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}
Yong Chin Gwee, Grace Chin, Chee Hou. Chan, Lee San Chua, Jason Ling, Yvonne Wu
A subsea production flexible flowline in Gumusut-Kakap field was found blocked in March 2021 during a routine production well-flowline switching/alignment operation. Further evaluation showed that the blockage was caused by the formation of hydrate and gel over the 1.3km length of the flexible flowline, as the live crude and water were left stagnant and untreated in the flowline over a prolonged period. This paper covers the remediation strategy and the associated challenges from a System perspective, which successfully unblocked the flowline within a relatively short period of time. The condition of the blockage in the flexible flowline was simulated using a commercial multiphase dynamic software to ascertain the phase distribution and hence allowed the estimation of the location and length of hydrate, gel, and emulsion in the flowline which has a downward inclination of circa 50 meters height. Heating (from production well), methanol (MeOH) soaking and flowline depressurization were planned and executed. In addition to the technical methodology, the System-wide aspects were also considered for the effective and optimum execution of the remediation activities which include attempting to fulfill the production commitment, abide by the subsea hardware and flexible flowline integrity envelope, and consider the impact of the remediation operation on other operations at the Gumusut-Kakap installation. The MeOH soaking, flowline depressurization and pressurization successfully remediated the blockage over the period of weeks. Positive results were observed at the start of the remediation when the targeted location for MeOH contact and depressurization were identified via field trial. One of the key challenges is the time factor in which to ascertain the "appropriate" waiting time for the flowline depressurization, as the remediation involved partial shut-in of the prolific production wells. A holistic System engineering approach is critical to the successful remediation of the blockage, integrating the key technical requirements as well as the soft and non-technical aspects to deliver optimum and net positive value for the asset.
{"title":"Remediation of A Complex Blockage for Gumusut-Kakap Subsea Flexible Flowline from a System Perspective","authors":"Yong Chin Gwee, Grace Chin, Chee Hou. Chan, Lee San Chua, Jason Ling, Yvonne Wu","doi":"10.4043/31422-ms","DOIUrl":"https://doi.org/10.4043/31422-ms","url":null,"abstract":"A subsea production flexible flowline in Gumusut-Kakap field was found blocked in March 2021 during a routine production well-flowline switching/alignment operation. Further evaluation showed that the blockage was caused by the formation of hydrate and gel over the 1.3km length of the flexible flowline, as the live crude and water were left stagnant and untreated in the flowline over a prolonged period. This paper covers the remediation strategy and the associated challenges from a System perspective, which successfully unblocked the flowline within a relatively short period of time.\u0000 The condition of the blockage in the flexible flowline was simulated using a commercial multiphase dynamic software to ascertain the phase distribution and hence allowed the estimation of the location and length of hydrate, gel, and emulsion in the flowline which has a downward inclination of circa 50 meters height. Heating (from production well), methanol (MeOH) soaking and flowline depressurization were planned and executed. In addition to the technical methodology, the System-wide aspects were also considered for the effective and optimum execution of the remediation activities which include attempting to fulfill the production commitment, abide by the subsea hardware and flexible flowline integrity envelope, and consider the impact of the remediation operation on other operations at the Gumusut-Kakap installation.\u0000 The MeOH soaking, flowline depressurization and pressurization successfully remediated the blockage over the period of weeks. Positive results were observed at the start of the remediation when the targeted location for MeOH contact and depressurization were identified via field trial. One of the key challenges is the time factor in which to ascertain the \"appropriate\" waiting time for the flowline depressurization, as the remediation involved partial shut-in of the prolific production wells.\u0000 A holistic System engineering approach is critical to the successful remediation of the blockage, integrating the key technical requirements as well as the soft and non-technical aspects to deliver optimum and net positive value for the asset.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79893578","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}
Ariel Lyons, A. Salehpour, C. Azwar, Mahdi Sheikh Veisi, Lynden Duthie, Steven Marshall
Analysis has consistently shown that carbon capture and storage (CCS) has an important role in meeting emission-reduction targets (IPCC, 2018). CCS wells require special design considerations to ensure long-term zonal isolation when exposed to carbon dioxide (CO2) because a complex set of chemical reactions leads to carbonation and dissolution of conventional cement sheaths. Several studies conducted into the long-term stability of different cement systems when exposed to wet supercritical CO2 and CO2-saturated water showed that the novel CO2- resistant cement system provides enduring zonal isolation. Properties investigated included permeability, porosity, mass evolution, CO2 degradation front, and compressive strength. Given its superior mechanical properties, the novel CO2-resistant cement system was selected for use in the first Australian offshore CCS Gular-1 appraisal well. To ensure