P. Aalberts, A. Ibekwe, R. Hageman, Gbolagade Oguntola, Josiah Izuchukwu, Kjeld Sorensen, Varadarajan Nadathur, R. Vliet
This paper describes the implementation of the Advisory Hull Monitoring System (AHMS) onboard the existing Bonga FPSO (Nigeria) during operations and production. AHMS has been developed for FPSOs in the Monitas Joint Industry Project as a fully automated system, which explains and advises on the fatigue lifetime consumption of the hull of FPSOs. The explanations and advice offered are based on a comparison between the design and the actual predicted lifetime consumption by replacing the design parameters including environmental and operational conditions with the measured data. The system differentiates between the contributions of environmental and operational conditions as well as hydro-mechanic and structural responses. The AHMS system comprises hardware and software for smart data gathering and processing. AHMS hardware includes strain- type sensors on deck and inside the Water Ballast Tanks (WBTs) and/or void spaces and interfaces with external systems including the Computer Loading Instrument (CLI), Gyro and metocean system. AHMS has generally been installed onboard newly built floaters including the Usan FPSO (Nigeria), Clov FPSO (Angola), Ichthys FPSO (Australia) and Moho Nord FPU (Congo). Being in operation since 2005, the Bonga FPSO has lived 14 of its 20-year design life. Given the constraints inherent in her design, deployment of the AHMS for the FPSO's hull fatigue life monitoring therefore presented unique installation challenges to overcome as would be expected for ageing brownfield assets. To add to this challenge, the installation was carried out during production and so required strict adherence to the stringent safety requirements of Simultaneous Operations (SIMOPs) on a live plant. This paper describes in detail, the AHMS hardware, the complexity and challenges of their installation for the Bonga FPSO and highlights lessons learned for typical brownfiled retrofit of this nature. OCTOPUS MONITAS, the software of the AHMS system for the smart data processing, calculates onboard fatigue lifetime consumption of the hull and explains the differences against design predictions. Methodology of the software is herein described, and the first set of measurements taken from the Bonga FPSO as well as preliminary results produced by the software are similarly presented.
{"title":"Advisory Hull Monitoring System for the Bonga FPSO","authors":"P. Aalberts, A. Ibekwe, R. Hageman, Gbolagade Oguntola, Josiah Izuchukwu, Kjeld Sorensen, Varadarajan Nadathur, R. Vliet","doi":"10.4043/29250-MS","DOIUrl":"https://doi.org/10.4043/29250-MS","url":null,"abstract":"\u0000 This paper describes the implementation of the Advisory Hull Monitoring System (AHMS) onboard the existing Bonga FPSO (Nigeria) during operations and production. AHMS has been developed for FPSOs in the Monitas Joint Industry Project as a fully automated system, which explains and advises on the fatigue lifetime consumption of the hull of FPSOs. The explanations and advice offered are based on a comparison between the design and the actual predicted lifetime consumption by replacing the design parameters including environmental and operational conditions with the measured data. The system differentiates between the contributions of environmental and operational conditions as well as hydro-mechanic and structural responses. The AHMS system comprises hardware and software for smart data gathering and processing. AHMS hardware includes strain- type sensors on deck and inside the Water Ballast Tanks (WBTs) and/or void spaces and interfaces with external systems including the Computer Loading Instrument (CLI), Gyro and metocean system. AHMS has generally been installed onboard newly built floaters including the Usan FPSO (Nigeria), Clov FPSO (Angola), Ichthys FPSO (Australia) and Moho Nord FPU (Congo). Being in operation since 2005, the Bonga FPSO has lived 14 of its 20-year design life. Given the constraints inherent in her design, deployment of the AHMS for the FPSO's hull fatigue life monitoring therefore presented unique installation challenges to overcome as would be expected for ageing brownfield assets. To add to this challenge, the installation was carried out during production and so required strict adherence to the stringent safety requirements of Simultaneous Operations (SIMOPs) on a live plant. This paper describes in detail, the AHMS hardware, the complexity and challenges of their installation for the Bonga FPSO and highlights lessons learned for typical brownfiled retrofit of this nature.\u0000 OCTOPUS MONITAS, the software of the AHMS system for the smart data processing, calculates onboard fatigue lifetime consumption of the hull and explains the differences against design predictions. Methodology of the software is herein described, and the first set of measurements taken from the Bonga FPSO as well as preliminary results produced by the software are similarly presented.