifer dosing rate (on production header and dehydrator), wash water dosing rate, de-salting train mixing valves differential pressure and transformers voltage with continues monitoring and corrective actions based on the export specification of BS&W and salts within pre-defined internal limits to avoid having off-spec product (Trial and Error) This approach resulted in decreasing the operating costs by reducing overall demulsifer dosage by 50%, and allowing the overall separation efficiency to be increased contributing towards enhanced separation. Various graphs included showing the full impact of optimizing the operating parameters on improved separation in dehydrator. From the water conservation, this process resulted in reducing non-potable wash water consumption for crude washing purposes by more than 20,000 gallon/day without compromising the crude specification. This optimization resulted in cost saving equivalent to around US$ 650,000 due to significant demulsifer reduction. Sustaining such an optimum performance proves to be a challenge and in this regard, the team is focusing heavily on the monitoring efforts that are equipped with the advisory features on what to do should the deviation exist from the stipulated target. This includes, among others, the alerting feature for immediate corrective actions by the team. Overall, this initiative succeeded in maintaining the facility crude quality specifications of BS&W and salts while reducing chemical operating costs, creating positive environmental impacts by saving non-potable wash water while increasing the assets utilization and reliability effectively.
{"title":"Practical Wash Water & Demulsifer Optimization at Khurais Crude Processing Facility","authors":"H. A. Bajuaifer, M. A. Malki, K. Amminudin","doi":"10.2118/208215-ms","DOIUrl":"https://doi.org/10.2118/208215-ms","url":null,"abstract":"\u0000 This paper covers practical demulsifer and wash water approach followed by Saudi Aramco Khurais producing facility to optimize the chemical and water consumption.\u0000 This Paper is intended to:\u0000 Share practical demulsifer and wash water optimization approach. Highlight how this approach enhanced the separation process and how it already helped Saudi Aramco to meet the product quality with minimal operating costs by optimizing operating parameters in the field.\u0000 The basic idea of the optimization is to relax the oil - emulsified water separation in HPPT by allowing water carry over to the downstream equipment and vessels through minimizing the demulsifer dosage on the production header to increase the retention time. The optimization process includes manipulating different key parameters (controlled variables) which are demulsifer dosing rate (on production header and dehydrator), wash water dosing rate, de-salting train mixing valves differential pressure and transformers voltage with continues monitoring and corrective actions based on the export specification of BS&W and salts within pre-defined internal limits to avoid having off-spec product (Trial and Error)\u0000 This approach resulted in decreasing the operating costs by reducing overall demulsifer dosage by 50%, and allowing the overall separation efficiency to be increased contributing towards enhanced separation. Various graphs included showing the full impact of optimizing the operating parameters on improved separation in dehydrator. From the water conservation, this process resulted in reducing non-potable wash water consumption for crude washing purposes by more than 20,000 gallon/day without compromising the crude specification. This optimization resulted in cost saving equivalent to around US$ 650,000 due to significant demulsifer reduction.\u0000 Sustaining such an optimum performance proves to be a challenge and in this regard, the team is focusing heavily on the monitoring efforts that are equipped with the advisory features on what to do should the deviation exist from the stipulated target. This includes, among others, the alerting feature for immediate corrective actions by the team. Overall, this initiative succeeded in maintaining the facility crude quality specifications of BS&W and salts while reducing chemical operating costs, creating positive environmental impacts by saving non-potable wash water while increasing the assets utilization and reliability effectively.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89244780","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}
A. Aslanyan, Arkady Popov, Rustem Asmandiyarov, A. Margarit
The paper shares a 4-years’ experience of "Gazprom Neft" PJSC on Digital Twin Learning Program in training of holistic multidisciplinary petroleum asset management and engineering based on the on-line cloud PetroCup software facility. The objective of the program was to train and test large amounts of managers and engineers with minimum off-work time and motivate self-improvement among the employee. The program includes warm-up videos, immersive master-classes, training courses, discussion clubs and Annual Corporate Championship, with a strong focus on home learning, remote communication, simulation-based exercises and automated testing/certification. The program is divided into Master Development Planning (MDP) and Well & Reservoir Management (WRM) domains which are related to different stages of the petroleum asset lifecycle. The interaction with simulator takes 2-3 days for WRM and 5 days for MDP and engages a multidisciplinary team: asset manager, economist, contract engineer, surface facility engineer, reservoir engineer, geologist, petrophysicist, simulation engineer, well test engineer, well and log analyst and production technologist. The session starts by reading the existing field data and its history and then perform well drilling, completions, workovers, well tests, open-hole and cased-hole logging, manage production and injection targets, build/modify the surface production/injection facilities and receive the fully automated asset response in the form of the field reports, very much in the same way as in real life. Once session is over the simulator generates a detailed debriefing report on team performance in numerous areas: economical, production, injection, reservoir and well performance so that team can understand where it did a good job and where it was not efficient. The current paper shows how this facility has been integrated into the corporate staff capability program, expanded to anchor universities and shed the light to the future perspectives.
