Turbomachinery is recognized as one of the most important equipment in oil and gas facilities. Major issues identified are the monitoring of turbomachinery health condition; recognizing equipment failure patterns; reducing unplanned repair costs; ensuring uninterrupted production and avoiding unscheduled downtime. Thus, there is a need of innovative digital solution to address the highlighted issues. This paper will explain the transformation journey that has been endured by PETRONAS Upstream in crafting the journey in digitalizing the remote monitoring and operations for turbomachinery and major rotating equipment. The transformation journey started back in 2014 where the upstream assets were deploying various Original Equipment Manufacturer (OEM) remote monitoring solutions, which require additional hardware installation at site, significant capital expenditure and monthly subscription for each OEMThe strategy hit a setback when oil price went down which requires significant cost cutting measures. Applying the mantra of "Do More With Less", the asset collaborated with the Centre of Operational Excellence (CoE) to develop their own solution which was branded as Prescriptive Rotating Equipment Analytics (PROTEAN), which eventually replaced all OEM solutions in the long run. Defying the norm, all changed when the PETRONAS Upstream Operational Excellence team decided to embark on the digital journey by developing an in-house predictive analytics tool which is capable to identify anomalies trends, highlight potential incipient failures and identify opportunities for reliability improvement of the turbomachinery equipment. The pilot implementation was conducted in 2017 via implementation on 2 units of supercritical turbomachinery equipment. Following the the successful implementation, PROTEAN was upscaled and expanded to cover more than 200 units of major rotating equipment located at 23 offshore platforms, 6 onshore terminals located within Malaysia, International Assets as well as the world first Floating Liquified Natural Gas i.e. PETRONAS PFLNG Satu. PROTEAN+ provides a niche edge in supporting data driven maintenance, understanding the machinery deteroriation rate and justifying the extension of Mean Time Between Overhaul (MTBO). PROTEAN+ also provides the prescriptive analytics based on the Failure Mode and Effect Analysis (FMEA) of each specific rotating equipment. To date; PROTEAN has generated more than 700 alerts since 2017 resulting in USD50 Million of cost avoidance from unplanned production deferment and unplanned repair cost. The journey also covers the Technology Readiness Level (TRL) process which is vital in order to gain the confidence level from end users. As a conclusion, the paper will highlight the critical success factors and key lessons learned in a transformation journey for turbomachinery digital remote monitoring and operation. This paper shares the experience from the transformation journey on how the overall operatin
{"title":"The Transformation Journey and Key Critical Success Factors of Turbomachinery Digital Remote Monitoring","authors":"Harris Abd Rahman Sabri","doi":"10.4043/31342-ms","DOIUrl":"https://doi.org/10.4043/31342-ms","url":null,"abstract":"\u0000 Turbomachinery is recognized as one of the most important equipment in oil and gas facilities. Major issues identified are the monitoring of turbomachinery health condition; recognizing equipment failure patterns; reducing unplanned repair costs; ensuring uninterrupted production and avoiding unscheduled downtime. Thus, there is a need of innovative digital solution to address the highlighted issues. This paper will explain the transformation journey that has been endured by PETRONAS Upstream in crafting the journey in digitalizing the remote monitoring and operations for turbomachinery and major rotating equipment.\u0000 The transformation journey started back in 2014 where the upstream assets were deploying various Original Equipment Manufacturer (OEM) remote monitoring solutions, which require additional hardware installation at site, significant capital expenditure and monthly subscription for each OEMThe strategy hit a setback when oil price went down which requires significant cost cutting measures. Applying the mantra of \"Do More With Less\", the asset collaborated with the Centre of Operational Excellence (CoE) to develop their own solution which was branded as Prescriptive Rotating Equipment Analytics (PROTEAN), which eventually replaced all OEM solutions in the long run. Defying the norm, all changed when the PETRONAS Upstream Operational Excellence team decided to embark on the digital journey by developing an in-house predictive analytics tool which is capable to identify anomalies trends, highlight potential incipient failures and identify opportunities for reliability improvement of the turbomachinery equipment.\u0000 The pilot implementation was conducted in 2017 via implementation on 2 units of supercritical turbomachinery equipment. Following the the successful implementation, PROTEAN was upscaled and expanded to cover more than 200 units of major rotating equipment located at 23 offshore platforms, 6 onshore terminals located within Malaysia, International Assets as well as the world first Floating Liquified Natural Gas i.e. PETRONAS PFLNG Satu. PROTEAN+ provides a niche edge in supporting data driven maintenance, understanding the machinery deteroriation rate and justifying the extension of Mean Time Between Overhaul (MTBO). PROTEAN+ also provides the prescriptive analytics based on the Failure Mode and Effect Analysis (FMEA) of each specific rotating equipment. To date; PROTEAN has generated more than 700 alerts since 2017 resulting in USD50 Million of cost avoidance from unplanned production deferment and unplanned repair cost. The journey also covers the Technology Readiness Level (TRL) process which is vital in order to gain the confidence level from end users. As a conclusion, the paper will highlight the critical success factors and key lessons learned in a transformation journey for turbomachinery digital remote monitoring and operation.\u0000 This paper shares the experience from the transformation journey on how the overall operatin","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73149750","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. A. Abitalhah, Nurul Nadia Ezzatty Abu Bakar, M. Hod, Avinash Kishore Kumar, C. Lau, Mya Thuzar