that the blend characteristics of the novel CO2-resistant cement system remained optimal, a stringent quality-control procedure was developed. The blend management process, supported by rigorous laboratory testing, covered the complete lifecycle of the blend. This lifecycle extended from sourcing chemical components, to blending the components in a bulk plant, to transporting the blend across land and sea, and ultimately, preparing the slurry mixing. By adhering to the project management process, all primary cement jobs were successfully performed without incident using conventional cementing equipment and practices. The novel approach of blending the product locally at a fit-for-purpose facility reduced costs compared with previous methods of importing a preblended product prepared at a special centralized facility. Blend homogeneity was maintained during transfer from a sea vessel to the jackup rig, with minimal change in density between samples received from the bulk plant and samples received from the rig. This blending, which verified the initial blend flow capability and the robustness tests performed at a regional laboratory using specialized equipment, concluded the blend is suitable for offshore operations. Selection of a suitable cement system to ensure long-term zonal isolation will prove essential to the continuing expansion of the CO2 injection market. Through this offshore CCS appraisal project, valuable best practices and lessons learned in design and execution have been captured. This paper presents the decision process used for selecting a suitable CO2-resistant cement system for Australia's first offshore CCS appraisal well, drilled by AGR as part of the CarbonNet Project in late 2019, as well as the project management processes implemented to ensure successful job execution. The experiences detailed in this paper will benefit other operators confronted by challenges associated with wells subjected to CO2 injection.
{"title":"Cementing the First Australian Offshore Carbon Capture and Storage Appraisal Well","authors":"Ariel Lyons, A. Salehpour, C. Azwar, Mahdi Sheikh Veisi, Lynden Duthie, Steven Marshall","doi":"10.4043/31562-ms","DOIUrl":"https://doi.org/10.4043/31562-ms","url":null,"abstract":"\u0000 Analysis has consistently shown that carbon capture and storage (CCS) has an important role in meeting emission-reduction targets (IPCC, 2018). CCS wells require special design considerations to ensure long-term zonal isolation when exposed to carbon dioxide (CO2) because a complex set of chemical reactions leads to carbonation and dissolution of conventional cement sheaths.\u0000 Several studies conducted into the long-term stability of different cement systems when exposed to wet supercritical CO2 and CO2-saturated water showed that the novel CO2- resistant cement system provides enduring zonal isolation. Properties investigated included permeability, porosity, mass evolution, CO2 degradation front, and compressive strength. Given its superior mechanical properties, the novel CO2-resistant cement system was selected for use in the first Australian offshore CCS Gular-1 appraisal well.\u0000 To ensure that the blend characteristics of the novel CO2-resistant cement system remained optimal, a stringent quality-control procedure was developed. The blend management process, supported by rigorous laboratory testing, covered the complete lifecycle of the blend. This lifecycle extended from sourcing chemical components, to blending the components in a bulk plant, to transporting the blend across land and sea, and ultimately, preparing the slurry mixing.\u0000 By adhering to the project management process, all primary cement jobs were successfully performed without incident using conventional cementing equipment and practices. The novel approach of blending the product locally at a fit-for-purpose facility reduced costs compared with previous methods of importing a preblended product prepared at a special centralized facility. Blend homogeneity was maintained during transfer from a sea vessel to the jackup rig, with minimal change in density between samples received from the bulk plant and samples received from the rig. This blending, which verified the initial blend flow capability and the robustness tests performed at a regional laboratory using specialized equipment, concluded the blend is suitable for offshore operations.\u0000 Selection of a suitable cement system to ensure long-term zonal isolation will prove essential to the continuing expansion of the CO2 injection market. Through this offshore CCS appraisal project, valuable best practices and lessons learned in design and execution have been captured. This paper presents the decision process used for selecting a suitable CO2-resistant cement system for Australia's first offshore CCS appraisal well, drilled by AGR as part of the CarbonNet Project in late 2019, as well as the project management processes implemented to ensure successful job execution. The experiences detailed in this paper will benefit other operators confronted by challenges associated with wells subjected to CO2 injection.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79297548","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}
Nik Fahusnaza Nik Mohd Najmi, Alif Shamir Baharudin, Khabilashini Ravendrnathan, Vaniel Anyi, Beng Seow Chai, Jen Ming Lim, Gregg Alexander