{"title":"Gamification in Training of Holistic Multidisciplinary Petroleum Asset Management","authors":"A. Aslanyan, Arkady Popov, Rustem Asmandiyarov, A. Margarit","doi":"10.2118/208001-ms","DOIUrl":"https://doi.org/10.2118/208001-ms","url":null,"abstract":"\u0000 The paper shares a 4-years’ experience of \"Gazprom Neft\" PJSC on Digital Twin Learning Program in training of holistic multidisciplinary petroleum asset management and engineering based on the on-line cloud PetroCup software facility.\u0000 The objective of the program was to train and test large amounts of managers and engineers with minimum off-work time and motivate self-improvement among the employee.\u0000 The program includes warm-up videos, immersive master-classes, training courses, discussion clubs and Annual Corporate Championship, with a strong focus on home learning, remote communication, simulation-based exercises and automated testing/certification.\u0000 The program is divided into Master Development Planning (MDP) and Well & Reservoir Management (WRM) domains which are related to different stages of the petroleum asset lifecycle.\u0000 The interaction with simulator takes 2-3 days for WRM and 5 days for MDP and engages a multidisciplinary team: asset manager, economist, contract engineer, surface facility engineer, reservoir engineer, geologist, petrophysicist, simulation engineer, well test engineer, well and log analyst and production technologist.\u0000 The session starts by reading the existing field data and its history and then perform well drilling, completions, workovers, well tests, open-hole and cased-hole logging, manage production and injection targets, build/modify the surface production/injection facilities and receive the fully automated asset response in the form of the field reports, very much in the same way as in real life.\u0000 Once session is over the simulator generates a detailed debriefing report on team performance in numerous areas: economical, production, injection, reservoir and well performance so that team can understand where it did a good job and where it was not efficient.\u0000 The current paper shows how this facility has been integrated into the corporate staff capability program, expanded to anchor universities and shed the light to the future perspectives.","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86633426","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}
A. Fawzy, N. Talib, Ruslan Makhiyanov, Arslan Naseem, N. Molero, Rao Shafin Ali Khan, P. Enkababian, Wafaa Belkadi, A. Elattar, A. Ibrahim
In high-temperature carbonate producers, conventional hydrochloric (HCl) acid systems have been ineffective at delivering sustainable production improvement due to their kinetics. Retarded acids are deemed necessary to control the reaction and create effective wormholes. This scenario is even more critical in wells completed across long openhole horizontal intervals due to reservoir heterogeneity, changing downhole dynamics, and uniform acid placement goals. Out of the different retarded acid options, emulsified acid is one of the preferred choices by Middle East operators because of its excellent corrosion inhibition and deep wormhole penetration properties. However, it also brings other operational complexities, such as higher friction pressures, reduced pump rates, and more elaborate mixing procedures, which in some cases restrict its applicability. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as emulsified acids while eliminating its drawbacks, allowing friction pressures like that of straight HCl and wormholing performance equivalent to that of emulsified acid. A newly drilled oil producer in one of the largest carbonate fields in onshore Middle East was selected by the operator for pilot implementation of the SPRIAS as an alternative to emulsified acid. The candidate well featured significant damage associated with drilling, severely affecting its productivity. The well was completed across 3,067 ft of 6-in. openhole horizontal section, with a bottomhole temperature of 285°F, permeability range of 0.5 to 1.0 md, and an average porosity of 15%. Coiled tubing (CT) equipped with fiber optics was selected as the fluid conveyance method due to its capacity to enable visualization of the original fluid coverage through distributed temperature sensing (DTS), thus allowing informed adjustment of the stimulation schedule as well as identification of chemical diversion and complementary fluid placement requirements. Likewise, lower CT friction pressures from SPRIAS enabled the utilization of high-pressure jetting nozzle for enhanced acid placement, which was nearly impossible with emulsified acid. Following the acidizing treatment, post-stimulation DTS showed a more uniform intake profile across the uncased section; during well testing operations, the oil production doubled, exceeding the initial expectations. The SPRIAS allowed a 40% reduction in CT friction pressures compared to emulsified acid, 20% optimization in stimulation fluids volume, and reduced mixing time by 18 hours. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. In addition to production enhancement, this novel fluid simplified logistics by eliminating diesel transportation, thus reducing equipment and environmental footprints. It also reduces friction, thus enabling high-pressure jetting via CT, leading to more efficie
{"title":"Single-Phase Retarded Inorganic Acid Optimizes Remediation of Drilling Formation Damage in High-Temperature Openhole Horizontal Carbonate Producer","authors":"A. Fawzy, N. Talib, Ruslan Makhiyanov, Arslan Naseem, N. Molero, Rao Shafin Ali Khan, P. Enkababian, Wafaa Belkadi, A. Elattar, A. Ibrahim","doi":"10.2118/208185-ms","DOIUrl":"https://doi.org/10.2118/208185-ms","url":null,"abstract":"\u0000 In high-temperature carbonate producers, conventional hydrochloric (HCl) acid systems have been ineffective at delivering sustainable production improvement due to their kinetics. Retarded acids are deemed necessary to control the reaction and create effective wormholes. This scenario is even more critical in wells completed across long openhole horizontal intervals due to reservoir heterogeneity, changing downhole dynamics, and uniform acid placement goals.\u0000 Out of the different retarded acid options, emulsified acid is one of the preferred choices by Middle East operators because of its excellent corrosion inhibition and deep wormhole penetration properties. However, it also brings other operational complexities, such as higher friction pressures, reduced pump rates, and more elaborate mixing procedures, which in some cases restrict its applicability. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as emulsified acids while eliminating its drawbacks, allowing friction pressures like that of straight HCl and wormholing performance equivalent to that of emulsified acid.\u0000 A newly drilled oil producer in one of the largest carbonate fields in onshore Middle East was selected by the operator for pilot implementation of the SPRIAS as an alternative to emulsified acid. The candidate well featured significant damage associated with drilling, severely affecting its productivity. The well was completed across 3,067 ft of 6-in. openhole horizontal section, with a bottomhole temperature of 285°F, permeability range of 0.5 to 1.0 md, and an average porosity of 15%. Coiled tubing (CT) equipped with fiber optics was selected as the fluid conveyance method due to its capacity to enable visualization of the original fluid coverage through distributed temperature sensing (DTS), thus allowing informed adjustment of the stimulation schedule as well as identification of chemical diversion and complementary fluid placement requirements. Likewise, lower CT friction pressures from SPRIAS enabled the utilization of high-pressure jetting nozzle for enhanced acid placement, which was nearly impossible with emulsified acid. Following the acidizing treatment, post-stimulation DTS showed a more uniform intake profile across the uncased section; during well testing operations, the oil production doubled, exceeding the initial expectations. The SPRIAS allowed a 40% reduction in CT friction pressures compared to emulsified acid, 20% optimization in stimulation fluids volume, and reduced mixing time by 18 hours.\u0000 The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. In addition to production enhancement, this novel fluid simplified logistics by eliminating diesel transportation, thus reducing equipment and environmental footprints. It also reduces friction, thus enabling high-pressure jetting via CT, leading to more efficie","PeriodicalId":10959,"journal":{"name":"Day 3 Wed, November 17, 2021","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80493481","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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