A. Leong, Y. Azizan, Yee Tzen Yong, Yan Song, Rudzaifi Adizamri Abd Rani, Mohd Majdi Jasni
Mature fields often include wells or platforms that require a plug and abandonment (P&A) job and decommissioning. Two high-pressure gas wells were identified in a field offshore Brunei that required a coiled tubing unit (CTU) intervention to secure them. The job was further complicated by high reservoir pressure in a tight formation, a small platform area, and no existing surface facility. Because the flowline and pipeline equipment on the platform are not in service, a method was needed to take large volumes of returns. To overcome this challenge, an integrated operation was designed and planned that uses a complete catenary CTU and a pumping and flowback package with a mobile storage support vessel. The returns system will enable liquid (brine and spacer) and gas returns with pressures of up to 5,000 psi. The mobile storage support vessel enables the returns to be stored before disposal at an onshore facility. Before killing the wells and pumping cement across the perforation, multiple tubing plugs must be removed. High tubing pressure indicated some communication to the reservoir; consequently, the plug removal strategy with coiled tubing (CT) must include risk mitigation to ensure that the plugs can be removed safely. After all plugs were removed, the wells were successfully killed by using a 17 kPa/m (14.45 ppg) calcium chloride/calcium bromide (CaCl2/CaBr2) blend brine. The next operation was to spot cement across the perforation to a depth that is below where the tubing will be cut during the P&A process. The spacers and cement design must be tailored to avoid compatibility issues with the CaCl2/CaBr2 and the presence of carbon dioxide (CO2). The cement placement with CT is critical to prevent flash reaction with the kill fluid and to minimize the volume of contaminated cement. The cement was placed successfully and tested in accordance with the Brunei Shell Petroleum requirement. The wells were safely secured and ready for the planned P&A process. These operations marked the first successful operation on high-pressure, tight gas wells with no surface facilities on the platform within a sensitive environment. The use of a mobile storage support vessel enabled the wells to be killed successfully. This approach demonstrates that a similar method and similar planning can be used to safely and economically perform future interventions.
{"title":"Rigless Intervention to Secure Internal Blowout IBO Monitoring Gas Wells Offshore of Brunei","authors":"A. Leong, Y. Azizan, Yee Tzen Yong, Yan Song, Rudzaifi Adizamri Abd Rani, Mohd Majdi Jasni","doi":"10.2118/192000-MS","DOIUrl":"https://doi.org/10.2118/192000-MS","url":null,"abstract":"Mature fields often include wells or platforms that require a plug and abandonment (P&A) job and decommissioning. Two high-pressure gas wells were identified in a field offshore Brunei that required a coiled tubing unit (CTU) intervention to secure them. The job was further complicated by high reservoir pressure in a tight formation, a small platform area, and no existing surface facility.\u0000 Because the flowline and pipeline equipment on the platform are not in service, a method was needed to take large volumes of returns. To overcome this challenge, an integrated operation was designed and planned that uses a complete catenary CTU and a pumping and flowback package with a mobile storage support vessel. The returns system will enable liquid (brine and spacer) and gas returns with pressures of up to 5,000 psi. The mobile storage support vessel enables the returns to be stored before disposal at an onshore facility.\u0000 Before killing the wells and pumping cement across the perforation, multiple tubing plugs must be removed. High tubing pressure indicated some communication to the reservoir; consequently, the plug removal strategy with coiled tubing (CT) must include risk mitigation to ensure that the plugs can be removed safely.\u0000 After all plugs were removed, the wells were successfully killed by using a 17 kPa/m (14.45 ppg) calcium chloride/calcium bromide (CaCl2/CaBr2) blend brine. The next operation was to spot cement across the perforation to a depth that is below where the tubing will be cut during the P&A process. The spacers and cement design must be tailored to avoid compatibility issues with the CaCl2/CaBr2 and the presence of carbon dioxide (CO2). The cement placement with CT is critical to prevent flash reaction with the kill fluid and to minimize the volume of contaminated cement. The cement was placed successfully and tested in accordance with the Brunei Shell Petroleum requirement.\u0000 The wells were safely secured and ready for the planned P&A process. These operations marked the first successful operation on high-pressure, tight gas wells with no surface facilities on the platform within a sensitive environment. The use of a mobile storage support vessel enabled the wells to be killed successfully. This approach demonstrates that a similar method and similar planning can be used to safely and economically perform future interventions.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88394216","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. Ismail, Syarifah Puteh Mariah Syed Abd Rahim, Z. Yahia, S. Elshourbagi, M. F. Ishak, M. R. Roslan, W. C. Hamat, A. Amara, Stephen Faux, G. Makin
Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure. The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology. DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement. Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system. The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system. Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years. The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.