This paper presents the success story of an exploration well in Malaysia evaluating the conventional approach of stacked cement plugs against the use of sacrificial tubing with a hydraulic disconnect sub system. Plug and Abandonment (P&A) is the process where the well is sealed permanently, and permanent well barrier must extend across the full cross section prior rig move. It is vital to ensure that plugged wells do not leak after abandonment, as there could be several potential leak paths or channeling from microannulus. Thus, well integrity shall be the utmost priority in designing the P&A strategy. Conventional P&A requires multiple cement plugs of a given length to be set and pressure tested, which could however be quite time-consuming and thus costly. The number of cement plugs will be based on the length of the open hole section, hydrocarbon zones presence or caprock to meet the P&A guidelines. The guidelines require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface. The thought process, design requirement both for the hardware and cement slurry, and execution follow through of a P&A approach with a sacrificial tubing method, driving for cost savings and operational efficiency will be elaborated. Some of the key points for replication based on lessons learnt are P&A with sacrificial tubing is economical justified for well scenario. As for the design, tubing centralizers or rotation is required in deviated hole for proper cement placement. Rotation of tubing during cementing is recommended for effective mud removal and cement placement for the case of no centralizer placement. This paper provides the novelty of the extensive planning, execution and improvement methods that will aid the project team to save cost and time in plug and abandonment (P&A) the well.
{"title":"Abandonment of Wells Under the New Norm – Sacrificial Tubing Approach","authors":"M. A. Abitalhah, Nurul Nadia Ezzatty Abu Bakar, M. Hod, Avinash Kishore Kumar, C. Lau, Mya Thuzar","doi":"10.4043/31369-ms","DOIUrl":"https://doi.org/10.4043/31369-ms","url":null,"abstract":"\u0000 This paper presents the success story of an exploration well in Malaysia evaluating the conventional approach of stacked cement plugs against the use of sacrificial tubing with a hydraulic disconnect sub system.\u0000 Plug and Abandonment (P&A) is the process where the well is sealed permanently, and permanent well barrier must extend across the full cross section prior rig move. It is vital to ensure that plugged wells do not leak after abandonment, as there could be several potential leak paths or channeling from microannulus. Thus, well integrity shall be the utmost priority in designing the P&A strategy.\u0000 Conventional P&A requires multiple cement plugs of a given length to be set and pressure tested, which could however be quite time-consuming and thus costly. The number of cement plugs will be based on the length of the open hole section, hydrocarbon zones presence or caprock to meet the P&A guidelines. The guidelines require that cement plugs be placed and tested across any open hydrocarbon-bearing formations, across all casing shoes, across freshwater aquifers, and perhaps several other areas near the surface.\u0000 The thought process, design requirement both for the hardware and cement slurry, and execution follow through of a P&A approach with a sacrificial tubing method, driving for cost savings and operational efficiency will be elaborated.\u0000 Some of the key points for replication based on lessons learnt are P&A with sacrificial tubing is economical justified for well scenario. As for the design, tubing centralizers or rotation is required in deviated hole for proper cement placement. Rotation of tubing during cementing is recommended for effective mud removal and cement placement for the case of no centralizer placement.\u0000 This paper provides the novelty of the extensive planning, execution and improvement methods that will aid the project team to save cost and time in plug and abandonment (P&A) the well.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"125 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89280083","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}
Formation evaluation and appraisal in Central Luconia carbonate reef is challenging when drilling operation change from conventional drilling to pressurised mud cap drilling (PMCD). PMCD drilling has always been the choice to deal with unmanageable losses condition. It is normally applied in carbonate reservoir with karst and vugs. Under this drilling condition, annular pressure and surface pressure is maintained above the formation that is able to take the cuttings and fluids. At the same time, light annular fluid is pumped down the annulus to maintain hole fill and avoid gas migration. Seawater, acts as sacrificial mud is pumped down the drill string to cool the bit and to transport the cuttings to loss zones. Meanwhile, for an exploration well, the primary objective is to prove hydrocarbon presence and hydrocarbon fluid contact through logging while drilling (LWD) as wireline logging is not favourable from operational perspective. One of the key challenges of interpreting hydrocarbon saturation in PMCD operation is suppression of resistivity value due to sea-water invasion. Indeed, with PMCD, the well is appeared to have high water saturation even though 1 MHz phase shift 36" spacing deep phase resistivity is used in the interpretation. However, this is inconsistent with gas kick occurred at the top of carbonate or gas shows prior to conversion from conventional drilling to PMCD operation. Another observation of resistivity log response in PMCD drilling is that the phase shift resistivity from different sensor spacing (6", 12", 24" and 36", with smaller number indicate shallower depth of investigation, and higher number indicate deeper depth of investigation) appears to have separation, which indicates invasion profile which happens at one time-frame. Although 1D inversion for true resistivity (Rt) can be carried out with multiple sensor spacing phase resistivity and invasion diameter (Di) as inputs, the inversion result does not yield satisfactory result that match pre-PMCD resistivity value. The objective of the paper/ abstract is to highlight the benefits or running dual – resistivity in LWD bottom-hole assembly (BHA) in PMCD well to capture time-lapse resistivity measurement, estimate Rt which is time-dependant and pin-pointing gas-water contact in the exploration/ appraisal wells. This new proposed concept and methodology is still at its early stage, yet designed to make better decision during operational time. Such an approach will provide benefits to petrophysics community in the PMCD well interpretation with minimal incremental cost.
随着钻井作业从常规钻井转向加压泥浆帽钻井(PMCD)， Central Luconia碳酸盐岩礁的地层评价与评价面临挑战。PMCD钻井一直是处理难以控制的漏失情况的选择。通常应用于具有岩溶和溶洞的碳酸盐岩储层。在这种钻井条件下，环空压力和地面压力保持在能够带走岩屑和流体的地层上方。同时，将轻质环空流体泵入环空，以保持井眼充填，避免气体运移。海水作为牺牲泥浆被泵入钻柱以冷却钻头并将岩屑输送到漏失层。同时，对于一口探井来说，主要目的是通过随钻测井(LWD)来证明油气的存在和油气流体的接触，因为从操作角度来看，电缆测井并不有利。在PMCD作业中，解释油气饱和度的关键挑战之一是由于海水侵入而抑制电阻率值。事实上，使用PMCD，即使在解释中使用1 MHz相移36”间距深相电阻率，该井的含水饱和度也很高。然而，这与常规钻井转换为PMCD作业之前发生在碳酸盐岩顶部或气层的气涌不一致。PMCD钻井中电阻率测井响应的另一个观察结果是，不同传感器间距(6”、12”、24”和36”，数值越小表示探测深度越浅，数值越大表示探测深度越深)的相移电阻率出现分离现象，表明入侵剖面发生在同一时间段。以多传感器间距相电阻率和侵入直径Di为输入，虽然可以进行真电阻率(Rt)的一维反演，但反演结果与pmcd前电阻率值并不匹配。本文的目的是强调在PMCD井的LWD底部钻具组合(BHA)中使用双电阻率的好处，以获取时移电阻率测量数据，估计随时间变化的Rt，并在勘探/评价井中精确定位气水接触。这个新提出的概念和方法仍处于早期阶段，但旨在在操作期间做出更好的决策。这种方法将以最小的增量成本为岩石物理学界提供PMCD井解释的好处。
{"title":"Hydrocarbon Saturation Determination in Case of Total Losses: Invasion Profile Modelling with Dual Resistivity – A Possible Application in PMCD Drilling","authors":"K. Ling, H. Zulkiply","doi":"10.4043/31353-ms","DOIUrl":"https://doi.org/10.4043/31353-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Formation evaluation and appraisal in Central Luconia carbonate reef is challenging when drilling operation change from conventional drilling to pressurised mud cap drilling (PMCD). PMCD drilling has always been the choice to deal with unmanageable losses condition. It is normally applied in carbonate reservoir with karst and vugs. Under this drilling condition, annular pressure and surface pressure is maintained above the formation that is able to take the cuttings and fluids. At the same time, light annular fluid is pumped down the annulus to maintain hole fill and avoid gas migration. Seawater, acts as sacrificial mud is pumped down the drill string to cool the bit and to transport the cuttings to loss zones.\u0000 Meanwhile, for an exploration well, the primary objective is to prove hydrocarbon presence and hydrocarbon fluid contact through logging while drilling (LWD) as wireline logging is not favourable from operational perspective. One of the key challenges of interpreting hydrocarbon saturation in PMCD operation is suppression of resistivity value due to sea-water invasion. Indeed, with PMCD, the well is appeared to have high water saturation even though 1 MHz phase shift 36\" spacing deep phase resistivity is used in the interpretation. However, this is inconsistent with gas kick occurred at the top of carbonate or gas shows prior to conversion from conventional drilling to PMCD operation. Another observation of resistivity log response in PMCD drilling is that the phase shift resistivity from different sensor spacing (6\", 12\", 24\" and 36\", with smaller number indicate shallower depth of investigation, and higher number indicate deeper depth of investigation) appears to have separation, which indicates invasion profile which happens at one time-frame. Although 1D inversion for true resistivity (Rt) can be carried out with multiple sensor spacing phase resistivity and invasion diameter (Di) as inputs, the inversion result does not yield satisfactory result that match pre-PMCD resistivity value. The objective of the paper/ abstract is to highlight the benefits or running dual – resistivity in LWD bottom-hole assembly (BHA) in PMCD well to capture time-lapse resistivity measurement, estimate Rt which is time-dependant and pin-pointing gas-water contact in the exploration/ appraisal wells. This new proposed concept and methodology is still at its early stage, yet designed to make better decision during operational time. Such an approach will provide benefits to petrophysics community in the PMCD well interpretation with minimal incremental cost.\u0000","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87872111","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the Netherlands, a large number of onshore wells are near urban areas or close to forests where environmental emission and noise reduction are important to consider. With more than 23 different well site locations to be abandoned, a significant amount of collaboration is required to ensure there is minimal interruption and impact to the local community and the environment. To achieve this, the operator together with Baker Hughes as the project management lead, formulated a unique, low-impact solution with fully electrified equipment that mostly uses grid power. Alongside other service partners, the majority of the onsite equipment are electrically driven, such as the rigless well abandonment unit, cement pumps, ancillary equipment, and the slickline unit. A noise dampener and decibel readers were put in place to minimize and track sound emissions. Such collaboration and integration with all providers were carefully identified and mitigated through a series of non-technical risks (NTRs) to ensure compliance with local regulations. Extra steps were taken to ensure that smell and noise remain unnoticed by the surrounding environment. Frequent communications are sent to the public by the operator to keep everyone informed prior to any mobilization. After a one-year campaign, there have been zero LTI, zero accidents, zero non-compliance incidents and above all, safe and secured end-of-life oil wells in an urban setting with many more to follow suit. This paper will provide insight into the integrated operations of a well abandonment project in a unique urban setting and the challenges to successfully abandon wells of varying complexity. This project is to be accomplished in compliance with the local mining and environmental regulations with no remaining liabilities, all while limiting total project costs. The supply chain stepped up by providing a cost-effective solution through multi-party collaboration, multi-skilling, technology innovation, and logistical solutions. The project planning, start-up phase, and an overview of the first year of operations will be presented.
{"title":"An Electrifying Integrated Solution Towards a Safe and Environmentally Sound Well Abandonment in Urban Setting","authors":"Syahnon Mohamad, L. Joppe","doi":"10.4043/31394-ms","DOIUrl":"https://doi.org/10.4043/31394-ms","url":null,"abstract":"\u0000 In the Netherlands, a large number of onshore wells are near urban areas or close to forests where environmental emission and noise reduction are important to consider. With more than 23 different well site locations to be abandoned, a significant amount of collaboration is required to ensure there is minimal interruption and impact to the local community and the environment.\u0000 To achieve this, the operator together with Baker Hughes as the project management lead, formulated a unique, low-impact solution with fully electrified equipment that mostly uses grid power. Alongside other service partners, the majority of the onsite equipment are electrically driven, such as the rigless well abandonment unit, cement pumps, ancillary equipment, and the slickline unit. A noise dampener and decibel readers were put in place to minimize and track sound emissions.\u0000 Such collaboration and integration with all providers were carefully identified and mitigated through a series of non-technical risks (NTRs) to ensure compliance with local regulations. Extra steps were taken to ensure that smell and noise remain unnoticed by the surrounding environment. Frequent communications are sent to the public by the operator to keep everyone informed prior to any mobilization.\u0000 After a one-year campaign, there have been zero LTI, zero accidents, zero non-compliance incidents and above all, safe and secured end-of-life oil wells in an urban setting with many more to follow suit.\u0000 This paper will provide insight into the integrated operations of a well abandonment project in a unique urban setting and the challenges to successfully abandon wells of varying complexity. This project is to be accomplished in compliance with the local mining and environmental regulations with no remaining liabilities, all while limiting total project costs. The supply chain stepped up by providing a cost-effective solution through multi-party collaboration, multi-skilling, technology innovation, and logistical solutions. The project planning, start-up phase, and an overview of the first year of operations will be presented.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85939653","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. H. Ariffin, Ryan Guillory, Bee Chan Low, F. A. Salleh
Greenhouse gas emission (GHG) is the main contributor to global warming, so the industry players need to take a huge step to reduce GHG. Furthermore, the implementation of carbon tax has eroded oil project values and drives teams to think about ways to reduce the carbon tax. This paper highlights the subsurface studies, gas balancing method, and surface modification effort to reduce the gas emission in Field B while reaping the benefits not just of reduced carbon tax but increased oil production and revenue. Gas injection is not just increasing reservoir pressure but also reduces emission. Several reservoirs in the field have been depleted by 66% to 500 psi. The team converted the existing oil wells to gas injection wells instead of spending high CAPEX to drill new gas injection well. This way the team can confirm the benefit of gas injection with a low-risk cash injection. The field has a high amount of unproduced Non-Associated Gas (NAG), but this NAG cannot be produced without a gas evacuation plan. Producing the NAG will cause the field to vent higher with existing facilities installations. So, the team came out with a plan to monetize the gas by installing a new gas pipeline and new gas processing platform. Furthermore, the Associated Gas (AG) which was vented previously can be channeled to the new compression system to further reduce the emission. Currently, the gas from the surge tank is lined up straight to the vent stack. A Vapour Recovery Unit (VRU) was proposed to install upstream of the surge vessels. The VRU will pump the gas back to an AG gas compressor and straight to the gas sales line. The gas injection project has increased the reservoir pressure from 500 psi to 700 psi. As a result, one idle well reactivated to produce oil, two wells were drilled from the same reservoir, and gas venting was reduced by up to 7 MMscf/d. Because of this success, several other wells were identified for gas injection candidates in other reservoirs. NAG gas project is expected to provide 100 MMscf/d revenue. In addition to that, the NAG project also helps to reduce AG venting because of AG compressor limitations. The additional AG volumes are around 5 MMscf/d. VRU installation is still undergoing doability and commerciality study because the gas from the surge vessel is minimal. However, the team's dream towards zero gas emission is a step closer if VRU installation is brought forward. Because the field is not well equipped with a gas meter for each piece of equipment. An accurate and understanding of gas balance estimation is important to drive zero gas emission.
{"title":"Striving Towards Zero Gas Emission","authors":"M. H. Ariffin, Ryan Guillory, Bee Chan Low, F. A. Salleh","doi":"10.4043/31392-ms","DOIUrl":"https://doi.org/10.4043/31392-ms","url":null,"abstract":"\u0000 Greenhouse gas emission (GHG) is the main contributor to global warming, so the industry players need to take a huge step to reduce GHG. Furthermore, the implementation of carbon tax has eroded oil project values and drives teams to think about ways to reduce the carbon tax.\u0000 This paper highlights the subsurface studies, gas balancing method, and surface modification effort to reduce the gas emission in Field B while reaping the benefits not just of reduced carbon tax but increased oil production and revenue.\u0000 Gas injection is not just increasing reservoir pressure but also reduces emission. Several reservoirs in the field have been depleted by 66% to 500 psi. The team converted the existing oil wells to gas injection wells instead of spending high CAPEX to drill new gas injection well. This way the team can confirm the benefit of gas injection with a low-risk cash injection.\u0000 The field has a high amount of unproduced Non-Associated Gas (NAG), but this NAG cannot be produced without a gas evacuation plan. Producing the NAG will cause the field to vent higher with existing facilities installations. So, the team came out with a plan to monetize the gas by installing a new gas pipeline and new gas processing platform. Furthermore, the Associated Gas (AG) which was vented previously can be channeled to the new compression system to further reduce the emission.\u0000 Currently, the gas from the surge tank is lined up straight to the vent stack. A Vapour Recovery Unit (VRU) was proposed to install upstream of the surge vessels. The VRU will pump the gas back to an AG gas compressor and straight to the gas sales line.\u0000 The gas injection project has increased the reservoir pressure from 500 psi to 700 psi. As a result, one idle well reactivated to produce oil, two wells were drilled from the same reservoir, and gas venting was reduced by up to 7 MMscf/d. Because of this success, several other wells were identified for gas injection candidates in other reservoirs.\u0000 NAG gas project is expected to provide 100 MMscf/d revenue. In addition to that, the NAG project also helps to reduce AG venting because of AG compressor limitations. The additional AG volumes are around 5 MMscf/d.\u0000 VRU installation is still undergoing doability and commerciality study because the gas from the surge vessel is minimal. However, the team's dream towards zero gas emission is a step closer if VRU installation is brought forward.\u0000 Because the field is not well equipped with a gas meter for each piece of equipment. An accurate and understanding of gas balance estimation is important to drive zero gas emission.","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":"86602993","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}
Junling Wan, Xiang Wu, B. Chang, Chao Wang, Gong Li, Fei Wang, Y. Shim
At the in-depth development phase, the current horizontal infill campaign in H oil field targets reservoirs with high remaining oil potential and the diverse complexities subject to both structural and lithological controls. These structural and lithological reservoirs are characterized by the uncertainties of formation dip and oil/water contact (OWC), severe stratigraphic heterogeneity, lateral properties change, poor sandstone connectivity, and thickness variation (less than 5 m) of the oil column and interbeds. To effectively squeeze the potential remaining reserves, the scope of the current infill campaign mainly encompasses: (1) the limited crests of the anticlinal traps with uncertain oil column and lateral changed reservoir, and (2) the unexploited marginal areas close to the reservoir pinchout line. Accordingly, it is necessary to quantitatively update the reservoir-scale subsurface profile and execute well placement operations by addressing the above uncertainties with individualized services and workflow. In these diverse reservoirs, interwell structural and stratigraphic uncertainties are high because resolution of large-scale seismic data and depth-of-investigation (DOI) of small-scale conventional logging data are limited. On these grounds, a high-definition boundary detection service (HDBDS) was employed, which can provide a stochastic resistivity inversion to remotely identify quantitative subsurface features with DOI up to 6 m and resolution of approximately 1 m. Its advantage of balancing resolution and DOI can induce the accurate description of high-definition interwell details, including formation superposition configuration, reservoir pinchout points, and dynamic OWC. Furthermore, HDBDS inversion can combine 3D seismic data and conventional logging data to effectively induce the workflow from subsurface uncertainty management to the quantitative reservoir-scale profile update and well placement. HDBDS inversion-derived workflow effectively contributed to us achieving our objectives of this infill campaign by generally revealing the high-definition reservoir profiles along the horizontal sections. Up to four boundaries and five layers were mapped simultaneously with a maximum of 3 m distance from the borehole. High coverage and probability of the updated quantitative features induced the higher reservoir profile update rate in these specific environments than that based on the conventional services. In the complex developed areas mainly subject to both structural and lithological controls, the reservoir top, lateral changed properties, and dynamic tilted OWC were quantitatively inverted to identify the effective 1.5- to 3-m oil column, lower than prognosed 5-m column. In the lithological-control reservoirs at block margins, formation superposition configuration, pinchout points, and lateral properties changing features were clearly delineated. Accordingly, the quantitative well placement operations were efficiently executed