Designing robust hole-opening BHA to drill two consecutive sections with interbedded formation in a deep HPHT appraisal well is exceptionally challenging. The two hole-opening sections, 17in × 20in and 14-3/4in × 17in need to retain strict verticality requirement and the final hole diameter sizes must be guaranteed to allow for smooth casing running operations. Conventional method, consisting of pilot hole drilling and a dedicated hole-opening run, is time consuming. Hence, the Operator decided to proceed with single run hole-opening while drilling approach for significant time saving benefit. Utilizing finite element analysis modeling approach, tandem reamer BHA were designed and proposed for both hole-opening sections. The BHA consists of a PDC bit, a hydraulic-actuated reamer near the bit and a mechanical-actuated reamer above MWD tools. This BHA design concept can deliver both hole-opening and rat-hole cleaning operations in a single run. BHA optimization modeling was also done to select robust and appropriate cutting structures that can yield the most stable drilling dynamics with suitable drilling parameters. Applying the FEA modeling recommendations in the 17in × 20in hole-opening section, the operation went smoothly as planned for the first 1184m until a vibration level increase was observed, believed to be due to an unexpected sudden increase in the hardness of the interbedded formation. Realizing the potential of similar risk happening for the next hole interval, a conventional two-runs approach was implemented in the 14-3/4in × 17in section. A pilot hole was first drilled with a steerable motor BHA for trajectory adjustment and then followed by a dedicated under-reaming only (URO) operation with a bullnose BHA. The 937m under-reaming interval was executed successfully without any downhole issues, despite lower ROP than initially expected.
{"title":"Longest in Asia Pacific: Robust BHA Design Optimization Using Advanced FEA Modeling for Two Consecutive Hole-Opening Sections in HPHT Well","authors":"Nik Fahusnaza Nik Mohd Najmi, Alif Shamir Baharudin, Khabilashini Ravendrnathan, Vaniel Anyi, Beng Seow Chai, Jen Ming Lim, Gregg Alexander","doi":"10.4043/31433-ms","DOIUrl":"https://doi.org/10.4043/31433-ms","url":null,"abstract":"\u0000 Designing robust hole-opening BHA to drill two consecutive sections with interbedded formation in a deep HPHT appraisal well is exceptionally challenging. The two hole-opening sections, 17in × 20in and 14-3/4in × 17in need to retain strict verticality requirement and the final hole diameter sizes must be guaranteed to allow for smooth casing running operations. Conventional method, consisting of pilot hole drilling and a dedicated hole-opening run, is time consuming. Hence, the Operator decided to proceed with single run hole-opening while drilling approach for significant time saving benefit.\u0000 Utilizing finite element analysis modeling approach, tandem reamer BHA were designed and proposed for both hole-opening sections. The BHA consists of a PDC bit, a hydraulic-actuated reamer near the bit and a mechanical-actuated reamer above MWD tools. This BHA design concept can deliver both hole-opening and rat-hole cleaning operations in a single run. BHA optimization modeling was also done to select robust and appropriate cutting structures that can yield the most stable drilling dynamics with suitable drilling parameters.\u0000 Applying the FEA modeling recommendations in the 17in × 20in hole-opening section, the operation went smoothly as planned for the first 1184m until a vibration level increase was observed, believed to be due to an unexpected sudden increase in the hardness of the interbedded formation. Realizing the potential of similar risk happening for the next hole interval, a conventional two-runs approach was implemented in the 14-3/4in × 17in section. A pilot hole was first drilled with a steerable motor BHA for trajectory adjustment and then followed by a dedicated under-reaming only (URO) operation with a bullnose BHA. The 937m under-reaming interval was executed successfully without any downhole issues, despite lower ROP than initially expected.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78910384","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}
Digital transformation is a term that continues to be popular with the oil and gas industry. The industry's historic opposition to the adoption of innovative technology seems to be fading as operators, contractors, and service providers alike continue to invest in innovative solutions around not only digital technologies, but also in process and system optimization techniques. However, while operators are more willing to adopt newer and automated technologies, the "proof of value" burden still falls on service companies. Perceived value to operators may vary slightly, but overall, the industry has focused on two core tenants of value: Increased safety and efficiencyPersonnel reduction For widespread adoption of an enhanced digital solution, the technology must not only provide quantifiable value in at least one of the core tenants, but also must repeatably demonstrate the value in the field. The case study presented demonstrates the value added by introducing a new proprietary Programmable Logic Controller (PLC) based solution into the tubular running process. This system allows for tong operation, elevator and slip function, and single joint elevator (SJE) operation to be performed by a single person, rather than three or four personnel crew, as traditionally employed during tubular running operations. All functions are intelligently executed from a triple certified hazardous zone rated wireless tablet by a single operator's command while located inside the driller's cabin. Through the deployment of a new consolidated and intelligent control system, the rig was able to reduce the number of personnel typically required for casing run and rack back operations down to two operators per tower, which equates to as much as a 66% reduction in personnel needed for tubular running operations. Additionally, the system allowed the operator to control the equipment from inside the driller's cabin, which improved communications and reduced red zone exposure by 30% while increasing run time efficiency by as much as 11% on some connection strings.
{"title":"Optimizing Tubular Running Services Through Digital Solutions – Doing More with Less!","authors":"Robert L. Thibodeaux, Logan E. Smith, A. Mahmood","doi":"10.4043/31495-ms","DOIUrl":"https://doi.org/10.4043/31495-ms","url":null,"abstract":"\u0000 Digital transformation is a term that continues to be popular with the oil and gas industry. The industry's historic opposition to the adoption of innovative technology seems to be fading as operators, contractors, and service providers alike continue to invest in innovative solutions around not only digital technologies, but also in process and system optimization techniques. However, while operators are more willing to adopt newer and automated technologies, the \"proof of value\" burden still falls on service companies. Perceived value to operators may vary slightly, but overall, the industry has focused on two core tenants of value: Increased safety and efficiencyPersonnel reduction\u0000 For widespread adoption of an enhanced digital solution, the technology must not only provide quantifiable value in at least one of the core tenants, but also must repeatably demonstrate the value in the field.\u0000 The case study presented demonstrates the value added by introducing a new proprietary Programmable Logic Controller (PLC) based solution into the tubular running process. This system allows for tong operation, elevator and slip function, and single joint elevator (SJE) operation to be performed by a single person, rather than three or four personnel crew, as traditionally employed during tubular running operations. All functions are intelligently executed from a triple certified hazardous zone rated wireless tablet by a single operator's command while located inside the driller's cabin.\u0000 Through the deployment of a new consolidated and intelligent control system, the rig was able to reduce the number of personnel typically required for casing run and rack back operations down to two operators per tower, which equates to as much as a 66% reduction in personnel needed for tubular running operations. Additionally, the system allowed the operator to control the equipment from inside the driller's cabin, which improved communications and reduced red zone exposure by 30% while increasing run time efficiency by as much as 11% on some connection strings.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90566650","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}
Hayati Hussien, Nor Salwanie Zakaria, Ahiruddin A Rahman, Aishah Mastura Supian, Nur Asiah Maryam Abdullah, Raizil Aisyaizni Juzilman
Recently digital pipeline system has been introduced, advocating the advantages on the simplification of pipeline monitoring, elimination of inspection activities as well as the accessibility of information especially on the wellness of the pipeline(s). For successful implementation of digital pipeline system, availability of Internet of things (IoT); which is the network of physical objects "things" that are embedded with sensors, software, and other technologies for the purpose of connecting and exchanging data with other devices and systems over the Internet, is a must. The problems is IoT is rare or even non-existence for pipelines that have been there before 2005. Despite there are many oil and gas operators who have well advanced in control and monitoring their offshore facilities, they mostly monitor the only pressures and shutdown system. Other than that existing equipment in offshore facilities are often analogue and disconnected. A study on data retrieval feasibility to provide information to develop digital pipeline network for brown field facility arrived with very costly equipment installation. This is due the absent off communication system (DCS) and online measuring equipment (such as flow meter, pressure gauge and temperature sensor) at the required location of many offshore facility. This paper will discuss the feasibility and urgency of implementing of Digital Pipeline Network in offshore facilities most importantly at the existing and aging facilities. It will put across the importance of data retrieval, the required additional equipment and the facility for communication system as well as the assessment of installation hurdles at the aging facilities and the consequential cost requirement. Comprehensive data retrieval at brown field facilities can be achieved through rationalization between automated digital data online reading by installation of wireless IoT system (for equipment to measure pressure, flowrate and temperature) complimented with the existing communication system, manual data retrieval by site visit and network software analysis in order to reduce the material and installation cost while keeping the objectives intact. Pipeline OPEX will be subsequently reduced once AI based technology such as predictive and prescriptive assessment for effective pipeline monitoring and integrity management can be implemented and hence inspection and maintenance program for pipeline(s) can be optimized.
{"title":"Digital Pipeline Network, Feasibility of Data Acquisition at Offshore Brownfield","authors":"Hayati Hussien, Nor Salwanie Zakaria, Ahiruddin A Rahman, Aishah Mastura Supian, Nur Asiah Maryam Abdullah, Raizil Aisyaizni Juzilman","doi":"10.4043/31627-ms","DOIUrl":"https://doi.org/10.4043/31627-ms","url":null,"abstract":"\u0000 Recently digital pipeline system has been introduced, advocating the advantages on the simplification of pipeline monitoring, elimination of inspection activities as well as the accessibility of information especially on the wellness of the pipeline(s). For successful implementation of digital pipeline system, availability of Internet of things (IoT); which is the network of physical objects \"things\" that are embedded with sensors, software, and other technologies for the purpose of connecting and exchanging data with other devices and systems over the Internet, is a must. The problems is IoT is rare or even non-existence for pipelines that have been there before 2005. Despite there are many oil and gas operators who have well advanced in control and monitoring their offshore facilities, they mostly monitor the only pressures and shutdown system. Other than that existing equipment in offshore facilities are often analogue and disconnected. A study on data retrieval feasibility to provide information to develop digital pipeline network for brown field facility arrived with very costly equipment installation. This is due the absent off communication system (DCS) and online measuring equipment (such as flow meter, pressure gauge and temperature sensor) at the required location of many offshore facility.\u0000 This paper will discuss the feasibility and urgency of implementing of Digital Pipeline Network in offshore facilities most importantly at the existing and aging facilities. It will put across the importance of data retrieval, the required additional equipment and the facility for communication system as well as the assessment of installation hurdles at the aging facilities and the consequential cost requirement.\u0000 Comprehensive data retrieval at brown field facilities can be achieved through rationalization between automated digital data online reading by installation of wireless IoT system (for equipment to measure pressure, flowrate and temperature) complimented with the existing communication system, manual data retrieval by site visit and network software analysis in order to reduce the material and installation cost while keeping the objectives intact. Pipeline OPEX will be subsequently reduced once AI based technology such as predictive and prescriptive assessment for effective pipeline monitoring and integrity management can be implemented and hence inspection and maintenance program for pipeline(s) can be optimized.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78237018","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}
D. Kusuma, Taufik Nordin, A. Wijaya, Azlan Shah B Johari, Z. Ernando, Rosli bin Ismail, Hilman bin Roslan, Heri Tanjung, Jorge Gonzales Iglesias, Ratna Dewanda, Piko Satria Danda
ABC-1 exploration well was drilled through a carbonate build-up structure of Ngimbang Formation in offshore East Java, Indonesia. Standard triple-combo open hole logs were acquired by means of logging while drilling, while more advance wireline loggings were planned subsequently. Unfortunately, there were total losses during drilling which had to be managed by pressurized mud cap drilling (PMCD) which prevent from cuttings recovery for the rest of the interval. Multiple trips were also required to drill the well safely resulting in rugose and enlarged borehole. These conditions did not allow open-hole wireline log to access the target located at the lower interval of the well. It was inevitable to complete the well despite not enough data had been acquired to perform a comprehensive formation evaluation. In order to obtain remaining required data, it was decided to complement the compromised open-hole data with an advance pulsed neutron log (PNL) device, which offered several unique measurements to tackle the harsh conditions. Some of these key measurements are: (1) a self-compensation algorithm which provided robust sigma (SIGM) and cased-hole porosity measurement (TPHI), which was used to further validate neutron from LWD. (2) A combination of both capture and inelastic high definition elemental spectra measurement were utilized to obtain accurate mineralogy fraction. (3) carbon-oxygen ratio (COR) high precision measurement to calculate oil saturation. Lastly (4), fast neutron capture cross-section (FNXS) measurement was also acquired to give insight on possible gas occurrence even in tight zones. The advance PNL, acquired over 3 passes, showed consistent reading of sigma, TPHI, FNXS and elemental spectroscopy measurement. However, there were some discrepancies in between COR passes, which eventually has shed some light on what happened in this well. The first pass did not really show any potential oil along the carbonate body. Then, the second pass started to reveal potential oil around the top part of the carbonate, where resistivity is low with no distinctive neutron-density crossover. The third pass revealed an even more oil volume along the top carbonate. There is a possibility that the increase of oil reading might be due to the changing environment during logging, allowing some invasion to dissipate along the carbonate tops. This implies that there might be yet another oil zone below the revealed oil interval, should the invasion fluid start to dissipate. Subsequent well test showed significant oil production over the interval identified from the PNL interpretation, which put ABC-1 as one of the most successful Indonesian exploration well in 2021. This case study shows the success of utilizing advance pulsed neutron log to perform comprehensive formation evaluation under challenging condition, which can be used as reference for tackling similar drilling challenges in the future.
{"title":"Advance Pulsed Neutron Logging – An Optimized Solution in PMCD Well: Case Study of Oil Discovery in Indonesia","authors":"D. Kusuma, Taufik Nordin, A. Wijaya, Azlan Shah B Johari, Z. Ernando, Rosli bin Ismail, Hilman bin Roslan, Heri Tanjung, Jorge Gonzales Iglesias, Ratna Dewanda, Piko Satria Danda","doi":"10.4043/31506-ms","DOIUrl":"https://doi.org/10.4043/31506-ms","url":null,"abstract":"\u0000 ABC-1 exploration well was drilled through a carbonate build-up structure of Ngimbang Formation in offshore East Java, Indonesia. Standard triple-combo open hole logs were acquired by means of logging while drilling, while more advance wireline loggings were planned subsequently. Unfortunately, there were total losses during drilling which had to be managed by pressurized mud cap drilling (PMCD) which prevent from cuttings recovery for the rest of the interval. Multiple trips were also required to drill the well safely resulting in rugose and enlarged borehole. These conditions did not allow open-hole wireline log to access the target located at the lower interval of the well.\u0000 It was inevitable to complete the well despite not enough data had been acquired to perform a comprehensive formation evaluation. In order to obtain remaining required data, it was decided to complement the compromised open-hole data with an advance pulsed neutron log (PNL) device, which offered several unique measurements to tackle the harsh conditions. Some of these key measurements are: (1) a self-compensation algorithm which provided robust sigma (SIGM) and cased-hole porosity measurement (TPHI), which was used to further validate neutron from LWD. (2) A combination of both capture and inelastic high definition elemental spectra measurement were utilized to obtain accurate mineralogy fraction. (3) carbon-oxygen ratio (COR) high precision measurement to calculate oil saturation. Lastly (4), fast neutron capture cross-section (FNXS) measurement was also acquired to give insight on possible gas occurrence even in tight zones.\u0000 The advance PNL, acquired over 3 passes, showed consistent reading of sigma, TPHI, FNXS and elemental spectroscopy measurement. However, there were some discrepancies in between COR passes, which eventually has shed some light on what happened in this well. The first pass did not really show any potential oil along the carbonate body. Then, the second pass started to reveal potential oil around the top part of the carbonate, where resistivity is low with no distinctive neutron-density crossover. The third pass revealed an even more oil volume along the top carbonate. There is a possibility that the increase of oil reading might be due to the changing environment during logging, allowing some invasion to dissipate along the carbonate tops. This implies that there might be yet another oil zone below the revealed oil interval, should the invasion fluid start to dissipate.\u0000 Subsequent well test showed significant oil production over the interval identified from the PNL interpretation, which put ABC-1 as one of the most successful Indonesian exploration well in 2021. This case study shows the success of utilizing advance pulsed neutron log to perform comprehensive formation evaluation under challenging condition, which can be used as reference for tackling similar drilling challenges in the future.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82766204","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}
Siti Nadiah Ishak, Nurul Iffah M Garib, E. Damasena, D. Dahasry
Drilling keeper wells with an open-sea concept by suspending a 36″ conductor to a jackup drilling rig as a temporary structure induced several criticalities in plugging and abandoning the wells. The severity amplified with the two (2) wells are cemented inside the conductor and completed with a splitter wellhead. As per the Malaysia local regulatory, any abandoned wells are to be free from any structure protruding from seabed. This is paramount in confirming the drilled location is free from potential hazards. This splitter design confirmed that conventional cut-and-pull approach is not feasible and multistring cutter is the only solution available. This paper covers the approach and result in performing eccentric cut of fully cemented 2 × 9-5/8″, 2 × 13-3/8″ and a 1.0″ wall thickness 36″ conductor including decommission of a splitter wellhead. In achieving the objective to P&A the keeper wells, an Abrasive Water Jet Cutter (AWJC) is deployed to perform an internal eccentric cut that able to penetrate five (5) cemented casing simultaneously. The cutter is paired up with Drilling Wire Saw (DWS) and Dual Drilling Machine (DDM) as a surface cutter and a "hole-borer" in cutting the retrieved multistring into shorter sections that eliminated the needs to dismantle the splitter wellhead into individual component. Meanwhile, for surface lifting and suspending, an engineered pad eyes, H-beam and lifting frame with pins were required to guarantee a successful operation. AWJC is designed to penetrate structures with extreme pressure, coupled with optimized pre-planned nozzle rotation speed to establish a complete 360° clean cut downhole. The jetting mechanism using the right mixture of water and garnet is crucial in providing sufficient capability to penetrate the conductor size in an eccentric condition considering the worst-case position of the cutter downhole. The significant finding from this P&A operation is understanding the type of garnet and fluid less environment around nozzle cutter head as main contributors for an efficient cutting process. Actual pick-up weight to pull free the pipe was 37% higher than the calculated weight for a complete cut. Hence, the surface capability shall be designed with some marginal tolerance to provide additional lifting capability in case an unsmoothed cut is experienced. Overall, the operation managed to overcome the challenges and uncertainties experienced and mark as a great milestone for the first ever decommission splitter well design in Malaysia.
{"title":"Decommissioning of Splitter Wellhead Wells","authors":"Siti Nadiah Ishak, Nurul Iffah M Garib, E. Damasena, D. Dahasry","doi":"10.4043/31577-ms","DOIUrl":"https://doi.org/10.4043/31577-ms","url":null,"abstract":"\u0000 Drilling keeper wells with an open-sea concept by suspending a 36″ conductor to a jackup drilling rig as a temporary structure induced several criticalities in plugging and abandoning the wells. The severity amplified with the two (2) wells are cemented inside the conductor and completed with a splitter wellhead. As per the Malaysia local regulatory, any abandoned wells are to be free from any structure protruding from seabed. This is paramount in confirming the drilled location is free from potential hazards. This splitter design confirmed that conventional cut-and-pull approach is not feasible and multistring cutter is the only solution available. This paper covers the approach and result in performing eccentric cut of fully cemented 2 × 9-5/8″, 2 × 13-3/8″ and a 1.0″ wall thickness 36″ conductor including decommission of a splitter wellhead. In achieving the objective to P&A the keeper wells, an Abrasive Water Jet Cutter (AWJC) is deployed to perform an internal eccentric cut that able to penetrate five (5) cemented casing simultaneously. The cutter is paired up with Drilling Wire Saw (DWS) and Dual Drilling Machine (DDM) as a surface cutter and a \"hole-borer\" in cutting the retrieved multistring into shorter sections that eliminated the needs to dismantle the splitter wellhead into individual component. Meanwhile, for surface lifting and suspending, an engineered pad eyes, H-beam and lifting frame with pins were required to guarantee a successful operation. AWJC is designed to penetrate structures with extreme pressure, coupled with optimized pre-planned nozzle rotation speed to establish a complete 360° clean cut downhole. The jetting mechanism using the right mixture of water and garnet is crucial in providing sufficient capability to penetrate the conductor size in an eccentric condition considering the worst-case position of the cutter downhole. The significant finding from this P&A operation is understanding the type of garnet and fluid less environment around nozzle cutter head as main contributors for an efficient cutting process. Actual pick-up weight to pull free the pipe was 37% higher than the calculated weight for a complete cut. Hence, the surface capability shall be designed with some marginal tolerance to provide additional lifting capability in case an unsmoothed cut is experienced. Overall, the operation managed to overcome the challenges and uncertainties experienced and mark as a great milestone for the first ever decommission splitter well design in Malaysia.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82800020","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}
Rahman Setiadi, Yulianto Jong, Nur Mahfudhin, Mutawif Ilmi Muwaffaqih, Albert Richal Dading
Tunu is one of Mahakam fields with majority gas production. The depositional nature of fluvial with minimum tidal influence results in the signature of delta sedimentation by hundred layers of gas-bearing sand lenses as pay zone. They are constructed of unconsolidated clean and shaly sand reservoirs at the shallower burial and higher consolidation at deeper burial due to compaction and diagenesis. The unconsolidated section requires sand control as mandatory means to unlock it safely. The combined challenge of numerous sand layers and marginal reserves makes it economically impossible to perform regular detailed physical sand grain assessment by individual conventional coring completed with Laser Particle Sieve Analysis (LPSA). An economic approach is through performing sand bailing. However, the bailed sand dry-sieve results were confusing with wide particle size distribution (PSD) curve variation from several well samples. Referring to this PSD uncertainty, installing straddled thru-tubing screen in front of the reservoir as sand control resulted in good production and plugged indication at the beginning of the initiative by utilizing a similar screen opening size. Thus, a new fit-for-purpose methodology was required. A study to predict sand grain size on each reservoir target was initiated by analyzing three available shallow reservoir cores in Mahakam, which could cover most of Tunu's shallow sedimentation type. The result was that most of the sand grain size distribution on each sample core correlated with their calculated shale volume content (v-shale). Lower v-shale is respected to larger sand grain size. Unconsolidated Tunu Shallow reservoir doesn't contain any specific radioactive minerals. Thus, v-shale could be easily calculated from gamma-ray logs, which are always available on each reservoir target at any drilled wells. The relationship between sand grain size and v-shale was gathered on a single map. The map was then validated by historical screen installation. Positive results were seen when screen size selection respects specific patterns on the generated sand map at the v-shale value of perforation intervals. Thru-tubing screen installation campaign was continued following the new sand map reference. It could deliver more than 80% successful installation with no plugging or sand at a new perforated reservoir when no screen integrity issue due to erosion was encountered. This novel approach allowed better prediction of thru-tubing screen opening size requirements and perforation interval selection in Tunu unconsolidated reservoir and was successfully expanded in offshore Mahakam field at similar facies.
{"title":"Novel Reservoir Sand Grain Size Map Based on Open Hole Gamma Ray Log as Im-Proved ThruTubing Sand Screen Size Selection Guideline on Tunu Multi-Layer Un-Consolidated Gas Reservoir","authors":"Rahman Setiadi, Yulianto Jong, Nur Mahfudhin, Mutawif Ilmi Muwaffaqih, Albert Richal Dading","doi":"10.4043/31573-ms","DOIUrl":"https://doi.org/10.4043/31573-ms","url":null,"abstract":"\u0000 Tunu is one of Mahakam fields with majority gas production. The depositional nature of fluvial with minimum tidal influence results in the signature of delta sedimentation by hundred layers of gas-bearing sand lenses as pay zone. They are constructed of unconsolidated clean and shaly sand reservoirs at the shallower burial and higher consolidation at deeper burial due to compaction and diagenesis. The unconsolidated section requires sand control as mandatory means to unlock it safely.\u0000 The combined challenge of numerous sand layers and marginal reserves makes it economically impossible to perform regular detailed physical sand grain assessment by individual conventional coring completed with Laser Particle Sieve Analysis (LPSA). An economic approach is through performing sand bailing. However, the bailed sand dry-sieve results were confusing with wide particle size distribution (PSD) curve variation from several well samples. Referring to this PSD uncertainty, installing straddled thru-tubing screen in front of the reservoir as sand control resulted in good production and plugged indication at the beginning of the initiative by utilizing a similar screen opening size. Thus, a new fit-for-purpose methodology was required.\u0000 A study to predict sand grain size on each reservoir target was initiated by analyzing three available shallow reservoir cores in Mahakam, which could cover most of Tunu's shallow sedimentation type. The result was that most of the sand grain size distribution on each sample core correlated with their calculated shale volume content (v-shale). Lower v-shale is respected to larger sand grain size. Unconsolidated Tunu Shallow reservoir doesn't contain any specific radioactive minerals. Thus, v-shale could be easily calculated from gamma-ray logs, which are always available on each reservoir target at any drilled wells. The relationship between sand grain size and v-shale was gathered on a single map.\u0000 The map was then validated by historical screen installation. Positive results were seen when screen size selection respects specific patterns on the generated sand map at the v-shale value of perforation intervals. Thru-tubing screen installation campaign was continued following the new sand map reference. It could deliver more than 80% successful installation with no plugging or sand at a new perforated reservoir when no screen integrity issue due to erosion was encountered.\u0000 This novel approach allowed better prediction of thru-tubing screen opening size requirements and perforation interval selection in Tunu unconsolidated reservoir and was successfully expanded in offshore Mahakam field at similar facies.","PeriodicalId":11011,"journal":{"name":"Day 3 Thu, March 24, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91484637","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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