I. Putra, Tan Chin Chien, M. Badaruddin, M. Isa, Cheong Xiang Hou, Liu Dongjie, Sun Dalin
Late life production of oil & gas facilities are faced with significant challenge especially when sand is produced along with the production fluid. It can cause premature failure of the equipment, for example piping and pipeline. Mitigation by adding sand removal facility is limited by space, available load, and handling at satellite wellhead platform. It also introduced additional pressure drop which limit the production that already in low pressure. One of the measures to mitigate sand erosion issue for the offshore pipeline and riser is by flow assurance, to reduce the flow velocity so that the sand velocity will be less than the erosional velocity. This mitigation comes with drawback where reducing velocity will require bigger size pipeline, higher cost, and introduce higher liquid dropout along the pipeline which will create severe slugging issue in the pipeline. Next mitigation can be done by increasing bend radius along the pipeline, to reduce impact angle of the sand to the internal surface of the pipeline. Last mitigation will be increasing resistance of the material to the sand erosion. Combination of those methodology is required to achieve the most optimum solution to mitigate sand erosion. This paper present sand erosion mitigation on one of the existing pipeline replacement projects in PETRONAS by application of unbonded flexible pipe. Modeling of the of the erosion due to sand particle solution in the pipeline was done using computational fluid dynamic finite element analysis simulation. Experimental test with samples positioned at various orientation of the riser bend location were also investigated. Concerning the exceptional balance between results efficiency and simulation time, a grid sensitivity test has also been included. Various parameters were used to verify the sensitivity of the simulation including materials properties for various fluid composition data obtained from production forecast and fluid velocity as modeled in the pipeline steady state hydraulic analysis and transient flow assurance analysis. As result, the thickness of internal carcass is found sufficient to withstand the erosion threat generated by sand particles for the entire design life of the pipeline. The results obtained from finite element analysis and erosion experimental test were then correlated, and the comparison were illustrated in graph of velocity against erosion rate for each of sand concentration. The result of the modeling and experimental testing may improve prediction model of the sand erosion in the offshore pipeline especially for flexible pipeline and riser application.
{"title":"Sand Erosion Mitigation for Offshore Pipeline and Riser – Erosion Prediction by Computational Fluid Dynamic CFD Analysis and Experimental Testing","authors":"I. Putra, Tan Chin Chien, M. Badaruddin, M. Isa, Cheong Xiang Hou, Liu Dongjie, Sun Dalin","doi":"10.4043/31451-ms","DOIUrl":"https://doi.org/10.4043/31451-ms","url":null,"abstract":"\u0000 Late life production of oil & gas facilities are faced with significant challenge especially when sand is produced along with the production fluid. It can cause premature failure of the equipment, for example piping and pipeline. Mitigation by adding sand removal facility is limited by space, available load, and handling at satellite wellhead platform. It also introduced additional pressure drop which limit the production that already in low pressure. One of the measures to mitigate sand erosion issue for the offshore pipeline and riser is by flow assurance, to reduce the flow velocity so that the sand velocity will be less than the erosional velocity. This mitigation comes with drawback where reducing velocity will require bigger size pipeline, higher cost, and introduce higher liquid dropout along the pipeline which will create severe slugging issue in the pipeline. Next mitigation can be done by increasing bend radius along the pipeline, to reduce impact angle of the sand to the internal surface of the pipeline. Last mitigation will be increasing resistance of the material to the sand erosion. Combination of those methodology is required to achieve the most optimum solution to mitigate sand erosion. This paper present sand erosion mitigation on one of the existing pipeline replacement projects in PETRONAS by application of unbonded flexible pipe. Modeling of the of the erosion due to sand particle solution in the pipeline was done using computational fluid dynamic finite element analysis simulation. Experimental test with samples positioned at various orientation of the riser bend location were also investigated. Concerning the exceptional balance between results efficiency and simulation time, a grid sensitivity test has also been included. Various parameters were used to verify the sensitivity of the simulation including materials properties for various fluid composition data obtained from production forecast and fluid velocity as modeled in the pipeline steady state hydraulic analysis and transient flow assurance analysis. As result, the thickness of internal carcass is found sufficient to withstand the erosion threat generated by sand particles for the entire design life of the pipeline. The results obtained from finite element analysis and erosion experimental test were then correlated, and the comparison were illustrated in graph of velocity against erosion rate for each of sand concentration. The result of the modeling and experimental testing may improve prediction model of the sand erosion in the offshore pipeline especially for flexible pipeline and riser application.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83007045","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}
Raja Zahirudin Raja Ismail, Zahrin Zain, Mohd Noor Baharin Che Kamaruddin, Mohd Faridz Mod Yunoh
This paper aims to share a new concept of assets condition assessment knows as Integrated Metal Magnetic Memory (i-MMM) which integrates capability of various Non-Destructive Testing (NDT) technology in determining the current state of deformed pipeline due to external loadings. MMM technology is one of NDT technique which can be used for early failure detection especially for Stress Concentration Zones (SCZ), microcrack and fatigue damage for ferromagnetic components. MMM is a passive technology tools that relies on the measurement of Self-magnetic Leakage Field (SMLF) of the ferromagnetic materials. Most of the traditional NDT method able to inspect the macro defect but incapable to identify micro defect due to the stress concentration zone. Based on this, MMM can be integrated and complimentary in its capability to other well-known NDT testing such as Ultrasonic Testing (UT) and Hardness Test. A case study presented whereby iMMM can be utilized to determined location which are prone to deformation due to stress and detailed assessment from changes of hardness up to development of macro size defect. Based on the findings in the case study, 2 microcrack were found at 2 inspected location of the pipeline. Finally, based on the results and findings from the integrated approach of i-MMM, it can contribute and provide more impact on the simulation analysis by providing focused anomaly area or location and reduced the processing time.
{"title":"Assessment on Deformed Pipeline Using Integrated Metal Magnetic Memory i-MMM Technology","authors":"Raja Zahirudin Raja Ismail, Zahrin Zain, Mohd Noor Baharin Che Kamaruddin, Mohd Faridz Mod Yunoh","doi":"10.4043/31424-ms","DOIUrl":"https://doi.org/10.4043/31424-ms","url":null,"abstract":"\u0000 This paper aims to share a new concept of assets condition assessment knows as Integrated Metal Magnetic Memory (i-MMM) which integrates capability of various Non-Destructive Testing (NDT) technology in determining the current state of deformed pipeline due to external loadings.\u0000 MMM technology is one of NDT technique which can be used for early failure detection especially for Stress Concentration Zones (SCZ), microcrack and fatigue damage for ferromagnetic components. MMM is a passive technology tools that relies on the measurement of Self-magnetic Leakage Field (SMLF) of the ferromagnetic materials. Most of the traditional NDT method able to inspect the macro defect but incapable to identify micro defect due to the stress concentration zone. Based on this, MMM can be integrated and complimentary in its capability to other well-known NDT testing such as Ultrasonic Testing (UT) and Hardness Test.\u0000 A case study presented whereby iMMM can be utilized to determined location which are prone to deformation due to stress and detailed assessment from changes of hardness up to development of macro size defect. Based on the findings in the case study, 2 microcrack were found at 2 inspected location of the pipeline.\u0000 Finally, based on the results and findings from the integrated approach of i-MMM, it can contribute and provide more impact on the simulation analysis by providing focused anomaly area or location and reduced the processing time.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90843089","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}
Mohd Shafie Jumaat, S. Wattanapornmongkol, Sorawit Wattanachai, Kontron Konglumthan
The Gulf of Thailand is developed with a high volume of slim monobore wells, producing from multiple thin reservoirs. The high volume of wells enables sufficient production output, but their costs must be well managed for overall field economics. An important cost component comes from the perforating operation that involves several runs of guns on electric wireline, and on each run consists of several guns that are activated sequentially using switches. This process of perforating multiple zones in a well, if not managed, will lead to extended operational time or worse, leading to serious problems like off-depth perforation. Additionally, the temperature of the wells averaging at 370 degF poses an additional challenge to the operations. The efficiency of operation is paramount in achieving better well economics. Hence, several operational and technology optimizations were performed over the years to achieve several incremental in efficiency. Incremental improvement is always valuable in such a high-volume operation involving thousands of perforating runs annually. However, the gain is even more pronounced when a step change in efficiency is achieved, and this has been observed in the new gun docking system engineered for the high-volume market in Thailand. It enables quicker connection of multiple guns on the surface with better safety and reliability. This paper discusses the background of the high-volume perforating in Thailand and the need for efficiency, which led to the development of this new gun docking system tailored for this market. This docking system technology is presented together with the statistics of its deployment in over 300 perforating runs to date and compared to the statistics of the previous system. The efficiency achieved comes from its quicker connection and arming system, combined with its better safety and reliability that lead to a lower misfire rate. The success of its deployment and more importantly, its step change in efficiency may pave ways for more marginal fields to be developed globally. Additionally, as thousands of perforating runs are performed globally, its efficiency will also play a vital role in shortening operational times and contribute to lower global carbon emission.
{"title":"Perforating Docking System for Efficient High-Volume Operation","authors":"Mohd Shafie Jumaat, S. Wattanapornmongkol, Sorawit Wattanachai, Kontron Konglumthan","doi":"10.4043/31571-ms","DOIUrl":"https://doi.org/10.4043/31571-ms","url":null,"abstract":"\u0000 The Gulf of Thailand is developed with a high volume of slim monobore wells, producing from multiple thin reservoirs. The high volume of wells enables sufficient production output, but their costs must be well managed for overall field economics. An important cost component comes from the perforating operation that involves several runs of guns on electric wireline, and on each run consists of several guns that are activated sequentially using switches. This process of perforating multiple zones in a well, if not managed, will lead to extended operational time or worse, leading to serious problems like off-depth perforation. Additionally, the temperature of the wells averaging at 370 degF poses an additional challenge to the operations.\u0000 The efficiency of operation is paramount in achieving better well economics. Hence, several operational and technology optimizations were performed over the years to achieve several incremental in efficiency. Incremental improvement is always valuable in such a high-volume operation involving thousands of perforating runs annually. However, the gain is even more pronounced when a step change in efficiency is achieved, and this has been observed in the new gun docking system engineered for the high-volume market in Thailand. It enables quicker connection of multiple guns on the surface with better safety and reliability.\u0000 This paper discusses the background of the high-volume perforating in Thailand and the need for efficiency, which led to the development of this new gun docking system tailored for this market. This docking system technology is presented together with the statistics of its deployment in over 300 perforating runs to date and compared to the statistics of the previous system. The efficiency achieved comes from its quicker connection and arming system, combined with its better safety and reliability that lead to a lower misfire rate.\u0000 The success of its deployment and more importantly, its step change in efficiency may pave ways for more marginal fields to be developed globally. Additionally, as thousands of perforating runs are performed globally, its efficiency will also play a vital role in shortening operational times and contribute to lower global carbon emission.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85775901","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}
Unmanned aerial vehicle (UAV) technology has recently improved in terms of robustness and reliability to be utilized industrially such as site patronage, monitoring and surveillance missions. On the contrary, the delayed development of competent UAV pilots and operators is slowing down operational expansion, resulting in everyday UAV usage costly and unfeasible. The fully automated and completely independent "DroneBox" will act as the drone storage and self-maintenance base for a surveillance operation with no direct human involvement. The drone will be capable of taking- off, performing missions, landing precisely, and recharging automatically while utilizing collected real-time data to perform with the safest configuration through DroneBox. When compared to the industry’s conventional method, the risk, cost, and time of surveillance operation will be reduced with the application of the DroneBox system offshore. According to realistic estimates, deploying the DroneBox system on 20 unmanned wellhead platform platforms can cut operator visits up to one-third of the trips, resulting in saving 22% fuel of crew boat vessels or up to 1.82 million USD operating cost in Artit (ART) and Great Bongkot North (GBN) wellhead platforms.
无人机(UAV)技术最近在鲁棒性和可靠性方面得到了改进，可用于工业上，例如现场赞助，监测和监视任务。相反，有能力的无人机飞行员和操作员的延迟发展正在减缓作战扩张，导致日常无人机使用成本高昂且不可行。完全自动化和完全独立的“无人机箱”将作为无人机存储和自我维护基地，进行无人直接参与的监视行动。无人机将能够起飞，执行任务，精确着陆，并自动充电，同时利用收集的实时数据，通过DroneBox以最安全的配置执行。与行业的传统方法相比，在海上应用DroneBox系统将降低监控操作的风险、成本和时间。根据实际估计，在20个无人井口平台上部署DroneBox系统可以减少操作人员多达三分之一的行程，从而节省22%的船员船燃料，或在Artit (ART)和Great Bongkot North (GBN)井口平台上节省高达182万美元的运营成本。
{"title":"DroneBox: A Fully Automated Drone System for Surveillance Application","authors":"Pattawut Manapongpun, Chanon Karoonkornsakul, Krittin Peechaphand, Pakpoom Kriengkomol, Amin Rajawana, Pawarit Ritmetee, Narongsak Lounsrimongkol, Napat Chenchai","doi":"10.4043/31685-ms","DOIUrl":"https://doi.org/10.4043/31685-ms","url":null,"abstract":"\u0000 Unmanned aerial vehicle (UAV) technology has recently improved in terms of robustness and reliability to be utilized industrially such as site patronage, monitoring and surveillance missions. On the contrary, the delayed development of competent UAV pilots and operators is slowing down operational expansion, resulting in everyday UAV usage costly and unfeasible. The fully automated and completely independent \"DroneBox\" will act as the drone storage and self-maintenance base for a surveillance operation with no direct human involvement. The drone will be capable of taking- off, performing missions, landing precisely, and recharging automatically while utilizing collected real-time data to perform with the safest configuration through DroneBox. When compared to the industry’s conventional method, the risk, cost, and time of surveillance operation will be reduced with the application of the DroneBox system offshore. According to realistic estimates, deploying the DroneBox system on 20 unmanned wellhead platform platforms can cut operator visits up to one-third of the trips, resulting in saving 22% fuel of crew boat vessels or up to 1.82 million USD operating cost in Artit (ART) and Great Bongkot North (GBN) wellhead platforms.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"66 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91340099","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}
Zulkifli B M Zin, Jennyfer Joseph Kuanji, Nik Zarina Bt Nik Khansani
Sand production is a common issue, especially in a depleting field as water production commences, and sand strength weakens. Conventional sand management focuses on downhole sand exclusion from the wellbore either through completion design or production reduction by choke optimisation as passive sand control. The objective of the paper is to share the company's journey in sand management in collaboration of various supporting units. The Holistic Sand Management methodological process adopts a 5 keys action plan, namely: Establishment of dedicated focus sand team with multidisciplinary support covering surface and subsurface activities Situational Assessment to develop baseline in sand management preparedness in each field, identifying gaps and developing an intervention plan Development and utilisation of an in-house erosion prediction tool, Continuous upskilling in sand management best practices, and Technology review and active pilot testing utilising digital enhancement to assist in sand management activities. Establishment of a dedicated and collaborative focus group, Integrated Sand Management (ISM) team in the centre which is replicated at the region as Regional Sand Team (RST), has allowed for continuous communication on sand management matters. Situational Assessment consists of 13 integrated subsurface and surface elements to evaluate a field capability to manage sand production. These 13 elements include sand management philosophy and organisation setup, sand prediction, sand control design, sand sampling and monitoring as well as surface sand handling and disposal. Findings from the assessment are used to gauge the field's readiness and ability to manage sand operation and develop gaps closure plan to achieve the optimum holistic sand management. The Sand Erosional and Transportation (SET) tool, an in-house developed tool, is used to evaluate sand erosion and deposition risk in the production system. The tool is used extensively to generate a safe operating envelope for sand producing well during open-up and continuous production. This has allowed the company to shift from limiting production up to a specific sand concentration to erosion risk-based approach, which in turn creates production optimization opportunities. Regular and continuous upskilling sessions ensure the frontline operations are updated and abreast with best practices in sand management. In addition, the ISM team reviews and leverages on latest technology, actively organises pilot test at a selected site supported with digital enhancement to assist in sand management activities. The application of a Holistic Sand Management methodology is seen to reduce erosion related Loss of Primary Containment (LOPC), sustain production, and minimise unplanned deferment. However, this is just the beginning and the battle in sand operation will continue to be very challenging in balancing between production while ensuring asset integrity. The methodology is a novel approach f
{"title":"Holistic Sand Management in Malaysia Assets; Successful Case Studies and Lessons Learnt","authors":"Zulkifli B M Zin, Jennyfer Joseph Kuanji, Nik Zarina Bt Nik Khansani","doi":"10.4043/31370-ms","DOIUrl":"https://doi.org/10.4043/31370-ms","url":null,"abstract":"\u0000 Sand production is a common issue, especially in a depleting field as water production commences, and sand strength weakens. Conventional sand management focuses on downhole sand exclusion from the wellbore either through completion design or production reduction by choke optimisation as passive sand control.\u0000 The objective of the paper is to share the company's journey in sand management in collaboration of various supporting units.\u0000 The Holistic Sand Management methodological process adopts a 5 keys action plan, namely:\u0000 Establishment of dedicated focus sand team with multidisciplinary support covering surface and subsurface activities Situational Assessment to develop baseline in sand management preparedness in each field, identifying gaps and developing an intervention plan Development and utilisation of an in-house erosion prediction tool, Continuous upskilling in sand management best practices, and Technology review and active pilot testing utilising digital enhancement to assist in sand management activities.\u0000 Establishment of a dedicated and collaborative focus group, Integrated Sand Management (ISM) team in the centre which is replicated at the region as Regional Sand Team (RST), has allowed for continuous communication on sand management matters. Situational Assessment consists of 13 integrated subsurface and surface elements to evaluate a field capability to manage sand production. These 13 elements include sand management philosophy and organisation setup, sand prediction, sand control design, sand sampling and monitoring as well as surface sand handling and disposal. Findings from the assessment are used to gauge the field's readiness and ability to manage sand operation and develop gaps closure plan to achieve the optimum holistic sand management. The Sand Erosional and Transportation (SET) tool, an in-house developed tool, is used to evaluate sand erosion and deposition risk in the production system. The tool is used extensively to generate a safe operating envelope for sand producing well during open-up and continuous production. This has allowed the company to shift from limiting production up to a specific sand concentration to erosion risk-based approach, which in turn creates production optimization opportunities. Regular and continuous upskilling sessions ensure the frontline operations are updated and abreast with best practices in sand management. In addition, the ISM team reviews and leverages on latest technology, actively organises pilot test at a selected site supported with digital enhancement to assist in sand management activities. The application of a Holistic Sand Management methodology is seen to reduce erosion related Loss of Primary Containment (LOPC), sustain production, and minimise unplanned deferment. However, this is just the beginning and the battle in sand operation will continue to be very challenging in balancing between production while ensuring asset integrity.\u0000 The methodology is a novel approach f","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91125587","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}
Asba Madzidah Binti Abu Bakar, M. M. H. B. Amjath Hussain, M. F. B. Bakar, Fuziana Binti Tusimin, A. Abdullah, Chee Seong Tan, Nicholas Moses
Originally, an infill well from project H was approved in 2013 to be completed as a single zone Open Hole Gravel Pack (OHGP) to produce gas commingled from three sands located at the shallowest reservoir in that field. Interpretation of recent logs from a nearby producing well indicated that there was significant water threat at two of the sands which would lead to water influx from the beginning of production if the well was to be completed as a single zone OHGP. The well was then redesigned to be completed as a Cased Hole Gravel Pack (CHGP) in order to have mechanical isolation from the water zones with an inner string and internal isolation packers to allow feasibility of zonal isolation to shut off the water producing zone in the future. This feature however resulted in higher well cost as compared to the approved design. Due to recent hostile low oil price, a more cost-effective sand control design was evaluated to reduce the well cost while maintaining similar performances as a CHGP design in terms of the capability to delay water breakthrough. Design feasibility study was performed on multizone OHGP with open hole mechanical packer and an inner string design to evaluate its performance and magnitude of cost reduction relative to a CHGP design. Skin analysis was performed for both OHGP and CHGP completion designs to evaluate any additional pressure loss for each sand. Prior to compartment optimization, an OHGP completion without packer placement was simulated in a dynamic simulation to generate the production profile as a base case. This was followed by a compartment optimization that was performed with OH mechanical packer placement at various standoff distances from the Gas-Water Contact (GWC) such as 5ft, 10ft, 15ft, 20ft and 30ft respectively. Subsequently, similar analysis was then performed on the CHGP completion design with a higher skin value estimated for the CHGP completion to reflect a higher degree of damage resulting from the cementing and perforation operations. Several production sensitivities were simulated by varying the perforation length and standoff from the GWC to replicate the same scenario of the open hole mechanical packer placement in the OHGP design analysis. Finally, analysis on the effectiveness of the base case (OHGP with no packer) against the cases of OHGP with optimum packer placement and CHGP with optimum perforation depth were compared and ranked over cumulative gas production, cumulative water production, operational complexity, and risk as well as total well cost. Based on the dynamic modelling, the base case (OHGP without packer) showed water breakthrough occurring right at the start of production as expected. Once breakthrough occured, water production would rapidly dominate production. On the other hand, packer placement sensitivity analysis for the OHGP design showed that the optimum depth for packer placement was 20ft or 30ft above the GWC depth where it provided highest gas cumulative and low
{"title":"Open Hole Gravel Pack with Mechanical Open Hole Isolation Packer: Cost Effective Alternative Solution for Water Influx Deferments in Sand Prone Multizone Gas Well","authors":"Asba Madzidah Binti Abu Bakar, M. M. H. B. Amjath Hussain, M. F. B. Bakar, Fuziana Binti Tusimin, A. Abdullah, Chee Seong Tan, Nicholas Moses","doi":"10.4043/31470-ms","DOIUrl":"https://doi.org/10.4043/31470-ms","url":null,"abstract":"\u0000 Originally, an infill well from project H was approved in 2013 to be completed as a single zone Open Hole Gravel Pack (OHGP) to produce gas commingled from three sands located at the shallowest reservoir in that field. Interpretation of recent logs from a nearby producing well indicated that there was significant water threat at two of the sands which would lead to water influx from the beginning of production if the well was to be completed as a single zone OHGP.\u0000 The well was then redesigned to be completed as a Cased Hole Gravel Pack (CHGP) in order to have mechanical isolation from the water zones with an inner string and internal isolation packers to allow feasibility of zonal isolation to shut off the water producing zone in the future. This feature however resulted in higher well cost as compared to the approved design.\u0000 Due to recent hostile low oil price, a more cost-effective sand control design was evaluated to reduce the well cost while maintaining similar performances as a CHGP design in terms of the capability to delay water breakthrough. Design feasibility study was performed on multizone OHGP with open hole mechanical packer and an inner string design to evaluate its performance and magnitude of cost reduction relative to a CHGP design.\u0000 Skin analysis was performed for both OHGP and CHGP completion designs to evaluate any additional pressure loss for each sand. Prior to compartment optimization, an OHGP completion without packer placement was simulated in a dynamic simulation to generate the production profile as a base case. This was followed by a compartment optimization that was performed with OH mechanical packer placement at various standoff distances from the Gas-Water Contact (GWC) such as 5ft, 10ft, 15ft, 20ft and 30ft respectively.\u0000 Subsequently, similar analysis was then performed on the CHGP completion design with a higher skin value estimated for the CHGP completion to reflect a higher degree of damage resulting from the cementing and perforation operations. Several production sensitivities were simulated by varying the perforation length and standoff from the GWC to replicate the same scenario of the open hole mechanical packer placement in the OHGP design analysis. Finally, analysis on the effectiveness of the base case (OHGP with no packer) against the cases of OHGP with optimum packer placement and CHGP with optimum perforation depth were compared and ranked over cumulative gas production, cumulative water production, operational complexity, and risk as well as total well cost.\u0000 Based on the dynamic modelling, the base case (OHGP without packer) showed water breakthrough occurring right at the start of production as expected. Once breakthrough occured, water production would rapidly dominate production. On the other hand, packer placement sensitivity analysis for the OHGP design showed that the optimum depth for packer placement was 20ft or 30ft above the GWC depth where it provided highest gas cumulative and low","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86263904","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}
Malikai Phase 2 project is a brownfield infill drilling project consisting of 5 new infill wells with 1 sidetrack scope. These new wells are tied into existing Malikai Tension Leg Platform (TLP) production facilities for offshore processing prior to export. Offshore execution activities were heavily congested with multiple works fronts from Drilling, Mooring, Hook-up Commissioning alongside existing production and maintenance operations of the Malikai facility requiring prioritization via simultaneous operations (SIMOPS) activities. The paper highlights the challenges of conventional radiography for inspection activities post pipework welding, which is usually scheduled within windows of low activities i.e. in the night with lower risk of personnel exposure to possible radiation. Since drilling operations runs 24 hours continuously, it renders almost impossible for conventional radiography inspection activities to take place as required. This paper also describes the benefits with the introduction of SAR technology, the radiation exclusion zone can be set to less than 5 meters, thus allowing the topsides facilities pipework welding to take place concurrent with drilling and operation activities, achieving project success factors of optimized manning requirement and earlier than plan First Oil Date (FOD). Advanced NDT technologies in the market like small area radiography and phased-array ultrasound were evaluated. Considering the piping diameter/wall thickness & material being Stainless Steel/Duplex SS (coarse grain welds – requires more extensive PAUT qualification), the final decision was to use SAR. A demo was conducted onshore with representation from various internal stakeholders. Necessary approvals from local regulatory bodies were obtained to facilitate the use of this technology for offshore assets. The team further evaluated the implementation in our offshore facilities in a HAZID workshop, collaborating with several contractors and asset counterpart to assess the hazards and risks associated with SAR. Results were then compared and used by the execution team to develop procedures suitable for offshore use. The paper compares past experiences of hook-up and commissioning activities using conventional radiography methods. By using SafeRad technology, the project can continue with the topsides' fabrication work simultaneously during drilling instead of conducting the pipework fabrication activities in series after drilling is completed. This allowed project team to be able to continue the fabrication works and subsequent pre-commissioning and commissioning activities whilst drilling in progress. As a result, project is able to liquidate the critical path in hook-up and commissioning activities and ultimately contributed to the project delivering early project ahead (circa 6 months) of the first oil milestone.