{"title":"Resistivity-Inversion-Derived Workflow from the Subsurface Uncertainty Management to the Quantitative Reservoir-Scale Profile Update and Well Placement in Reservoirs with Diverse Complexities","authors":"Junling Wan, Xiang Wu, B. Chang, Chao Wang, Gong Li, Fei Wang, Y. Shim","doi":"10.4043/31532-ms","DOIUrl":"https://doi.org/10.4043/31532-ms","url":null,"abstract":"\u0000 At the in-depth development phase, the current horizontal infill campaign in H oil field targets reservoirs with high remaining oil potential and the diverse complexities subject to both structural and lithological controls. These structural and lithological reservoirs are characterized by the uncertainties of formation dip and oil/water contact (OWC), severe stratigraphic heterogeneity, lateral properties change, poor sandstone connectivity, and thickness variation (less than 5 m) of the oil column and interbeds. To effectively squeeze the potential remaining reserves, the scope of the current infill campaign mainly encompasses: (1) the limited crests of the anticlinal traps with uncertain oil column and lateral changed reservoir, and (2) the unexploited marginal areas close to the reservoir pinchout line. Accordingly, it is necessary to quantitatively update the reservoir-scale subsurface profile and execute well placement operations by addressing the above uncertainties with individualized services and workflow.\u0000 In these diverse reservoirs, interwell structural and stratigraphic uncertainties are high because resolution of large-scale seismic data and depth-of-investigation (DOI) of small-scale conventional logging data are limited. On these grounds, a high-definition boundary detection service (HDBDS) was employed, which can provide a stochastic resistivity inversion to remotely identify quantitative subsurface features with DOI up to 6 m and resolution of approximately 1 m. Its advantage of balancing resolution and DOI can induce the accurate description of high-definition interwell details, including formation superposition configuration, reservoir pinchout points, and dynamic OWC. Furthermore, HDBDS inversion can combine 3D seismic data and conventional logging data to effectively induce the workflow from subsurface uncertainty management to the quantitative reservoir-scale profile update and well placement.\u0000 HDBDS inversion-derived workflow effectively contributed to us achieving our objectives of this infill campaign by generally revealing the high-definition reservoir profiles along the horizontal sections. Up to four boundaries and five layers were mapped simultaneously with a maximum of 3 m distance from the borehole. High coverage and probability of the updated quantitative features induced the higher reservoir profile update rate in these specific environments than that based on the conventional services. In the complex developed areas mainly subject to both structural and lithological controls, the reservoir top, lateral changed properties, and dynamic tilted OWC were quantitatively inverted to identify the effective 1.5- to 3-m oil column, lower than prognosed 5-m column. In the lithological-control reservoirs at block margins, formation superposition configuration, pinchout points, and lateral properties changing features were clearly delineated. Accordingly, the quantitative well placement operations were efficiently executed","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82224380","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}
Biramarta Isnadi, Suhaimi Mahasan, Syahnaz Omar, W. H. Fazli, Yusuf Sahari, Ave Suhendra, Ellis Wong, Aiman Kamaruzaman, R. Khan
This paper describes the SPM Integrity Management approach using risk based strategies for Single Point Mooring (SPM) throughout its asset life cycle, to ensure that there is a structural integrity management processes are implemented and SPM asset fitness for purpose is always maintained. SPM is one of the most important assets for any oil and gas upstream business, as its primary function is for product export and offloading operations. PETRONAS UPSTREAM currently operate seven (7) Single Point Mooring (SPM) assets for its Malaysia Upstream/ Downstream. To manage the integrity of the SPMs, an Integrity Management system has been developed and includes newer assets and those that are approaching or exceeding design lives. To optimize and focus limited resources toward critical activities, a SPM risk-based strategy and methodology for the SPM assets has been developed. The risk based inspection approach is aligned with the Structural Integrity Management (SIM) processes of DATA, EVALUATION, STRATEGY PROGRAM of the API RP2SIM code of practice. A qualitative risk based integrity management has been developed and for its implementation, inspection and maintenance activities shall target high expenditure items. SPM design, characteristic, assessment, and inspection data have been compiled and utilized in the risk based approach development. With this risk-based approach, PETRONAS can optimize and significantly reduce its inspection and maintenance activities whilst keeping operational risk levels within acceptable limits. The risk-based approach provides that added advantage to look at inspections and maintenance activities critically and make informed decisions on resourcing and aligning inspection & maintenance campaigns for the future. Inspection and maintenance measures also include an anomaly management, RBI, data management and inspections scopes of work which are being digitized and maintained within the Company's Structural Integrity Compliance System (SICS).
{"title":"A Risk Based Approach for the Integrity Management of Single Point Mooring Systems","authors":"Biramarta Isnadi, Suhaimi Mahasan, Syahnaz Omar, W. H. Fazli, Yusuf Sahari, Ave Suhendra, Ellis Wong, Aiman Kamaruzaman, R. Khan","doi":"10.4043/31405-ms","DOIUrl":"https://doi.org/10.4043/31405-ms","url":null,"abstract":"\u0000 This paper describes the SPM Integrity Management approach using risk based strategies for Single Point Mooring (SPM) throughout its asset life cycle, to ensure that there is a structural integrity management processes are implemented and SPM asset fitness for purpose is always maintained. SPM is one of the most important assets for any oil and gas upstream business, as its primary function is for product export and offloading operations. PETRONAS UPSTREAM currently operate seven (7) Single Point Mooring (SPM) assets for its Malaysia Upstream/ Downstream. To manage the integrity of the SPMs, an Integrity Management system has been developed and includes newer assets and those that are approaching or exceeding design lives.\u0000 To optimize and focus limited resources toward critical activities, a SPM risk-based strategy and methodology for the SPM assets has been developed. The risk based inspection approach is aligned with the Structural Integrity Management (SIM) processes of DATA, EVALUATION, STRATEGY PROGRAM of the API RP2SIM code of practice. A qualitative risk based integrity management has been developed and for its implementation, inspection and maintenance activities shall target high expenditure items. SPM design, characteristic, assessment, and inspection data have been compiled and utilized in the risk based approach development.\u0000 With this risk-based approach, PETRONAS can optimize and significantly reduce its inspection and maintenance activities whilst keeping operational risk levels within acceptable limits. The risk-based approach provides that added advantage to look at inspections and maintenance activities critically and make informed decisions on resourcing and aligning inspection & maintenance campaigns for the future.\u0000 Inspection and maintenance measures also include an anomaly management, RBI, data management and inspections scopes of work which are being digitized and maintained within the Company's Structural Integrity Compliance System (SICS).","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"174 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91006317","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. Guzmán, Thanushya Krishnan, Yong Chin Gwee, Yvonne Wu
A subsea well in Deepwater field in Malaysia observed high sand production during the first half of 2019, this well had been on production for around 7 years. Further evaluation during the second half of 2019 determined that the downhole sand control had been compromised and the well would require intervention to bring back its locked in potential. Technical and Economical evaluations were conducted to determine the most feasible well restoration activity. This paper covers the aspects from technology selection to operation challenges and identified solutions. Riserless well intervention was initially identified to restore production from this well and compared with other alternatives. After technical and economical evaluations, the use of a surface desander was identified as the best solution to unlock production from this well while a more permanent solution was evaluated. A surface desander was installed upstream of first stage separation. Well and facilities operating envelopes were updated to determine the operating window for the well as per last observed conditions before the well was shut in. However, once the well was back online a much higher than anticipated watercut was observed and different solutions, in term of surface settings, were tested to determine a new operation window. The use of surface desander to handle subsea sand control failure requires a steady flow against a significant choke to the flowline at the end of the riser. Changes in reservoir watercut provided a significant challenge to flow the well at steady conditions and limited the efficacy of surface desander. Flow assurance is a key parameter to avoid sand deposition along the subsea flowline to the platform. Use of a neighbor well proved to allow continuous steady production and a new logic was designed to maximize production from both wells while keeping sand from reaching the production facilities.
{"title":"Use of Surface Desander to Bring Back Subsea Production. How to Overcome Reservoir, Well and Facilities Challenges","authors":"M. Guzmán, Thanushya Krishnan, Yong Chin Gwee, Yvonne Wu","doi":"10.4043/31610-ms","DOIUrl":"https://doi.org/10.4043/31610-ms","url":null,"abstract":"\u0000 A subsea well in Deepwater field in Malaysia observed high sand production during the first half of 2019, this well had been on production for around 7 years. Further evaluation during the second half of 2019 determined that the downhole sand control had been compromised and the well would require intervention to bring back its locked in potential. Technical and Economical evaluations were conducted to determine the most feasible well restoration activity. This paper covers the aspects from technology selection to operation challenges and identified solutions.\u0000 Riserless well intervention was initially identified to restore production from this well and compared with other alternatives. After technical and economical evaluations, the use of a surface desander was identified as the best solution to unlock production from this well while a more permanent solution was evaluated. A surface desander was installed upstream of first stage separation. Well and facilities operating envelopes were updated to determine the operating window for the well as per last observed conditions before the well was shut in. However, once the well was back online a much higher than anticipated watercut was observed and different solutions, in term of surface settings, were tested to determine a new operation window.\u0000 The use of surface desander to handle subsea sand control failure requires a steady flow against a significant choke to the flowline at the end of the riser. Changes in reservoir watercut provided a significant challenge to flow the well at steady conditions and limited the efficacy of surface desander.\u0000 Flow assurance is a key parameter to avoid sand deposition along the subsea flowline to the platform. Use of a neighbor well proved to allow continuous steady production and a new logic was designed to maximize production from both wells while keeping sand from reaching the production facilities.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90168322","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}
Abdallah Magdy Darwish, A. K. Khalil, Mohamed El-Hussein El-Dessouky, Islam Ibrahim Mohamed, Tamer Hosny Abdelhalem
Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in "E" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production. An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy. The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline. This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.