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78664259","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the drivers used to determine the preferred method for pre-commissioning the flexible flowlines for a shallow water gas development project in Trinidad by BP. Upon mechanical completion, the flexible flowlines are required to be hydrotested to ensure the system is leak-free. After the hydrostatic pressure test, the industry norm is to dewater and dry the flowlines. However, the system architecture (one flexible flowline per well) requires subsea maneuvers around the subsea trees, which brings about significant risk of damaging the trees. Several alternatives (shown below) were proposed:Base Case – The original plan was to remove the tree choke insert, then insert the newly developed temporary subsea pig receiver into the choke body. Nitrogen (N2) and gel pigs are used to push water from the topsides to the subsea tree. The specification is to reduce the flowline water content to 5% or less.Alternative 1 – Involved not using the gel pigs and only using N2 gas to push the water out from the topside to the subsea tree. This alternative would not require a temporary pig receiver, which reduces the chance of damaging the choke insert profile.Alternative 2 – Involves dewatering the flowline using the umbilical tubes (methanol lines). This has an advantage in that there is no need to pull the subsea tree choke insert, which reduces the risk of damaging the trees.Alternative 3 – Do nothing and leave the seawater in the flowlines. The production stream would be used to push the water into the production system during first gas production (well offloading). The study concluded that all three alternatives were technically feasible. For Alternative 3, an additional assessment was conducted to determine the impact of seawater on the flexible pipe when exposed for an extended time. Ultimately, the decision was made to not dewater the flowlines. The corresponding well offloading (flow back) procedure and a contingency plan were then developed. The Juniper development had first gas in September 2017. The first well offloading with integrated de-watering went as planned. The decision of not-dewatering the flowlines was proven to be a good decision by reducing risks, costs and simplifying the schedule during the commissioning period.
{"title":"A Pre-Commissioning Decision: Dewater the Flexible Flowlines or Not","authors":"Marlycia Banks, W. Meng, Julio Jover Azpurua","doi":"10.4043/29520-MS","DOIUrl":"https://doi.org/10.4043/29520-MS","url":null,"abstract":"\u0000 This paper presents the drivers used to determine the preferred method for pre-commissioning the flexible flowlines for a shallow water gas development project in Trinidad by BP.\u0000 Upon mechanical completion, the flexible flowlines are required to be hydrotested to ensure the system is leak-free. After the hydrostatic pressure test, the industry norm is to dewater and dry the flowlines. However, the system architecture (one flexible flowline per well) requires subsea maneuvers around the subsea trees, which brings about significant risk of damaging the trees.\u0000 Several alternatives (shown below) were proposed:Base Case – The original plan was to remove the tree choke insert, then insert the newly developed temporary subsea pig receiver into the choke body. Nitrogen (N2) and gel pigs are used to push water from the topsides to the subsea tree. The specification is to reduce the flowline water content to 5% or less.Alternative 1 – Involved not using the gel pigs and only using N2 gas to push the water out from the topside to the subsea tree. This alternative would not require a temporary pig receiver, which reduces the chance of damaging the choke insert profile.Alternative 2 – Involves dewatering the flowline using the umbilical tubes (methanol lines). This has an advantage in that there is no need to pull the subsea tree choke insert, which reduces the risk of damaging the trees.Alternative 3 – Do nothing and leave the seawater in the flowlines. The production stream would be used to push the water into the production system during first gas production (well offloading).\u0000 The study concluded that all three alternatives were technically feasible. For Alternative 3, an additional assessment was conducted to determine the impact of seawater on the flexible pipe when exposed for an extended time. Ultimately, the decision was made to not dewater the flowlines. The corresponding well offloading (flow back) procedure and a contingency plan were then developed.\u0000 The Juniper development had first gas in September 2017. The first well offloading with integrated de-watering went as planned. The decision of not-dewatering the flowlines was proven to be a good decision by reducing risks, costs and simplifying the schedule during the commissioning period.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85180380","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}
G. Campos, T. