The second phase of Johan Sverdrup came on stream in December 2022. This paper focuses on the execution of Johan Sverdrup phase 2 and describes the assessments and investments for improved oil recovery (IOR) from one of the largest oil fields in Norway. The Johan Sverdrup field development has been called Equinor's ‘digital flagship’, and this paper includes the proof of concept for the digital initiatives after more than three years of operation. Despite the Covid-19 pandemic Johan Sverdrup phase 2 has been able to deliver on schedule, under budget, and with an excellent safety record. The paper includes experiences from the concept development and engineering phase to the global contracting strategy, through the construction on multiple building sites in Norway and globally, and until the end of the completion phase offshore Norway. Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS), and with recoverable reserves estimated at 2.7 billion barrels of oil equivalents, has the resources to be a North Sea Giant. Start-up of the Johan Sverdrup phase 2 extends and accelerates oil and gas production from the NCS for another five decades. This paper aims to highlight what it took to make Johan Sverdrup a true North Sea Giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. In many ways the Johan Sverdrup development has set a new standard for project execution in Equinor. The impact of different variables made during the execution of the project, such as the Covid-19 pandemic, market effects, procurement strategies, value improvement initiatives, execution performance and reservoir characteristics is addressed, as well as describing assessments and investments for improved oil recovery (IOR). Data acquisition, Permanent Reservoir Monitoring (PRM), fibre-optic monitoring of wells, innovative technologies, and digitalization, as well as new ways of working are included. Equinor´s digital strategy was established in 2017, and Johan Sverdrup was highlighted as a digital flagship at that time and a frontrunner in applying digital solutions to improve safety and efficiency from the development to the operational phase. What has been implemented so far together with experiences will be shared.
{"title":"Johan Sverdrup: The Final Lap of a True North Sea Giant","authors":"Vibeke Lossius, T. Nedrelid","doi":"10.4043/32552-ms","DOIUrl":"https://doi.org/10.4043/32552-ms","url":null,"abstract":"\u0000 The second phase of Johan Sverdrup came on stream in December 2022. This paper focuses on the execution of Johan Sverdrup phase 2 and describes the assessments and investments for improved oil recovery (IOR) from one of the largest oil fields in Norway.\u0000 The Johan Sverdrup field development has been called Equinor's ‘digital flagship’, and this paper includes the proof of concept for the digital initiatives after more than three years of operation.\u0000 Despite the Covid-19 pandemic Johan Sverdrup phase 2 has been able to deliver on schedule, under budget, and with an excellent safety record. The paper includes experiences from the concept development and engineering phase to the global contracting strategy, through the construction on multiple building sites in Norway and globally, and until the end of the completion phase offshore Norway.\u0000 Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS), and with recoverable reserves estimated at 2.7 billion barrels of oil equivalents, has the resources to be a North Sea Giant. Start-up of the Johan Sverdrup phase 2 extends and accelerates oil and gas production from the NCS for another five decades. This paper aims to highlight what it took to make Johan Sverdrup a true North Sea Giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. In many ways the Johan Sverdrup development has set a new standard for project execution in Equinor.\u0000 The impact of different variables made during the execution of the project, such as the Covid-19 pandemic, market effects, procurement strategies, value improvement initiatives, execution performance and reservoir characteristics is addressed, as well as describing assessments and investments for improved oil recovery (IOR). Data acquisition, Permanent Reservoir Monitoring (PRM), fibre-optic monitoring of wells, innovative technologies, and digitalization, as well as new ways of working are included. Equinor´s digital strategy was established in 2017, and Johan Sverdrup was highlighted as a digital flagship at that time and a frontrunner in applying digital solutions to improve safety and efficiency from the development to the operational phase. What has been implemented so far together with experiences will be shared.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"92 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134517987","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}
Chinh Phan Van, Abdulqawi Al Fakih, Luis Felipe Gonzales, Anwar Faizd Osman
The most challenging section in drilling directional wells is the curve section. This curve section used to be drilled by a conventional steerable motor with a slide/rotate decision with the greater challenges of poor hole cleaning efficiency and increased drilling time. The Rotary Steerable System (RSS) was introduced in a turnkey project by eliminating slide and rotate limitations to reduce the cost per foot. Initially, the downhole automation of the RSS was limited to holding verticals and inclinations. Later, the closed-loop control progressed to hold inclination and azimuth, but the curve section remained unautomated. The driller continued to drill the curve section manually by adjusting the steering parameters. A new Autonomous Downhole Control System (ADCS) recently integrated into the RSS enables autonomous drilling of the curve section, further reducing human inconsistencies and improving borehole quality, drilling efficiency, well economic, and reducing carbon footprint. Multiple offset wells were analyzed. Different BHA configurations were studied with various stabilizations to increase the dogleg capability. Bit records were gathered and analyzed for steerability and stability. The trajectory design was revisited to ensure minimum dogleg severity was considered at the planning stage. This ensured staying within the RSS's technical limits and avoiding unplanned pulling out of the hole due to failure to maintain the trajectory. The specific field strategy was prepared with the digital journey of intelligent planning, intelligent execution, surface automation, and downhole automation. The RSS was incorporated with the newly developed ADCS, placing the driller into the supervisory role to monitor the digital drilling system. The RSS was introduced in a turnkey project to reduce the cost per foot by improving the ROP, drilling shoe-to-shoe in one run, having efficient hole cleaning to avoid stuck pipe incidents, and having a smoother borehole for running casing and liner. The new ADCS incorporated into the RSS completed the automation puzzle and has been tested successfully in many wells on the same project. It transfers human decision-making to the downhole control, further increasing ROP in some cases by up to 100% and up to three days saved on each well drilled. This paper will illustrate the detailed BHA change in curved and horizontal sections from mud motor to the RSS with the significant progression of downhole automation and a future view for autonomous drilling in similar fields worldwide.