{"title":"Ground Breaking Technology in Artificial Lift; 1st Installation of Full Digital Intelligent Artificial Lift DIAL System at DL field, Brownfield Offshore Malaysia","authors":"S. Ismail, Syarifah Puteh Mariah Syed Abd Rahim, Z. Yahia, S. Elshourbagi, M. F. Ishak, M. R. Roslan, W. C. Hamat, A. Amara, Stephen Faux, G. Makin","doi":"10.2118/191885-MS","DOIUrl":"https://doi.org/10.2118/191885-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Moving to digitalization era in the current low oil price environment, paradigm shift is really crucial in managing brownfield development and production. The challenge is to select the best technology to harvest the optimum production from the field but at the same time reduce potential capital and operating expenditure.\u0000 \u0000 \u0000 \u0000 The paper highlights the technology evaluation of Digital Intelligent Artificial Lift (DIAL) system. This includes it's working principles, candidates screening, risk mitigation plan as well as technology success criteria developed specifically for the technology.\u0000 DIAL system is an in-well gas lift system that can overcome the well design and operational limitations of existing side pocket mandrels and valves. DIAL enables a better gas lift well design as well as able to interconnect downhole and surface monitoring & control in real-time. It provides opportunity for automation, better subsurface and surface integration as well as minimizing well intervention requirement.\u0000 Based on the promising technology evaluation, one pilot well was identified by the team at DL field. The well was part of DL drilling campaign executed in Q2 2018. Details of the well design & scope, as well as gas lift design for the well will be shared. Commercial comparison was demonstrated between conventional side pocket mandrel system and the DIAL system.\u0000 \u0000 \u0000 \u0000 The case study at DL field will be discussed in details, starts from their wells’ design, technology deployment strategy, installation, production test result as well as lessons learnt during installation and operationalization of the system.\u0000 Moving forward from the pilot application, root cause failure analysis was done, lessons learnt were identified, design improvements were proposed and continuous monitoring of the system will be done, according to the success criteria outlined. Potential replication candidates have also been identified by the team with at least 10 promising potential candidates to be installed within the next 2 years.\u0000 \u0000 \u0000 \u0000 The technology deployment was the result of collaborative works between PETRONAS, Silverwell Energy and Neural Oilfield Service.\u0000","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73450870","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}
Y. Al-Otaibi, M. Al-Mutawa, T. Bloushi, E. Fidan, S. Sharma, S. Pradhan, P. Manimaran
Optimization of permanent liner completions in the North Kuwait Jurassic Gas (NKJG) reservoirs has been an ongoing challenge progressed on a steep learning curve within the last decade. Various completion options are field-tested in determining the optimal completion hardware and activation methodology. The asset's objectives have been multi-dimensional: preserve natural fractures, minimize formation damage, segregate, stimulate and activate optimally, while installing permanent completions hardware efficiently, which can withstand 15,000-psi differential pressure at high temperature and sour gas environment and sustain production for the well life of over 20 years. NKJG faces the enormous task of increasing the hydrocarbon production potential by over 200% within a short time period. The reservoirs are high-pressured and high-temperature (HTHP) gas condensate assets with tight matrix properties (i.e. <0.1 mD permeability), in variation with naturally fractured sections within flow-zones separated into eight segments. Preserving the natural fractures, removal of near wellbore damage and segregating flow-zones based on lithology and critical reservoir properties are important especially in peripheral subsurface locations, where the realization of full reservoir potential is not only essential for production success, but also required for appraisal of boundary conditions. For realizing these objectives, the asset custom-designed a multi-stage completion system with hydro-mechanical liner hanger packer, open-hole packers, hydraulic anchor and multiple frac ports set and activated as a drop-ball system. Due to the high completion loads, differential body and packer rating are manufactured to 15,000 psi using corrosion resistant alloy throughout, with the PBR and seal-bore assembly designed to withstand differential pressures and contraction during multiple fracturing events. Custom-designed multi-stage completion assembly (MSC-HP) was successfully installed, sequentially hydraulic-fracced and commingle-tested on flowback. Customized operational guidelines were established including a pre-set success criterion, openhole and caliper log sequences, tie-back cementation and subsequent clean out trips, followed by hole conditioning and reamer runs to compute the final drag and friction forces. Differential sticking risks were mitigated by avoiding the "pressure ramps" exacerbated by differential depletion evident in the area. Reservoir was segmented in three distinct intervals to maximize flow potential. As a result, the asset's objectives were successfully met, with the additional benefits of proving multiple zone activation, each with a complicated sequence of operational events, performed sequentially in four days. This paper documents the project cycle from successful planning and design, to installation and execution phases of the MSC-HP in peripheral deep NKJG asset. Key learnings and critical factors, which led to the successful well results i