{"title":"Preventing Halite Scaling in Offshore Pipelines Using Integrated Scale Management System and Modeling – Case Study from Gulf of Suez, Egypt","authors":"Abdallah Magdy Darwish, A. K. Khalil, Mohamed El-Hussein El-Dessouky, Islam Ibrahim Mohamed, Tamer Hosny Abdelhalem","doi":"10.4043/31455-ms","DOIUrl":"https://doi.org/10.4043/31455-ms","url":null,"abstract":"\u0000 Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in \"E\" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production.\u0000 An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy.\u0000 The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline.\u0000 This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89078134","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}
Krongrath Suwannasri, Cheong Yaw Peng, S. Asawachaisujja, R. Uttareun, O. Limpornpipat, A. Suphawajruksakul, P. Chongrueanglap
Capturing the reservoir heterogeneity is crucial for optimizing field development. Lang-Lebah field is a Miocene carbonate platform with approximately 5 sq.km. in size and over 1 km in height with a high degree of heterogeneity in both vertical and horizontal directions. In this study, we conducted a seismic-based characterization to capture reservoir heterogeneity and then ran sequential gaussian simulation with a data from wells to build a static model for field development purpose. The method mainly comprises of four steps. The first step is to establish a relationship between reservoir properties (such as facie and porosity) to elastic properties (such as P- and S-wave impedances) to build conditional probability. The second step is running pre-stack inversion to derive P- and S-wave impedances as inputs for the third step. The posterior probability of each facie is determined through Bayesian classification using inverted impedances and the derived conditional probability as inputs. The last step is employing sequential gaussian simulation to build a static model using derived posterior probability of each facie and porosity cube. The static model encapsulates heterogeneity in terms of carbonate facie and reservoir properties. The observed heterogeneity is highly consistent with the understanding of geological model of this carbonate platform. The result shows lateral heterogeneity in each zone of high energy facies (such as reef margin) at the windward flank of the platform and low energy facies (such as lake) at platform interior. Thus, this result was elaborated for geological concept beyond the using well data alone. The result also shows a vertical succession from different carbonate reservoir deposit regarding to accommodation as carbonate build-out to a typical carbonate platform build-up continue to carbonate build-in. In addition, flooding event or surfaces, which is part of reservoir barrier, was also identified and included in this static model. The details of this successful novel study lay a fundamental work process for battling the challenge of gigantic carbonate characterization for field development. Because of this sophisticated model, we can properly plan the sequence of production and producing well targeting based on the derived reservoir heterogeneity resulting in enabling several Tscf of reserves and minimizing development costs.
{"title":"Encapsulating Complex Carbonate Facie Heterogeneity into Static Reservoir Model through Seismic-Based Characterization, Lang-Lebah Field, Central Luconia, Offshore Sarawak","authors":"Krongrath Suwannasri, Cheong Yaw Peng, S. Asawachaisujja, R. Uttareun, O. Limpornpipat, A. Suphawajruksakul, P. Chongrueanglap","doi":"10.4043/31517-ms","DOIUrl":"https://doi.org/10.4043/31517-ms","url":null,"abstract":"\u0000 Capturing the reservoir heterogeneity is crucial for optimizing field development. Lang-Lebah field is a Miocene carbonate platform with approximately 5 sq.km. in size and over 1 km in height with a high degree of heterogeneity in both vertical and horizontal directions. In this study, we conducted a seismic-based characterization to capture reservoir heterogeneity and then ran sequential gaussian simulation with a data from wells to build a static model for field development purpose.\u0000 The method mainly comprises of four steps. The first step is to establish a relationship between reservoir properties (such as facie and porosity) to elastic properties (such as P- and S-wave impedances) to build conditional probability. The second step is running pre-stack inversion to derive P- and S-wave impedances as inputs for the third step. The posterior probability of each facie is determined through Bayesian classification using inverted impedances and the derived conditional probability as inputs. The last step is employing sequential gaussian simulation to build a static model using derived posterior probability of each facie and porosity cube.\u0000 The static model encapsulates heterogeneity in terms of carbonate facie and reservoir properties. The observed heterogeneity is highly consistent with the understanding of geological model of this carbonate platform. The result shows lateral heterogeneity in each zone of high energy facies (such as reef margin) at the windward flank of the platform and low energy facies (such as lake) at platform interior. Thus, this result was elaborated for geological concept beyond the using well data alone. The result also shows a vertical succession from different carbonate reservoir deposit regarding to accommodation as carbonate build-out to a typical carbonate platform build-up continue to carbonate build-in. In addition, flooding event or surfaces, which is part of reservoir barrier, was also identified and included in this static model.\u0000 The details of this successful novel study lay a fundamental work process for battling the challenge of gigantic carbonate characterization for field development. Because of this sophisticated model, we can properly plan the sequence of production and producing well targeting based on the derived reservoir heterogeneity resulting in enabling several Tscf of reserves and minimizing development costs.","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":"81337929","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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