{"title":"Transforming the Trajectory Control from Conventional Motor Drilling to Autonomous Rotary Steerable Systems","authors":"Chinh Phan Van, Abdulqawi Al Fakih, Luis Felipe Gonzales, Anwar Faizd Osman","doi":"10.4043/32592-ms","DOIUrl":"https://doi.org/10.4043/32592-ms","url":null,"abstract":"\u0000 The most challenging section in drilling directional wells is the curve section. This curve section used to be drilled by a conventional steerable motor with a slide/rotate decision with the greater challenges of poor hole cleaning efficiency and increased drilling time. The Rotary Steerable System (RSS) was introduced in a turnkey project by eliminating slide and rotate limitations to reduce the cost per foot. Initially, the downhole automation of the RSS was limited to holding verticals and inclinations. Later, the closed-loop control progressed to hold inclination and azimuth, but the curve section remained unautomated. The driller continued to drill the curve section manually by adjusting the steering parameters. A new Autonomous Downhole Control System (ADCS) recently integrated into the RSS enables autonomous drilling of the curve section, further reducing human inconsistencies and improving borehole quality, drilling efficiency, well economic, and reducing carbon footprint.\u0000 Multiple offset wells were analyzed. Different BHA configurations were studied with various stabilizations to increase the dogleg capability. Bit records were gathered and analyzed for steerability and stability. The trajectory design was revisited to ensure minimum dogleg severity was considered at the planning stage. This ensured staying within the RSS's technical limits and avoiding unplanned pulling out of the hole due to failure to maintain the trajectory. The specific field strategy was prepared with the digital journey of intelligent planning, intelligent execution, surface automation, and downhole automation. The RSS was incorporated with the newly developed ADCS, placing the driller into the supervisory role to monitor the digital drilling system.\u0000 The RSS was introduced in a turnkey project to reduce the cost per foot by improving the ROP, drilling shoe-to-shoe in one run, having efficient hole cleaning to avoid stuck pipe incidents, and having a smoother borehole for running casing and liner. The new ADCS incorporated into the RSS completed the automation puzzle and has been tested successfully in many wells on the same project. It transfers human decision-making to the downhole control, further increasing ROP in some cases by up to 100% and up to three days saved on each well drilled.\u0000 This paper will illustrate the detailed BHA change in curved and horizontal sections from mud motor to the RSS with the significant progression of downhole automation and a future view for autonomous drilling in similar fields worldwide.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132347180","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}
Andrea Pontual Weydmann, Fernando Aquino Mendes, Vivian Peçanha Leite Oliveira, Gustavo da Cunha Maia, Arnaldo Martins Salazar Junior, Patrícia Marcela Doria Santiago Santos, Lilian Melo Barreto
This paper presents a series of improvements Petrobras has been undertaking in its Project Management (PM) practices and the shaping of a multi-level Project Management Office (PMO) structure through the case of Buzios implementation program. Buzios is Petrobras’ largest ultra-deepwater oil field, which already contains 4 large-scale operational floating production units (all of them among the company's top producing facilities) and at least seven additional modules to be implemented by 2027, each of which is a megaproject per se. The re-shaping of the PMO strategy in Petrobras observed a layered approach with improvements in strategic (corporate), tactical (portfolio) and operational (program/projects) level. PMOs were responsible for strengthening project planning and control practices, improving training of project management teams and aligning the portfolio to the corporate strategy. On Buzios production development program operational level, the PMO was a key driver to increase project and asset value. After a comprehensive assessment of stakeholder interests, the main practices prioritized for the structuring of Buzios PMO were: (i) exploitation of synergies between projects; (ii) standardization and alignment of project management practices; (iii) increase of information availability; (iv) improvement in communication flow and governance and (iv) dissemination of lessons learned among the teams. To attain these goals, the initiative itself was organized as a project and deliverables were classified in a Work Breakdown Structure (WBS) based on four main streams of action: Governance and Communication - establishment of a multi-level project governance, including the senior executive company level; Quality and Control - establishment of centralized and integrated planning and control processes and centralization of activities at the PMO level; Digitalization - automation of processes, and massive provision of self-service project/portfolio information; and Critical Resource management - establishment of a formal and structured process to support resource allocation. Some of the main results obtained are listed below, in line with the previously established pillars: Governance and Communication - timely decision-making was facilitated and integration of teams was increased; Quality and Control - improvement in cost and schedule predictability; Digitalization - cost/labor reduction and increased efficiency; Critical Resource management - more effective and organized sharing of resources among projects. Literature already recognizes the use of rigorous methodologies and PM practices as a driver for improvement in project outcome. The application of such practices in a program comprised by a handful of megaprojects (as provided by the world class asset of Buzios) allowed the validation of several theoretical constructs and at the same time generated value for the company's portfolio. Other companies can benefit from the lessons learned her
{"title":"Continuous Improvements in Project Management Practices Through PMOs - The Case of Buzios Field","authors":"Andrea Pontual Weydmann, Fernando Aquino Mendes, Vivian Peçanha Leite Oliveira, Gustavo da Cunha Maia, Arnaldo Martins Salazar Junior, Patrícia Marcela Doria Santiago Santos, Lilian Melo Barreto","doi":"10.4043/32196-ms","DOIUrl":"https://doi.org/10.4043/32196-ms","url":null,"abstract":"\u0000 This paper presents a series of improvements Petrobras has been undertaking in its Project Management (PM) practices and the shaping of a multi-level Project Management Office (PMO) structure through the case of Buzios implementation program. Buzios is Petrobras’ largest ultra-deepwater oil field, which already contains 4 large-scale operational floating production units (all of them among the company's top producing facilities) and at least seven additional modules to be implemented by 2027, each of which is a megaproject per se.\u0000 The re-shaping of the PMO strategy in Petrobras observed a layered approach with improvements in strategic (corporate), tactical (portfolio) and operational (program/projects) level. PMOs were responsible for strengthening project planning and control practices, improving training of project management teams and aligning the portfolio to the corporate strategy. On Buzios production development program operational level, the PMO was a key driver to increase project and asset value.\u0000 After a comprehensive assessment of stakeholder interests, the main practices prioritized for the structuring of Buzios PMO were: (i) exploitation of synergies between projects; (ii) standardization and alignment of project management practices; (iii) increase of information availability; (iv) improvement in communication flow and governance and (iv) dissemination of lessons learned among the teams. To attain these goals, the initiative itself was organized as a project and deliverables were classified in a Work Breakdown Structure (WBS) based on four main streams of action: Governance and Communication - establishment of a multi-level project governance, including the senior executive company level; Quality and Control - establishment of centralized and integrated planning and control processes and centralization of activities at the PMO level; Digitalization - automation of processes, and massive provision of self-service project/portfolio information; and Critical Resource management - establishment of a formal and structured process to support resource allocation.\u0000 Some of the main results obtained are listed below, in line with the previously established pillars: Governance and Communication - timely decision-making was facilitated and integration of teams was increased; Quality and Control - improvement in cost and schedule predictability; Digitalization - cost/labor reduction and increased efficiency; Critical Resource management - more effective and organized sharing of resources among projects.\u0000 Literature already recognizes the use of rigorous methodologies and PM practices as a driver for improvement in project outcome. The application of such practices in a program comprised by a handful of megaprojects (as provided by the world class asset of Buzios) allowed the validation of several theoretical constructs and at the same time generated value for the company's portfolio. Other companies can benefit from the lessons learned her","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134108047","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}
William Turner, Alexander Donald MacKay, S. Khurana
The objective of this paper is to provide a systematic approach to verify and validate Greenhouse Gas (GHG) emissions for a typical Gulf of Mexico (GoM) offshore oil and gas production facility. The paper discusses ways to reduce GHG emissions at the facility level and examines an approach to assess an energy company's emission reporting methods and, where applicable, its target to achieve net zero emissions. The paper reviews the regulatory framework for GHG emissions reporting and estimation guidelines. It identifies emission sources for a typical offshore facility and groups these emission sources into defined categories. A simplified model is created to estimate total emissions for offshore facilities. The model results are used to evaluate inherent uncertainty in emissions estimation techniques and also provide a basis to reduce emissions. Furthermore, the paper reviews sustainability reports of select energy companies, and analyzes these companies’ reporting methods, targets, and strategies to reduce emissions at the corporate level. In summary, the paper provides insights and guidance in estimating GHG emissions at the offshore facility level and subsequent reporting at the company corporate level with the following: Review of the regulatory framework, estimating methods, and reporting for an offshore facility level emissions. Organize emission sources into defined categories in order to comprehend major emission sources for an offshore facility. Analyze inherent uncertainty in emissions estimation. Discuss ways to reduce emissions at the facility level and its limitations. Analyze select energy companies’ corporate sustainability reports and cover ways to standardize emissions reporting so it is easier to evaluate and compare a company's performance with its peers. Identify energy company strategies and associated risks to achieve net zero emissions.
{"title":"GHG Emissions: Evaluation, Reduction, and Reporting","authors":"William Turner, Alexander Donald MacKay, S. Khurana","doi":"10.4043/32338-ms","DOIUrl":"https://doi.org/10.4043/32338-ms","url":null,"abstract":"\u0000 The objective of this paper is to provide a systematic approach to verify and validate Greenhouse Gas (GHG) emissions for a typical Gulf of Mexico (GoM) offshore oil and gas production facility. The paper discusses ways to reduce GHG emissions at the facility level and examines an approach to assess an energy company's emission reporting methods and, where applicable, its target to achieve net zero emissions.\u0000 The paper reviews the regulatory framework for GHG emissions reporting and estimation guidelines. It identifies emission sources for a typical offshore facility and groups these emission sources into defined categories. A simplified model is created to estimate total emissions for offshore facilities. The model results are used to evaluate inherent uncertainty in emissions estimation techniques and also provide a basis to reduce emissions. Furthermore, the paper reviews sustainability reports of select energy companies, and analyzes these companies’ reporting methods, targets, and strategies to reduce emissions at the corporate level.\u0000 In summary, the paper provides insights and guidance in estimating GHG emissions at the offshore facility level and subsequent reporting at the company corporate level with the following:\u0000 Review of the regulatory framework, estimating methods, and reporting for an offshore facility level emissions. Organize emission sources into defined categories in order to comprehend major emission sources for an offshore facility. Analyze inherent uncertainty in emissions estimation. Discuss ways to reduce emissions at the facility level and its limitations. Analyze select energy companies’ corporate sustainability reports and cover ways to standardize emissions reporting so it is easier to evaluate and compare a company's performance with its peers. Identify energy company strategies and associated risks to achieve net zero emissions.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130119514","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}
Matthew James Reilly, J. Thurmond, Koda Chovanetz, J. M. Party, O. De Jesus, Muhlis Unladi
A method is proposed to calculate pore pressure at the bit while drilling using all data typically available in a modern drilling operation. This method utilizes a machine learning approach that can estimate pore pressures at the same or lesser range of uncertainty as traditional methods and can do so at the bit in real-time. Traditional pore pressure estimation while drilling utilizes a combination of data sources most of which are detected from logging while drilling (LWD) sensors placed 100's of feet behind the drill bit (where resistivity, sonic, density etc. tools are commonly placed). Furthermore, smoothing algorithms are often used to average the detection data thus increasing the offset from the drill bit to the estimated pore pressure calculation. The result of this is that the pore pressure calculation while drilling is only relevant to the formation that has already been penetrated and not being actively drilled. In hole sections where minor pore pressure changes can have significant impact on operational decisions this has obvious disadvantages. However, while drilling a well multiple sources of data from the drill bit itself are typically left unused in pore pressure calculation. Whereas traditional methods give an estimate of pore pressure after the well has already experienced a change in pressure, this method can calculate pore pressure at the bit, as the change is experienced. Another benefit of applying a machine learning model to pore pressure calculation while drilling is that the computational time is almost instantaneous.
{"title":"Real Time Pore Pressure Calculation from Drilling Dynamics Data via Machine Learning Techniques","authors":"Matthew James Reilly, J. Thurmond, Koda Chovanetz, J. M. Party, O. De Jesus, Muhlis Unladi","doi":"10.4043/32209-ms","DOIUrl":"https://doi.org/10.4043/32209-ms","url":null,"abstract":"\u0000 A method is proposed to calculate pore pressure at the bit while drilling using all data typically available in a modern drilling operation. This method utilizes a machine learning approach that can estimate pore pressures at the same or lesser range of uncertainty as traditional methods and can do so at the bit in real-time. Traditional pore pressure estimation while drilling utilizes a combination of data sources most of which are detected from logging while drilling (LWD) sensors placed 100's of feet behind the drill bit (where resistivity, sonic, density etc. tools are commonly placed). Furthermore, smoothing algorithms are often used to average the detection data thus increasing the offset from the drill bit to the estimated pore pressure calculation. The result of this is that the pore pressure calculation while drilling is only relevant to the formation that has already been penetrated and not being actively drilled. In hole sections where minor pore pressure changes can have significant impact on operational decisions this has obvious disadvantages. However, while drilling a well multiple sources of data from the drill bit itself are typically left unused in pore pressure calculation. Whereas traditional methods give an estimate of pore pressure after the well has already experienced a change in pressure, this method can calculate pore pressure at the bit, as the change is experienced. Another benefit of applying a machine learning model to pore pressure calculation while drilling is that the computational time is almost instantaneous.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133894234","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}
Antoine Marret, Torgeir Helland, Eddy Papore, Frederic Le-Naour, E. Pratt, R. Vivet, Fredrik Andreas Møller, Knut Edmund Haugen
This paper presents the foundations as well as the main outcomes of the development, industrialization, fabrication and installation of the TechnipFMC's Electrically Trace Heated Pipe-in-Pipe (ETH-PiP) 2.0 for application on the Fenja field development. The Fenja Field is located offshore mid-Norway at a water depth of approximately 324m, and consists of two separate hydrocarbon accumulations, the Pil and Bue reservoirs, with fluid properties leading to flow assurance challenges such as hydrates and wax formation. Following successful deployment of a first generation of Electrically Trace Heated Pipe-in-Pipe on the TotalEnergies (then Total) Islay Field in 2011, TechnipFMC have conducted the development and industrialization of a completely new generation of ETH-PiP 2.0. The new ETH-PiP 2.0 has higher electrical rating of 3.8/6.6kV to overcome the specificities of the Fenja field development including the long tie-back distance of 36.8km which makes Fenja the longest (and largest) ETH-PiP in the world. Subsequent to successful qualification of the ETH-PiP system, TechnipFMC has completed the manufacturing of 36.8km of ETH-PiP stalks at the Evanton spoolbase. These were then loaded out onto the Deep Energy pipelay vessel for subsea installation by reel lay. The installation was finalized in summer 2021 with the complete system being connected and tested from the Njord A platform after it returned from refurbishment in spring 2022. This paper presents the qualification, industrialization, assembly and installation of the new generation ETH-PiP 2.0 which forms part of the Fenja field development.
{"title":"ETH-PiP 2.0 Experience from Fenja EPCI","authors":"Antoine Marret, Torgeir Helland, Eddy Papore, Frederic Le-Naour, E. Pratt, R. Vivet, Fredrik Andreas Møller, Knut Edmund Haugen","doi":"10.4043/32217-ms","DOIUrl":"https://doi.org/10.4043/32217-ms","url":null,"abstract":"\u0000 This paper presents the foundations as well as the main outcomes of the development, industrialization, fabrication and installation of the TechnipFMC's Electrically Trace Heated Pipe-in-Pipe (ETH-PiP) 2.0 for application on the Fenja field development.\u0000 The Fenja Field is located offshore mid-Norway at a water depth of approximately 324m, and consists of two separate hydrocarbon accumulations, the Pil and Bue reservoirs, with fluid properties leading to flow assurance challenges such as hydrates and wax formation. Following successful deployment of a first generation of Electrically Trace Heated Pipe-in-Pipe on the TotalEnergies (then Total) Islay Field in 2011, TechnipFMC have conducted the development and industrialization of a completely new generation of ETH-PiP 2.0.\u0000 The new ETH-PiP 2.0 has higher electrical rating of 3.8/6.6kV to overcome the specificities of the Fenja field development including the long tie-back distance of 36.8km which makes Fenja the longest (and largest) ETH-PiP in the world.\u0000 Subsequent to successful qualification of the ETH-PiP system, TechnipFMC has completed the manufacturing of 36.8km of ETH-PiP stalks at the Evanton spoolbase. These were then loaded out onto the Deep Energy pipelay vessel for subsea installation by reel lay.\u0000 The installation was finalized in summer 2021 with the complete system being connected and tested from the Njord A platform after it returned from refurbishment in spring 2022.\u0000 This paper presents the qualification, industrialization, assembly and installation of the new generation ETH-PiP 2.0 which forms part of the Fenja field development.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"245 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122467084","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 2009, the Vito field was discovered in more than 4,000 ft of water approximately 150 miles offshore from New Orleans, Louisiana. The project produces from reservoirs nearly 30,000 feet below sea level. This paper introduces the challenges of the multidiscipline project from a project management perspective and to compliment and introduce the several other Vito Floating Production System (FPS) papers submitted to OTC 2023 which are listed in the references of this papar. The original Vito project execution strategy was to replicate the mega-project of Appomattox. As the industry and market began to change in 2015, the project faced significant financial hurdles, and the project team decided to refresh the design concept to reduce cost and simplify. The new design included a smaller FPS, simplified operating model, and simplified subsea equipment. This allowed the project to open the contracting strategy to include more options including different fabrication sites, smaller offshore installation vessels, and include more vendor options in various disciplines. The Vito host, subsea system, and export were redesigned with the mindset of "simpler = safer = cost competitive". The host was radically reduced and limited to a 10,000 st single deck lift enabling simplified integration and pre-commissioning at the ground level to optimize work pace. The mooring system was streamlined to remove on-vessel winching equipment and storage, simplifying the hull and utilizing common anchor handler vessels for host installation. A simplified Subsea Umbilical Riser and Flowline (SURF) design was competitively scoped by focusing on minimum amount of equipment to safely gather and transport the fluids and minimum amount of equipment to manage flow assurance risks. The export pipelines leveraged industry capabilities to simplify the design and contracting approach. The simplified minimum technical scope for the topsides and subsea reduced operations personnel needed offshore and upskilling the operations staff enabled a simplified overall design concept. The world is dynamic and when changes are extreme, mega-projects must be reworked and mobilized for the new environment. Vito project is a story of change, simplification, and adaptation.
{"title":"Vito Project Overview","authors":"K. Shallenberger, Stacy Marie Fresquez","doi":"10.4043/32254-ms","DOIUrl":"https://doi.org/10.4043/32254-ms","url":null,"abstract":"\u0000 In 2009, the Vito field was discovered in more than 4,000 ft of water approximately 150 miles offshore from New Orleans, Louisiana. The project produces from reservoirs nearly 30,000 feet below sea level. This paper introduces the challenges of the multidiscipline project from a project management perspective and to compliment and introduce the several other Vito Floating Production System (FPS) papers submitted to OTC 2023 which are listed in the references of this papar.\u0000 The original Vito project execution strategy was to replicate the mega-project of Appomattox. As the industry and market began to change in 2015, the project faced significant financial hurdles, and the project team decided to refresh the design concept to reduce cost and simplify. The new design included a smaller FPS, simplified operating model, and simplified subsea equipment. This allowed the project to open the contracting strategy to include more options including different fabrication sites, smaller offshore installation vessels, and include more vendor options in various disciplines.\u0000 The Vito host, subsea system, and export were redesigned with the mindset of \"simpler = safer = cost competitive\". The host was radically reduced and limited to a 10,000 st single deck lift enabling simplified integration and pre-commissioning at the ground level to optimize work pace. The mooring system was streamlined to remove on-vessel winching equipment and storage, simplifying the hull and utilizing common anchor handler vessels for host installation. A simplified Subsea Umbilical Riser and Flowline (SURF) design was competitively scoped by focusing on minimum amount of equipment to safely gather and transport the fluids and minimum amount of equipment to manage flow assurance risks. The export pipelines leveraged industry capabilities to simplify the design and contracting approach. The simplified minimum technical scope for the topsides and subsea reduced operations personnel needed offshore and upskilling the operations staff enabled a simplified overall design concept.\u0000 The world is dynamic and when changes are extreme, mega-projects must be reworked and mobilized for the new environment. Vito project is a story of change, simplification, and adaptation.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"126 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130195834","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}
Current offshore wind activities within the Atlantic Outer Continental Shelf are within water depths suitable for fixed-bottom foundations, generally considered as water depths shallower than 60 m. Recent BOEM designated call areas within the Central Atlantic include two areas on the continental slope in water depths greater than 200 m that will require floating offshore wind turbines. The objective of this study is to expand upon a previously completed BOEM-funded desktop study and focus on the geological and geotechnical conditions and the engineering constraints for the deep-water Central Atlantic call areas E and F. This study focused on compiling public domain geophysical and geotechnical data to evaluate the seafloor and shallow subsurface geological and geotechnical conditions relevant to offshore wind within the area of interest. Data available from published scientific literature and government agencies were integrated and evaluated using GIS and seismic interpretation software to identify and map geohazards, seabed and subsurface conditions, and key stratigraphic geotechnical units. Our evaluation of the area of interest indicates generally favorable conditions for floating offshore wind development, with site-specific considerations to be factored into engineering design. Soil provinces with similar geologic characteristics and geotechnical properties include the upper slope (roughly 200 m to 2000 m water depths) and the lower slope (greater than 2000 m water depth). General sediment conditions for both these provinces include Holocene-Pleistocene age silts and clays with intervals of sandy clay or sandy layers related to mass transport deposits (MTDs) from gravity flows. A key difference between the provinces is the potential for older geological units, such as the coastal plain deposits (CPD) within the foundation depth of interest proximal to the upper slope, and a higher frequency of submarine landslide deposits within the lower slope. The potential for slope instability and steep seabed gradients will be a constraint for these developments, as well as the potential for hard grounds, such as submarine landslide blocks or authigenic carbonate/benthic features. Based on these conditions, the suitability of various anchor concepts is discussed.
{"title":"Geological and Geotechnical Considerations for Floating Offshore Wind Infrastructure within the U.S. Atlantic OCS","authors":"J. E. Fisher, S. Esmailzadeh, J. Fillingham","doi":"10.4043/32578-ms","DOIUrl":"https://doi.org/10.4043/32578-ms","url":null,"abstract":"\u0000 Current offshore wind activities within the Atlantic Outer Continental Shelf are within water depths suitable for fixed-bottom foundations, generally considered as water depths shallower than 60 m. Recent BOEM designated call areas within the Central Atlantic include two areas on the continental slope in water depths greater than 200 m that will require floating offshore wind turbines. The objective of this study is to expand upon a previously completed BOEM-funded desktop study and focus on the geological and geotechnical conditions and the engineering constraints for the deep-water Central Atlantic call areas E and F.\u0000 This study focused on compiling public domain geophysical and geotechnical data to evaluate the seafloor and shallow subsurface geological and geotechnical conditions relevant to offshore wind within the area of interest. Data available from published scientific literature and government agencies were integrated and evaluated using GIS and seismic interpretation software to identify and map geohazards, seabed and subsurface conditions, and key stratigraphic geotechnical units.\u0000 Our evaluation of the area of interest indicates generally favorable conditions for floating offshore wind development, with site-specific considerations to be factored into engineering design. Soil provinces with similar geologic characteristics and geotechnical properties include the upper slope (roughly 200 m to 2000 m water depths) and the lower slope (greater than 2000 m water depth). General sediment conditions for both these provinces include Holocene-Pleistocene age silts and clays with intervals of sandy clay or sandy layers related to mass transport deposits (MTDs) from gravity flows. A key difference between the provinces is the potential for older geological units, such as the coastal plain deposits (CPD) within the foundation depth of interest proximal to the upper slope, and a higher frequency of submarine landslide deposits within the lower slope. The potential for slope instability and steep seabed gradients will be a constraint for these developments, as well as the potential for hard grounds, such as submarine landslide blocks or authigenic carbonate/benthic features. Based on these conditions, the suitability of various anchor concepts is discussed.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125732690","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}
Leif Nordenstam, Matt Krueger, Keven Michael O’Connor, Kyle O’Keefe
Thousands of liner systems are deployed annually to reduce cost, time, and risk compared to casing long strings. Early liner hanger systems would require mechanical actuation (rotating or reciprocating drill pipe) to deploy the liner section. This method limited the ability to rotate and reciprocate the liner string when encountering high deviation and restrictions, particularly as well trajectories moved towards higher levels of deviation. The hydraulic actuated systems, found in both conventional and expandable liner hanger systems, allow the liner string to be manipulated with rotation and reciprocation. The traditional method for setting a hydraulic liner hanger includes the use of single or multiple activation balls being dropped from the surface so that pressure can be applied to the work string to function the hydraulic liner hanger and running tool. However, in complex wells such as HPHT, deep-water, and extended-reach applications, many operational issues experienced with running hydraulic liner hangers are related to limited surface indications on what is transpiring downhole and not landing the ball on seat, which can lead to Non Productive Time (NPT). Developing a liner hanger system that provides real time downhole readings throughout the drill pipe string and does not rely on pipe manipulation or dropping activation balls from surface will dramatically decrease high impact NPT and increase the overall operational capabilities of liner hangers. To respond to these industry needs, a new system to deploy and actuate a liner hanger on demand was needed. This paper presents a novel system which utilizes distributed sensing along the work string by means of an acoustic telemetry network. The liner hanger system uses that same acoustic network to communicate to and actuate the liner hanger, removing many of the challenges facing liner installations.
{"title":"Acoustic Set Liner Hanger for HPHT Applications","authors":"Leif Nordenstam, Matt Krueger, Keven Michael O’Connor, Kyle O’Keefe","doi":"10.4043/32595-ms","DOIUrl":"https://doi.org/10.4043/32595-ms","url":null,"abstract":"\u0000 Thousands of liner systems are deployed annually to reduce cost, time, and risk compared to casing long strings. Early liner hanger systems would require mechanical actuation (rotating or reciprocating drill pipe) to deploy the liner section. This method limited the ability to rotate and reciprocate the liner string when encountering high deviation and restrictions, particularly as well trajectories moved towards higher levels of deviation. The hydraulic actuated systems, found in both conventional and expandable liner hanger systems, allow the liner string to be manipulated with rotation and reciprocation. The traditional method for setting a hydraulic liner hanger includes the use of single or multiple activation balls being dropped from the surface so that pressure can be applied to the work string to function the hydraulic liner hanger and running tool. However, in complex wells such as HPHT, deep-water, and extended-reach applications, many operational issues experienced with running hydraulic liner hangers are related to limited surface indications on what is transpiring downhole and not landing the ball on seat, which can lead to Non Productive Time (NPT).\u0000 Developing a liner hanger system that provides real time downhole readings throughout the drill pipe string and does not rely on pipe manipulation or dropping activation balls from surface will dramatically decrease high impact NPT and increase the overall operational capabilities of liner hangers. To respond to these industry needs, a new system to deploy and actuate a liner hanger on demand was needed. This paper presents a novel system which utilizes distributed sensing along the work string by means of an acoustic telemetry network. The liner hanger system uses that same acoustic network to communicate to and actuate the liner hanger, removing many of the challenges facing liner installations.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126083265","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}
Kazuma Takahashi, S. Naganawa, Elvar K Bjarkason, R. Mukai
Fiber-containing drilling fluids are expected to improve hole cleaning efficiency and have filtration properties that help to form a strong mud cake on the borehole wall. The objective of this study is to evaluate the filtration properties of drilling fluids containing a novel biodegradable polymer fiber. The novel 100% bio-based polymer, named PHBH (TM), biodegrades easily in a seawater environment. The filtration properties of drilling fluids containing PHBH fibers were investigated through static filtration tests using an API (LPLT) filter press and a high-temperature and high-pressure (HPHT) filter press. The HPHT tests were conducted at 93°C (200°F). The tested base fluids contained 1.5wt% of bentonite or sepiolite clay, and 0.1 to 0.4wt% of polyanionic cellulose (PAC-HG) as a viscosifier. Sepiolite was considered since it is more thermally stable than bentonite. From the results of API and HPHT filtration tests, adding 0.4wt% PHBH fibers reduced the amount of filtrate by approximately 5 to 7%, and the thicknesses of mud cake by approximately 24 to 34%. Among the 3, 5, 10, and 14 mm-long fibers tested, 14 mm long fibers resulted in the maximum reductions in filtrate and mud-cake thickness. Analysis of the solid concentration in the suggested that thin and strong mud cakes might form by adding the PHBH fibers for both bentonite- and sepiolite-based fluids. Compared to the existing commercial fiber additives, the novelty of application of the new biodegradable fiber-containing drilling fluids to prevention of lost circulation or borehole wall strengthening in offshore shallow weak formations is highly environmentally-friendly for sustainable oil and gas developments. The biodegradable fiber-containing fluids can be applied in various uses like completion fluid, cementing spacer, etc.
{"title":"Filtration of Biodegradable Fiber-Containing Drilling Fluids for Offshore Shallow Weak Formations","authors":"Kazuma Takahashi, S. Naganawa, Elvar K Bjarkason, R. Mukai","doi":"10.4043/32274-ms","DOIUrl":"https://doi.org/10.4043/32274-ms","url":null,"abstract":"\u0000 Fiber-containing drilling fluids are expected to improve hole cleaning efficiency and have filtration properties that help to form a strong mud cake on the borehole wall. The objective of this study is to evaluate the filtration properties of drilling fluids containing a novel biodegradable polymer fiber.\u0000 The novel 100% bio-based polymer, named PHBH (TM), biodegrades easily in a seawater environment. The filtration properties of drilling fluids containing PHBH fibers were investigated through static filtration tests using an API (LPLT) filter press and a high-temperature and high-pressure (HPHT) filter press. The HPHT tests were conducted at 93°C (200°F). The tested base fluids contained 1.5wt% of bentonite or sepiolite clay, and 0.1 to 0.4wt% of polyanionic cellulose (PAC-HG) as a viscosifier. Sepiolite was considered since it is more thermally stable than bentonite.\u0000 From the results of API and HPHT filtration tests, adding 0.4wt% PHBH fibers reduced the amount of filtrate by approximately 5 to 7%, and the thicknesses of mud cake by approximately 24 to 34%. Among the 3, 5, 10, and 14 mm-long fibers tested, 14 mm long fibers resulted in the maximum reductions in filtrate and mud-cake thickness. Analysis of the solid concentration in the suggested that thin and strong mud cakes might form by adding the PHBH fibers for both bentonite- and sepiolite-based fluids.\u0000 Compared to the existing commercial fiber additives, the novelty of application of the new biodegradable fiber-containing drilling fluids to prevention of lost circulation or borehole wall strengthening in offshore shallow weak formations is highly environmentally-friendly for sustainable oil and gas developments. The biodegradable fiber-containing fluids can be applied in various uses like completion fluid, cementing spacer, etc.","PeriodicalId":196855,"journal":{"name":"Day 2 Tue, May 02, 2023","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115229498","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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