{"title":"A Field Application of Successful Installation and Sequential Activation of 15,000-psi Rated Hydro-Mechanical Multi-Stage Completion in Peripheral Deep North Kuwait Jurassic Asset for Improved Completion Efficiency and Well Productivity","authors":"Y. Al-Otaibi, M. Al-Mutawa, T. Bloushi, E. Fidan, S. Sharma, S. Pradhan, P. Manimaran","doi":"10.2118/191935-MS","DOIUrl":"https://doi.org/10.2118/191935-MS","url":null,"abstract":"\u0000 Optimization of permanent liner completions in the North Kuwait Jurassic Gas (NKJG) reservoirs has been an ongoing challenge progressed on a steep learning curve within the last decade. Various completion options are field-tested in determining the optimal completion hardware and activation methodology. The asset's objectives have been multi-dimensional: preserve natural fractures, minimize formation damage, segregate, stimulate and activate optimally, while installing permanent completions hardware efficiently, which can withstand 15,000-psi differential pressure at high temperature and sour gas environment and sustain production for the well life of over 20 years.\u0000 NKJG faces the enormous task of increasing the hydrocarbon production potential by over 200% within a short time period. The reservoirs are high-pressured and high-temperature (HTHP) gas condensate assets with tight matrix properties (i.e. <0.1 mD permeability), in variation with naturally fractured sections within flow-zones separated into eight segments. Preserving the natural fractures, removal of near wellbore damage and segregating flow-zones based on lithology and critical reservoir properties are important especially in peripheral subsurface locations, where the realization of full reservoir potential is not only essential for production success, but also required for appraisal of boundary conditions. For realizing these objectives, the asset custom-designed a multi-stage completion system with hydro-mechanical liner hanger packer, open-hole packers, hydraulic anchor and multiple frac ports set and activated as a drop-ball system. Due to the high completion loads, differential body and packer rating are manufactured to 15,000 psi using corrosion resistant alloy throughout, with the PBR and seal-bore assembly designed to withstand differential pressures and contraction during multiple fracturing events.\u0000 Custom-designed multi-stage completion assembly (MSC-HP) was successfully installed, sequentially hydraulic-fracced and commingle-tested on flowback. Customized operational guidelines were established including a pre-set success criterion, openhole and caliper log sequences, tie-back cementation and subsequent clean out trips, followed by hole conditioning and reamer runs to compute the final drag and friction forces. Differential sticking risks were mitigated by avoiding the \"pressure ramps\" exacerbated by differential depletion evident in the area. Reservoir was segmented in three distinct intervals to maximize flow potential. As a result, the asset's objectives were successfully met, with the additional benefits of proving multiple zone activation, each with a complicated sequence of operational events, performed sequentially in four days.\u0000 This paper documents the project cycle from successful planning and design, to installation and execution phases of the MSC-HP in peripheral deep NKJG asset. Key learnings and critical factors, which led to the successful well results i","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"208 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72815345","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}
N. Koronful, K. Peters, M. F. Ali, J. Skulsangjuntr, Longcong Jiang, A. Kleine, Depnath Basu, J. Bencomo, Jonathan Hernandez, G. Brink
High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources. In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example, Figure 3 shows δ13CCO2 and δ13CCH4 for samples from various depths in the nearby field. The isotope data indicate that the samples contain mixed CO2 derived by different mechanisms from two sources. Partial least squares (PLS) regression of δ13CCO2 and δ13CCH4 and depth for 61 samples from the nearby field, where %CO2 was set as the dependent variable, resulted in a systematic correlation between predicted and measured %CO2. Alternate least squares (ALS) confirms that the data can be explained by mixing of gases from two endmembers: (1) shallower samples show lower %CO2 that is isotopically depleted in δ13CCH4 and δ13CCO2, and (2) deeper samples show higher %CO2 that is isotopically enriched in δ13CCH4 and δ13CCO2. The relative proportion of each endmember in the mixture can be calculated for each gas. Examples of near endmember gases in the nearby field (Figure 3) are: (1) shallow thermogenic CO2 derived by cracking of kerogen, e.g., 1681 m, 5% CO2, δ13CCH4 = -60‰, δ13CCO2 = -13‰, (100:0 mix); and (2) deep CO2 from carbonate decomposition, e.g., 2918 m, 74% CO2, δ13CCH4 = -32‰, δ13CCO2 = -3‰ (15:85 mix). These results are consistent with the general observation that tested Miocene traps in the Malay Basin and show a general trend of higher concentrations of CO2 in the deeper traps that are nearer carbonate basement. Biogenic CO2 may represent a third endmember in other parts of the basin.