{"title":"Deployment of Small Area Exposure Radiography S.A.R Technology to Maximise Multiple Work Fronts in Operating Offshore Facility","authors":"Jothi Sivarajah, E. Hassan, J. Toh, Tee Bin Lim","doi":"10.4043/31511-ms","DOIUrl":"https://doi.org/10.4043/31511-ms","url":null,"abstract":"\u0000 Malikai Phase 2 project is a brownfield infill drilling project consisting of 5 new infill wells with 1 sidetrack scope. These new wells are tied into existing Malikai Tension Leg Platform (TLP) production facilities for offshore processing prior to export. Offshore execution activities were heavily congested with multiple works fronts from Drilling, Mooring, Hook-up Commissioning alongside existing production and maintenance operations of the Malikai facility requiring prioritization via simultaneous operations (SIMOPS) activities.\u0000 The paper highlights the challenges of conventional radiography for inspection activities post pipework welding, which is usually scheduled within windows of low activities i.e. in the night with lower risk of personnel exposure to possible radiation. Since drilling operations runs 24 hours continuously, it renders almost impossible for conventional radiography inspection activities to take place as required.\u0000 This paper also describes the benefits with the introduction of SAR technology, the radiation exclusion zone can be set to less than 5 meters, thus allowing the topsides facilities pipework welding to take place concurrent with drilling and operation activities, achieving project success factors of optimized manning requirement and earlier than plan First Oil Date (FOD).\u0000 Advanced NDT technologies in the market like small area radiography and phased-array ultrasound were evaluated. Considering the piping diameter/wall thickness & material being Stainless Steel/Duplex SS (coarse grain welds – requires more extensive PAUT qualification), the final decision was to use SAR. A demo was conducted onshore with representation from various internal stakeholders. Necessary approvals from local regulatory bodies were obtained to facilitate the use of this technology for offshore assets.\u0000 The team further evaluated the implementation in our offshore facilities in a HAZID workshop, collaborating with several contractors and asset counterpart to assess the hazards and risks associated with SAR. Results were then compared and used by the execution team to develop procedures suitable for offshore use.\u0000 The paper compares past experiences of hook-up and commissioning activities using conventional radiography methods. By using SafeRad technology, the project can continue with the topsides' fabrication work simultaneously during drilling instead of conducting the pipework fabrication activities in series after drilling is completed. This allowed project team to be able to continue the fabrication works and subsequent pre-commissioning and commissioning activities whilst drilling in progress. As a result, project is able to liquidate the critical path in hook-up and commissioning activities and ultimately contributed to the project delivering early project ahead (circa 6 months) of the first oil milestone.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85829279","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 process of running completions typically involves an increased complexity of systems and setups. The running of control lines and umbilicals have historically used hanging sheaves to route the lines from the spoolers to well center and require increased number of personnel in the red zone during operations. These complexities introduce many risks and potential incidents that operators aim to eliminate. Typical procedures for running completions require man-riding operations to hang sheaves in the derrick. Once the control lines or umbilicals are routed through these sheaves, they become overhead loaded objects and subsequently increase the risk of incident to personnel working on the rig floor. Other operational steps include the manual manipulation of lines to clamp the lines/umbilical to the tubular. This traditional clamping procedure not only requires an increased number of personnel in the red zone, but it also introduces inefficiencies to the operation. Through planning and the use of specialized remote manipulation technologies, operators can remove the need for overhead control line/umbilical sheaves and the manual handling of lines in the red zone. Although risks do not always result in incidents, organizations still strive to eliminate risks throughout their operations. By using remote manipulation technologies that eliminate control line/umbilical hanging sheaves, the operators benefit from the following: – Eliminating working at height for sheave installation – Eliminating overhead loaded components and increasing safety of personnel working on the rig floor – Decreasing the number of personnel required in the red zone and reducing manual handling – Increasing the efficiency of the operation By using systems like these, operators have been able to increase average running speeds, improving from 8.8 to 5.9 minutes per joint, as well as eliminate potentially fatal incidents that have occurred during the completions running process.
{"title":"Increasing the Safety and Efficiency of Completions with the Utilization of Remote Manipulation Systems and Elimination of Hanging Sheaves","authors":"Neil Alleman","doi":"10.4043/31464-ms","DOIUrl":"https://doi.org/10.4043/31464-ms","url":null,"abstract":"\u0000 The process of running completions typically involves an increased complexity of systems and setups. The running of control lines and umbilicals have historically used hanging sheaves to route the lines from the spoolers to well center and require increased number of personnel in the red zone during operations. These complexities introduce many risks and potential incidents that operators aim to eliminate.\u0000 Typical procedures for running completions require man-riding operations to hang sheaves in the derrick. Once the control lines or umbilicals are routed through these sheaves, they become overhead loaded objects and subsequently increase the risk of incident to personnel working on the rig floor. Other operational steps include the manual manipulation of lines to clamp the lines/umbilical to the tubular. This traditional clamping procedure not only requires an increased number of personnel in the red zone, but it also introduces inefficiencies to the operation. Through planning and the use of specialized remote manipulation technologies, operators can remove the need for overhead control line/umbilical sheaves and the manual handling of lines in the red zone.\u0000 Although risks do not always result in incidents, organizations still strive to eliminate risks throughout their operations. By using remote manipulation technologies that eliminate control line/umbilical hanging sheaves, the operators benefit from the following:\u0000 – Eliminating working at height for sheave installation – Eliminating overhead loaded components and increasing safety of personnel working on the rig floor – Decreasing the number of personnel required in the red zone and reducing manual handling – Increasing the efficiency of the operation\u0000 By using systems like these, operators have been able to increase average running speeds, improving from 8.8 to 5.9 minutes per joint, as well as eliminate potentially fatal incidents that have occurred during the completions running process.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86303432","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}
Mohd Rizal Mengan, Saiful Azuan Abdul Aziz, Nadirah Khairul Anuar, Grant Veroba, Jean-Michel Munoz
A group of International Oil and Gas Producer (IOGP) members have established the Normally Unattended Facilities (NUF) Task Force aimed to position NUF as safe, cost-effective, widely accepted design and operating method for oil & gas facilities. The establishment of the Task Force was driven by the need to standardize, expand the NUF concept to all type of facilities and ensure industry wide acceptance of NUF standardization. To meet these objectives, the Task Force has produced a white paper to outline the design principles, anticipated challenges and enablers to allow for the implementation of a standard NUF design. NUF will enable oil and gas facilities to be remotely operated in a safe and reliable manner with no crew visitation for determined periods of time. However, this requires a change in the approach to designing, constructing, operating, and maintaining the facility. The NUF Task Force focused on cost compression, unattended duration and sustainability through reduced carbon emissions as key objectives in NUF design optimization. The proposed NUF design will reduce carbon emissions through high reliability, low emission equipment selection and reduction of marine vessels utilization. Technology advancement will allow for lean design, remote control and analysis to efficiently and effectively plan maintenance and optimize operations. Brownfield quick wins will provide avenue for technology maturity, drive for higher reliability and improving overall asset performance. These help in shifting the mindset of personnel involved. Change management is required for governance & procedural changes whilst human retooling will be required for the new skillsets. The main value drivers that support NUF implementation include but, are not limited to, the anticipated reduction in HSE risk exposure to personnel, a substantial reduction in CAPEX and OPEX, and lower greenhouse gases, with reliability better than or equal to attended facilities. Some standards and regulations may need to be revised to enable NUF application. At present, this is being investigated by IOGP under JIP39. NUF concepts can be applied to any facility (onshore and offshore) and will be greatly facilitated by some level of standardization. This would create economies of scale for both the qualification and fabrication of equipment and sub-systems. Substantial potential value drivers supporting the move to a standard NUF approach: HSE Risk reduction due to elimination of personnel during normal operations Potential 20-30% CAPEX reduction in facility cost Potential 20-30% OPEX reduction in operating and logistics expenses Reliability better than or equal to attended facilities Green House Gases (GHG) footprint improvement
{"title":"Expanding Acceptance of Normally Unattended Facilities NUF – A Collaborative effort within IOGP","authors":"Mohd Rizal Mengan, Saiful Azuan Abdul Aziz, Nadirah Khairul Anuar, Grant Veroba, Jean-Michel Munoz","doi":"10.4043/31648-ms","DOIUrl":"https://doi.org/10.4043/31648-ms","url":null,"abstract":"\u0000 A group of International Oil and Gas Producer (IOGP) members have established the Normally Unattended Facilities (NUF) Task Force aimed to position NUF as safe, cost-effective, widely accepted design and operating method for oil & gas facilities. The establishment of the Task Force was driven by the need to standardize, expand the NUF concept to all type of facilities and ensure industry wide acceptance of NUF standardization. To meet these objectives, the Task Force has produced a white paper to outline the design principles, anticipated challenges and enablers to allow for the implementation of a standard NUF design.\u0000 NUF will enable oil and gas facilities to be remotely operated in a safe and reliable manner with no crew visitation for determined periods of time. However, this requires a change in the approach to designing, constructing, operating, and maintaining the facility. The NUF Task Force focused on cost compression, unattended duration and sustainability through reduced carbon emissions as key objectives in NUF design optimization. The proposed NUF design will reduce carbon emissions through high reliability, low emission equipment selection and reduction of marine vessels utilization. Technology advancement will allow for lean design, remote control and analysis to efficiently and effectively plan maintenance and optimize operations. Brownfield quick wins will provide avenue for technology maturity, drive for higher reliability and improving overall asset performance. These help in shifting the mindset of personnel involved. Change management is required for governance & procedural changes whilst human retooling will be required for the new skillsets.\u0000 The main value drivers that support NUF implementation include but, are not limited to, the anticipated reduction in HSE risk exposure to personnel, a substantial reduction in CAPEX and OPEX, and lower greenhouse gases, with reliability better than or equal to attended facilities. Some standards and regulations may need to be revised to enable NUF application. At present, this is being investigated by IOGP under JIP39.\u0000 NUF concepts can be applied to any facility (onshore and offshore) and will be greatly facilitated by some level of standardization. This would create economies of scale for both the qualification and fabrication of equipment and sub-systems.\u0000 Substantial potential value drivers supporting the move to a standard NUF approach:\u0000 HSE Risk reduction due to elimination of personnel during normal operations Potential 20-30% CAPEX reduction in facility cost Potential 20-30% OPEX reduction in operating and logistics expenses Reliability better than or equal to attended facilities Green House Gases (GHG) footprint improvement","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"2013 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87734676","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}
Mahakam Block is a huge oil and gas concession managed by PT. Pertamina Hulu Mahakam (PHM) and located in deltaic and offshore environment in East Kalimantan, Indonesia. Until today, the field has produced oil and gas for more than 50 years and categorized as "brown field" due to its declining production and marginal reserve potential. This condition has led to numerous effort to boost efficiency in well delivery from drilling perspective such that the reserve could be produced more economically. One of the effort that has been done to create a well to be more economical is by increasing the Rate of Penetration (ROP). An increase in ROP would directly impact on well duration that could be finished faster in such that it would also impact on much lower well cost. There are several key factors that influence ROP, yet the most crucial part is coming from drilling bit design that is used to drill the formation. Incompatibility between bit design with formation and directional drive type would often result in slow drilling progress and thus would make a well less profitable. To support this idea, the operator has launched a campaign called MAXIDRILL with aim to have a persistent excellent drilling performance from ROP perspective. Selective approach to different bit designs and bit suppliers has brought the operator to conduct the first trial in Indonesia utilizing a one inch PDC cutter drill bit. Besides the effort to increase well economics by increasing ROP using various bit designs through MAXIDRILL Campaign, PHM also tries to implement new set of well architecture dedicated specifically for developing the shallow hydrocarbon zone in Mahakam in general, and in Tunu Field in particular. With this new type of architecture, it allows drilling with 9-1/2″ hole to be done straight from 20″ Conductor Pipe down to well final target depth in single phase, where next 3-1/2″ production tubing will be run and cemented in place. The new design of architecture is called "One Phase Well". This novel innovation was initiated in 2019, where to date, the operator has drilled more than 30 wells without any incident. With the learning curve that has turned into industrialization steps. More and more shorter well duration is born with these two initiatives, MAXIDRILL and One Phase Well. Ultimately, with the spirit of these two initiatives for bringing down well duration in gain for much better well economics has successfully set a two record breaking performance in Mahakam: 1) Being the fastest On Bottom ROP and 2) Being the fastest well ever delivered in Mahakam and Indonesia which is under two days.
Mahakam区块是由PT. Pertamina Hulu Mahakam (PHM)管理的一个巨大的油气特许权，位于印度尼西亚东加里曼丹的三角洲和海上环境中。到目前为止，该油田已经生产了50多年的石油和天然气，由于其产量下降和边际储量潜力，被归类为“棕色油田”。从钻井的角度来看，这种情况导致了大量的努力来提高钻井效率，以便更经济地开采储量。为了提高经济效益，人们所做的一项努力是提高机械钻速(ROP)。机械钻速的提高将直接影响井的工期，从而可以更快地完成作业，从而大大降低井的成本。影响机械钻速的关键因素有几个，但最关键的部分是用于钻入地层的钻头设计。钻头设计与地层和定向驱动类型之间的不兼容通常会导致钻井进度缓慢，从而降低井的利润。为了支持这一想法，作业者发起了一项名为MAXIDRILL的活动，旨在从ROP的角度获得持续优异的钻井性能。通过选择不同的钻头设计和钻头供应商，作业者在印度尼西亚使用1英寸PDC切削钻头进行了首次试验。除了通过MAXIDRILL Campaign使用各种钻头设计提高机械钻速来提高井的经济效益外，PHM还试图实施一套新的井结构，专门用于开发Mahakam的浅层油气带，特别是在Tunu油田。采用这种新型结构，9-1/2″井眼可以直接从20″导电管到井的最终目标深度，在此阶段下入3-1/2″生产油管并进行固井。这种新的建筑设计被称为“一期井”。这项创新始于2019年，迄今为止，运营商已经钻了30多口井，没有发生任何事故。随着学习曲线转变为工业化的步骤。随着MAXIDRILL和One Phase well这两项计划的推出，井的持续时间越来越短。最终，凭借这两项举措的精神，缩短了井的持续时间，获得了更好的油井经济效益，成功地在Mahakam创造了两个破纪录的表现:1)成为最快的底部ROP; 2)在Mahakam和印度尼西亚，在两天内成为最快的交付井。
{"title":"Delivering a One Phase Well Under Two Days with a One Inch Cutter PDC Drill Bit: A Record Breaking Performance in Mature Field, Drilling Optimization Case History","authors":"B. Sayogyo, Aditya Hermawan, Bastian Andoni","doi":"10.4043/31638-ms","DOIUrl":"https://doi.org/10.4043/31638-ms","url":null,"abstract":"\u0000 Mahakam Block is a huge oil and gas concession managed by PT. Pertamina Hulu Mahakam (PHM) and located in deltaic and offshore environment in East Kalimantan, Indonesia. Until today, the field has produced oil and gas for more than 50 years and categorized as \"brown field\" due to its declining production and marginal reserve potential. This condition has led to numerous effort to boost efficiency in well delivery from drilling perspective such that the reserve could be produced more economically.\u0000 One of the effort that has been done to create a well to be more economical is by increasing the Rate of Penetration (ROP). An increase in ROP would directly impact on well duration that could be finished faster in such that it would also impact on much lower well cost. There are several key factors that influence ROP, yet the most crucial part is coming from drilling bit design that is used to drill the formation. Incompatibility between bit design with formation and directional drive type would often result in slow drilling progress and thus would make a well less profitable. To support this idea, the operator has launched a campaign called MAXIDRILL with aim to have a persistent excellent drilling performance from ROP perspective. Selective approach to different bit designs and bit suppliers has brought the operator to conduct the first trial in Indonesia utilizing a one inch PDC cutter drill bit.\u0000 Besides the effort to increase well economics by increasing ROP using various bit designs through MAXIDRILL Campaign, PHM also tries to implement new set of well architecture dedicated specifically for developing the shallow hydrocarbon zone in Mahakam in general, and in Tunu Field in particular. With this new type of architecture, it allows drilling with 9-1/2″ hole to be done straight from 20″ Conductor Pipe down to well final target depth in single phase, where next 3-1/2″ production tubing will be run and cemented in place. The new design of architecture is called \"One Phase Well\". This novel innovation was initiated in 2019, where to date, the operator has drilled more than 30 wells without any incident.\u0000 With the learning curve that has turned into industrialization steps. More and more shorter well duration is born with these two initiatives, MAXIDRILL and One Phase Well. Ultimately, with the spirit of these two initiatives for bringing down well duration in gain for much better well economics has successfully set a two record breaking performance in Mahakam: 1) Being the fastest On Bottom ROP and 2) Being the fastest well ever delivered in Mahakam and Indonesia which is under two days.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82471230","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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