在许多含油气盆地，特别是在东南亚，储层中的高二氧化碳限制了成功的勘探。近海Malay盆地的高储层二氧化碳是一个重大的勘探挑战。一些油田的二氧化碳含量超过80%，这使得它们不适合开发。关于二氧化碳起源的各种假设已经提出，但仍有争议。本文表明，地球化学和先进的石油系统建模有助于解决储层二氧化碳的来源，并允许在钻探前对潜在储层目标的二氧化碳进行定量估计。一种新的工作流程基于对CO2起源的化学机制的了解和地质埋藏史的数值模拟来估算储层中的CO2含量。热流、覆盖岩沉积和特定反应机制的动力学控制了CO2生成的时间和不同来源CO2的相对贡献。利用稳定碳同位素比值(δ13CCO2和δ13CCH4，‰)确定马来盆地天然气样品中CO2的来源。例如，图3显示了附近油田不同深度样品的δ13CCO2和δ13CCH4。同位素数据表明，样品中含有来自两个不同来源的不同机制的混合CO2。以%CO2为因变量，对61个样品的δ13CCO2和δ13CCH4与深度进行偏最小二乘回归分析，结果表明预测值与实测值之间存在系统相关性。交替最小二乘法(ALS)证实了两个端元气体的混合作用:(1)较浅样品中CO2含量较低，同位素富集于δ13CCH4和δ13CCO2;(2)较深样品中CO2含量较高，同位素富集于δ13CCH4和δ13CCO2。可以计算出每种气体在混合物中各端元的相对比例。附近气田近端气体的例子(图3)有:(1)干酪根裂解产生的浅层热成因CO2，如1681 m, 5% CO2， δ13CCH4 = -60‰，δ13CCO2 = -13‰，(100:0混合);(2)碳酸盐分解产生的深层CO2，如2918 m, 74% CO2， δ13CCH4 = -32‰，δ13CCO2 = -3‰(15:85混合)。这些结果与马来盆地中新世圈闭的一般观测结果一致，表明靠近碳酸盐基底的深层圈闭中CO2浓度较高。在盆地的其他地区，生物源CO2可能是第三个端元。
{"title":"Carbon Dioxide in Reservoir Gases: New Insights from Basin and Petroleum System Modeling","authors":"N. Koronful, K. Peters, M. F. Ali, J. Skulsangjuntr, Longcong Jiang, A. Kleine, Depnath Basu, J. Bencomo, Jonathan Hernandez, G. Brink","doi":"10.2118/192011-MS","DOIUrl":"https://doi.org/10.2118/192011-MS","url":null,"abstract":"\u0000 High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources.\u0000 In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example, Figure 3 shows δ13CCO2 and δ13CCH4 for samples from various depths in the nearby field. The isotope data indicate that the samples contain mixed CO2 derived by different mechanisms from two sources. Partial least squares (PLS) regression of δ13CCO2 and δ13CCH4 and depth for 61 samples from the nearby field, where %CO2 was set as the dependent variable, resulted in a systematic correlation between predicted and measured %CO2. Alternate least squares (ALS) confirms that the data can be explained by mixing of gases from two endmembers: (1) shallower samples show lower %CO2 that is isotopically depleted in δ13CCH4 and δ13CCO2, and (2) deeper samples show higher %CO2 that is isotopically enriched in δ13CCH4 and δ13CCO2. The relative proportion of each endmember in the mixture can be calculated for each gas. Examples of near endmember gases in the nearby field (Figure 3) are: (1) shallow thermogenic CO2 derived by cracking of kerogen, e.g., 1681 m, 5% CO2, δ13CCH4 = -60‰, δ13CCO2 = -13‰, (100:0 mix); and (2) deep CO2 from carbonate decomposition, e.g., 2918 m, 74% CO2, δ13CCH4 = -32‰, δ13CCO2 = -3‰ (15:85 mix). These results are consistent with the general observation that tested Miocene traps in the Malay Basin and show a general trend of higher concentrations of CO2 in the deeper traps that are nearer carbonate basement. Biogenic CO2 may represent a third endmember in other parts of the basin.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81633000","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}
C. Feng, Xili Deng, Wenkun Yin, Zhenlin Wang, Z. Mao
Tight oil reservoirs need fracturing to obtain industrial productivity, and brittleness of rock has an important effect on fracturing. For oil reservoirs of the Permian Lucaogou Formation in Jimusar Sag of Junggar Basin, in order to predict brittleness index accurately, 19 typical tight oil core samples were selected and the related parameters of petrophysics and rock mechanics were measured at first, it is found that the static and dynamic brittleness indices vary greatly. Then, based on the static and dynamic experimental results of core samples and previous research results, the ratio of static and dynamic brittleness indices is constructed, it has a well correlation with porosity and clay content. Hence, according to the porosity and clay content correction, the static and dynamic conversion model of brittleness indices is built. The predicted results of the model are in good agreement with the experimental results. Then, on the basis of the composition, structure and deformation mechanism, the reservoirs are divided into three types via rock brittleness. The stress-strain curves of good, poor and moderate brittleness reservoirs are respectively linear, concave and "S". The static brittleness index-Poisson's ratio cross plot is built to classify the reservoirs. When the static brittleness index is greater than 85 and Poisson's ratio is less than 0.2, the reservoir shows good brittleness. When the static brittleness index is less than 40 and Poisson's ratio is greater than 0.24, the reservoir shows poor brittleness, and when the static brittleness index and Poisson's ratio are between them, the reservoir shows moderate brittleness. Finally, the static and dynamic brittleness index conversion model and reservoir classification standard are applied to formation evaluation in the study area, showing good application results. The research results are of guiding significance for the conversion of static and dynamic parameters of tight oil reservoirs, the selection of fracturing layers and fracturing operation schemes.
{"title":"Brittleness Index Prediction via Well Logs and Reservoir Classification Based on Brittleness","authors":"C. Feng, Xili Deng, Wenkun Yin, Zhenlin Wang, Z. Mao","doi":"10.2118/191934-MS","DOIUrl":"https://doi.org/10.2118/191934-MS","url":null,"abstract":"\u0000 Tight oil reservoirs need fracturing to obtain industrial productivity, and brittleness of rock has an important effect on fracturing. For oil reservoirs of the Permian Lucaogou Formation in Jimusar Sag of Junggar Basin, in order to predict brittleness index accurately, 19 typical tight oil core samples were selected and the related parameters of petrophysics and rock mechanics were measured at first, it is found that the static and dynamic brittleness indices vary greatly. Then, based on the static and dynamic experimental results of core samples and previous research results, the ratio of static and dynamic brittleness indices is constructed, it has a well correlation with porosity and clay content. Hence, according to the porosity and clay content correction, the static and dynamic conversion model of brittleness indices is built. The predicted results of the model are in good agreement with the experimental results. Then, on the basis of the composition, structure and deformation mechanism, the reservoirs are divided into three types via rock brittleness. The stress-strain curves of good, poor and moderate brittleness reservoirs are respectively linear, concave and \"S\". The static brittleness index-Poisson's ratio cross plot is built to classify the reservoirs. When the static brittleness index is greater than 85 and Poisson's ratio is less than 0.2, the reservoir shows good brittleness. When the static brittleness index is less than 40 and Poisson's ratio is greater than 0.24, the reservoir shows poor brittleness, and when the static brittleness index and Poisson's ratio are between them, the reservoir shows moderate brittleness. Finally, the static and dynamic brittleness index conversion model and reservoir classification standard are applied to formation evaluation in the study area, showing good application results. The research results are of guiding significance for the conversion of static and dynamic parameters of tight oil reservoirs, the selection of fracturing layers and fracturing operation schemes.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76358168","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 success of shale development has inspired new technologies to economize the extensive fracturing treatments necessary to complete extremely low permeability commercial wells. While bi-wing fractures are typically achieved during conventional fracture stimulation applications, it is often necessary to generate a complex fracturing network for most formation types encountered in very low permeability unconventional wells. Therefore, for source shale formations, the emphasis is on connectivity to natural fractures to establish an adequate stimulated reservoir volume (SRV). This paper discusses a new approach where improved initial wellbore-to-formation connections can be achieved by creating extended large diameter vertical cavities from the lateral as an effective fracture initiation point. This provides improved connectivity to the stimulated reservoir network both during stimulation and production. Additionally, this paper discusses the unique mechanics of the new procedure to generate a large connected SRV (CSRV) in unconventional formations, the technique, and the resulting benefits in fracture stimulation of resource shales or in ultra low permeability sandstones or carbonates as well as coal reservoirs. This new approach is fairly easy to implement, can be applied with limited hydraulic horsepower availability, and the impact could be substantial.
{"title":"Vertical Minihole Creation and Fracturing Technology for Completing Unconventional Wells","authors":"J. B. Surjaatmadja, H. Abass","doi":"10.2118/192073-MS","DOIUrl":"https://doi.org/10.2118/192073-MS","url":null,"abstract":"\u0000 The success of shale development has inspired new technologies to economize the extensive fracturing treatments necessary to complete extremely low permeability commercial wells. While bi-wing fractures are typically achieved during conventional fracture stimulation applications, it is often necessary to generate a complex fracturing network for most formation types encountered in very low permeability unconventional wells. Therefore, for source shale formations, the emphasis is on connectivity to natural fractures to establish an adequate stimulated reservoir volume (SRV).\u0000 This paper discusses a new approach where improved initial wellbore-to-formation connections can be achieved by creating extended large diameter vertical cavities from the lateral as an effective fracture initiation point. This provides improved connectivity to the stimulated reservoir network both during stimulation and production. Additionally, this paper discusses the unique mechanics of the new procedure to generate a large connected SRV (CSRV) in unconventional formations, the technique, and the resulting benefits in fracture stimulation of resource shales or in ultra low permeability sandstones or carbonates as well as coal reservoirs. This new approach is fairly easy to implement, can be applied with limited hydraulic horsepower availability, and the impact could be substantial.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91516624","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 presents case studies on reservoir and well management of two laterally and vertically compartmentalized Western Australian Triassic gas condensate reservoirs, developed by five multi-zone "smart" wells with sand control, tied back to an offshore platform via a subsea network. In managing assets with such complexity, it is imperative to understand reservoir performance on a zone-by-zone basis. Quantifying performance allows management of flux through downhole sand control systems and optimisation of offtake strategy. The majority of the material published to date on "smart" wells has been focused on completion design optimisation and minimisation of unwanted oil/water production. There are few existing articles about production and reservoir optimisation of high rate gas wells requiring flux management. This paper showcases how remotely-operated selective completions ("smart" wells with permanent downhole gauges for each completion coupled with subsea flow meters for each well) have been instrumental in facilitating prompt analysis of zonal reservoir performance and thus in yielding insights into reservoir connectivity and allowing optimisation of zonal contributions. Various case studies will be presented showing how reservoir surveillance data is acquired and interpreted to optimize well zone-by-zone production and to manage flux limits on each producing zone. These case studies will include manipulation of downhole valves to provide information for established techniques such as interference testing and P/Z analysis. Data acquisition and interpretation challenges are highlighted along with fit-for-purpose solutions developed to overcome those challenges. The insights presented could facilitate better planning of similar systems in the future.
{"title":"Managing Complex, Laterally and Vertically Compartmentalized Reservoirs in a Subsea Tie-Back via Smart Well Completions – Case Studies","authors":"N. Smith, Abid Ghous, Sagarika Bharatiya","doi":"10.2118/192013-MS","DOIUrl":"https://doi.org/10.2118/192013-MS","url":null,"abstract":"\u0000 This paper presents case studies on reservoir and well management of two laterally and vertically compartmentalized Western Australian Triassic gas condensate reservoirs, developed by five multi-zone \"smart\" wells with sand control, tied back to an offshore platform via a subsea network. In managing assets with such complexity, it is imperative to understand reservoir performance on a zone-by-zone basis. Quantifying performance allows management of flux through downhole sand control systems and optimisation of offtake strategy. The majority of the material published to date on \"smart\" wells has been focused on completion design optimisation and minimisation of unwanted oil/water production. There are few existing articles about production and reservoir optimisation of high rate gas wells requiring flux management.\u0000 This paper showcases how remotely-operated selective completions (\"smart\" wells with permanent downhole gauges for each completion coupled with subsea flow meters for each well) have been instrumental in facilitating prompt analysis of zonal reservoir performance and thus in yielding insights into reservoir connectivity and allowing optimisation of zonal contributions. Various case studies will be presented showing how reservoir surveillance data is acquired and interpreted to optimize well zone-by-zone production and to manage flux limits on each producing zone. These case studies will include manipulation of downhole valves to provide information for established techniques such as interference testing and P/Z analysis.\u0000 Data acquisition and interpretation challenges are highlighted along with fit-for-purpose solutions developed to overcome those challenges.\u0000 The insights presented could facilitate better planning of similar systems in the future.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"124 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86574619","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 presents a case study review of the performance benefits of a 66 well Coal Bed Methane (CBM) development program whereby cased-hole (CH) logging was introduced as a substitute for open-hole (OH) logging. This paper demonstrates how the reduction in OH logging requirements improved time and cost performance and reduced risk exposure while maintaining suitable data quality. The approach was based on utilizing existing offset well data and three-dimensional (3D) seismic data to substitute OH density logging for CH density logging. Therefore reducing critical path time on the drilling rig and risk exposure with wireline logging tools in an OH environment. A qualitative and quantitative approach to review rig performance and cost benefits was subsequently undertaken. The density log was of key importance as it is used to define net coal thickness in CBM reservoirs. Current CH density logging typically results in the reduction of log resolution and accuracy which limits the ability to resolve thinner coal seams. The loss of coal definition has the potential to result in the under-estimation of net coal for reserves purposes, impact static modelling and possibly negatively impact fracture stimulation decisions. The 66 well development program provided a suitable data set to quantify the performance benefits of a combined CH and OH evaluation program. The transition to CH density logs removes online evaluation activities during the drilling operation. This provides a direct time and associated spread cost saving. In addition, unsuccessful OH logs were replaced with CH density logs when hole conditions presented higher likelihood of unproductive and high risk operations (tight hole/fishing). The campaigning of CH logging operations further optimized both wireline and operating company resources and time. The CH density logs provided suitable data to adequately identify coal targets in order to stimulate and complete the wellbore. The reduction in log resolution and coal identification was overcome by developing 'optimized' density cut-offs based on a calibration study with OH density wireline data. This case study supports the use of CH density logs in lieu of OH density logs where feasible for CBM reservoirs. It demonstrates the operational optimizations and cost savings by conducting wireline logging operations offline while also reducing risk exposure to down hole issues.
{"title":"Case Study for Performance Benefits of Cased-Hole Logging in Coal Bed Methane CBM","authors":"S. Mastin, Matt Pfahl, R. Jukes","doi":"10.2118/191932-MS","DOIUrl":"https://doi.org/10.2118/191932-MS","url":null,"abstract":"\u0000 This paper presents a case study review of the performance benefits of a 66 well Coal Bed Methane (CBM) development program whereby cased-hole (CH) logging was introduced as a substitute for open-hole (OH) logging. This paper demonstrates how the reduction in OH logging requirements improved time and cost performance and reduced risk exposure while maintaining suitable data quality.\u0000 The approach was based on utilizing existing offset well data and three-dimensional (3D) seismic data to substitute OH density logging for CH density logging. Therefore reducing critical path time on the drilling rig and risk exposure with wireline logging tools in an OH environment. A qualitative and quantitative approach to review rig performance and cost benefits was subsequently undertaken.\u0000 The density log was of key importance as it is used to define net coal thickness in CBM reservoirs. Current CH density logging typically results in the reduction of log resolution and accuracy which limits the ability to resolve thinner coal seams. The loss of coal definition has the potential to result in the under-estimation of net coal for reserves purposes, impact static modelling and possibly negatively impact fracture stimulation decisions.\u0000 The 66 well development program provided a suitable data set to quantify the performance benefits of a combined CH and OH evaluation program. The transition to CH density logs removes online evaluation activities during the drilling operation. This provides a direct time and associated spread cost saving. In addition, unsuccessful OH logs were replaced with CH density logs when hole conditions presented higher likelihood of unproductive and high risk operations (tight hole/fishing). The campaigning of CH logging operations further optimized both wireline and operating company resources and time. The CH density logs provided suitable data to adequately identify coal targets in order to stimulate and complete the wellbore. The reduction in log resolution and coal identification was overcome by developing 'optimized' density cut-offs based on a calibration study with OH density wireline data.\u0000 This case study supports the use of CH density logs in lieu of OH density logs where feasible for CBM reservoirs. It demonstrates the operational optimizations and cost savings by conducting wireline logging operations offline while also reducing risk exposure to down hole issues.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85284224","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. Varshney, Aman Goyal, I. Goyal, Akanksha Jain, N. Pandey, A. Parasher, S. Vermani, A. Negi, Vinit Sharma
Waterflood is most commonly used secondary recovery mechanism in conventional sanstone reservoirs worldwide. Waterflooding assists in pressure maintenance and increases the field estimated ultimate recovery (EUR). Conformance in water injector wells plays an important role during waterflooding of a reservoir. Better conformance results in improved vertical sweep efficiency leading to higher recovery. Continuous injection of fluids into the reservoir at higher rates may create channels for preferential flow. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures. For injection wells, the entry of fluids into a set of perforations is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into selective pay intervals results in diminished overall sweep efficiency. (J. Vasquez, et.al., 2008). This paper discusses the use of thermally activated gels from polyacrylamides and metal chelates applied for selective reservoir matrix permeability reduction in an injector well. A low concentration, low viscosity delayed crosslinker gel system employing partially hydrolyzed polyacrylamide (PHPA) exhibiting 12-14% degree of hydrolysis level with chromium acetate as crosslinker offering delayed gelation time was used to selectively isolate one of the payzones. A non-profile retrievable (NPR) plug was installed to isolate the target interval from the rest of the pay zones to enable selective treatment of the interval using coiled tubing (CT). The fluid was customized to minimize CT friction while ensuring that the rheological properties of the fluid in the reservoir would achieve the desired diversion and allow delayed gel crosslinking mechanism assuring avoiding of gel crosslinking in CT while pumping in progress. Denser brine relative to the delayed gel density was spotted above the NPR plug to avoid gel settling on the plug for easy retrieval of the plug post-treatment. Injectivity was measured and subsequently, the treatment was placed as per design while constantly monitoring the pressures so as to qualitatively determine the effectiveness of the treatment placement. The treatment resulted in significant alteration in injectivity of the targeted zone. Post-treatment production logs confirmed an improvement in the injection conformance. Later, the zone was isolated and the bottommost zones were selectively stimulated enhancing the injection and thus improving sweep efficiency. Since the crosslinked gel system is not prone to any disintegration when in contact with acidic interventions, the treatment ensures a superior longevity of the conformance control when compared to other conventional diversion or zonal shut-off treatments. The success of the treatment substantiates that the CT deployed low viscosity, low concentr
{"title":"Improving Conformance in an Injector Well Using Delayed Crosslink Polymer Gel : A Case Study","authors":"M. Varshney, Aman Goyal, I. Goyal, Akanksha Jain, N. Pandey, A. Parasher, S. Vermani, A. Negi, Vinit Sharma","doi":"10.2118/192136-MS","DOIUrl":"https://doi.org/10.2118/192136-MS","url":null,"abstract":"\u0000 Waterflood is most commonly used secondary recovery mechanism in conventional sanstone reservoirs worldwide. Waterflooding assists in pressure maintenance and increases the field estimated ultimate recovery (EUR). Conformance in water injector wells plays an important role during waterflooding of a reservoir. Better conformance results in improved vertical sweep efficiency leading to higher recovery.\u0000 Continuous injection of fluids into the reservoir at higher rates may create channels for preferential flow. Zones of higher permeability, leading to higher injectivity in selective zones, can also exist because of various lithological conditions and rock structures comprising of naturally occurring fractures or fissures. For injection wells, the entry of fluids into a set of perforations is governed by the quality of the perforations and the permeability of the formation at that depth. Preferential flow of injected fluids into selective pay intervals results in diminished overall sweep efficiency. (J. Vasquez, et.al., 2008).\u0000 This paper discusses the use of thermally activated gels from polyacrylamides and metal chelates applied for selective reservoir matrix permeability reduction in an injector well. A low concentration, low viscosity delayed crosslinker gel system employing partially hydrolyzed polyacrylamide (PHPA) exhibiting 12-14% degree of hydrolysis level with chromium acetate as crosslinker offering delayed gelation time was used to selectively isolate one of the payzones.\u0000 A non-profile retrievable (NPR) plug was installed to isolate the target interval from the rest of the pay zones to enable selective treatment of the interval using coiled tubing (CT). The fluid was customized to minimize CT friction while ensuring that the rheological properties of the fluid in the reservoir would achieve the desired diversion and allow delayed gel crosslinking mechanism assuring avoiding of gel crosslinking in CT while pumping in progress. Denser brine relative to the delayed gel density was spotted above the NPR plug to avoid gel settling on the plug for easy retrieval of the plug post-treatment. Injectivity was measured and subsequently, the treatment was placed as per design while constantly monitoring the pressures so as to qualitatively determine the effectiveness of the treatment placement.\u0000 The treatment resulted in significant alteration in injectivity of the targeted zone. Post-treatment production logs confirmed an improvement in the injection conformance. Later, the zone was isolated and the bottommost zones were selectively stimulated enhancing the injection and thus improving sweep efficiency. Since the crosslinked gel system is not prone to any disintegration when in contact with acidic interventions, the treatment ensures a superior longevity of the conformance control when compared to other conventional diversion or zonal shut-off treatments.\u0000 The success of the treatment substantiates that the CT deployed low viscosity, low concentr","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"165 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74772825","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. Tan, Bor Seng Lee, H. Vader, N. Holleman, R. Spiteri, A. Ahmed, F. Maula, S. Shamsuddin, E. Heng
A Vertical Seismic Profile acquired while drilling and which utilized an a priori velocity model template to facilitate accurate well landing in a constrained drilling section is presented. The results were compared to original predictions based on surface seismic and actual formation depths taken from log data. The approach used actual checkshot velocities acquired in real time using VSP lookahead imaging while drilling to reduce spatial and depth uncertainty. Projections ahead of the well landing utilized the checkshot data to perturb the a priori velocity templates in real time. It was also complemented by the borehole seismic image to check for sub-seismic faults and alternate interpretations. Based on these projections, trajectory corrections were made to optimize landing the well in a key reservoir sand. Initiating early directional changes were critical to land on a short, directionally-constrained open-hole section whilst ensuring the section was within the targeted fault block. A comparison of the actual wellbore velocities against the predrill scenarios is provided along with corresponding vertical depth predictions. Lateral constraint was provided by the correlations of the VSP with the surface seismic image at key stages while drilling. Mapping of the drilling data to the velocity templates showed a deep case scenario for well placement. Details of the two resultant trajectory changes initiated after 2 and 5 stands of drilling respectively are explained. The approach allowed for accurate well placement, reducing depth uncertainty from 60-100 ft. predrill to within 5 ft from final while drilling prediction to actual depth. Final depth confirmation utilized Gamma Ray and Resistivity at Bit Inclination (GABI and RABI) for the key sand. The sand was found to be 18 ft. deeper than initially expected based on the pre-drill model. This method saved the drillers a potential side track. Conventional Electromagnetic well placement techniques can be limited in short open-hole sections where early time information is required to facilitate trajectory changes to allow for correct spatial landings. By using VSP while drilling in conjunction with a priori modelling, data can be acquired early enough to successfully, address this challenge.
{"title":"A Priori Scenario Modelling with LWD Seismic for Successful Well Placement","authors":"A. Tan, Bor Seng Lee, H. Vader, N. Holleman, R. Spiteri, A. Ahmed, F. Maula, S. Shamsuddin, E. Heng","doi":"10.2118/191970-MS","DOIUrl":"https://doi.org/10.2118/191970-MS","url":null,"abstract":"\u0000 A Vertical Seismic Profile acquired while drilling and which utilized an a priori velocity model template to facilitate accurate well landing in a constrained drilling section is presented. The results were compared to original predictions based on surface seismic and actual formation depths taken from log data.\u0000 The approach used actual checkshot velocities acquired in real time using VSP lookahead imaging while drilling to reduce spatial and depth uncertainty. Projections ahead of the well landing utilized the checkshot data to perturb the a priori velocity templates in real time. It was also complemented by the borehole seismic image to check for sub-seismic faults and alternate interpretations. Based on these projections, trajectory corrections were made to optimize landing the well in a key reservoir sand. Initiating early directional changes were critical to land on a short, directionally-constrained open-hole section whilst ensuring the section was within the targeted fault block.\u0000 A comparison of the actual wellbore velocities against the predrill scenarios is provided along with corresponding vertical depth predictions. Lateral constraint was provided by the correlations of the VSP with the surface seismic image at key stages while drilling. Mapping of the drilling data to the velocity templates showed a deep case scenario for well placement. Details of the two resultant trajectory changes initiated after 2 and 5 stands of drilling respectively are explained. The approach allowed for accurate well placement, reducing depth uncertainty from 60-100 ft. predrill to within 5 ft from final while drilling prediction to actual depth. Final depth confirmation utilized Gamma Ray and Resistivity at Bit Inclination (GABI and RABI) for the key sand. The sand was found to be 18 ft. deeper than initially expected based on the pre-drill model. This method saved the drillers a potential side track.\u0000 Conventional Electromagnetic well placement techniques can be limited in short open-hole sections where early time information is required to facilitate trajectory changes to allow for correct spatial landings. By using VSP while drilling in conjunction with a priori modelling, data can be acquired early enough to successfully, address this challenge.","PeriodicalId":11182,"journal":{"name":"Day 3 Thu, October 25, 2018","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-10-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85652393","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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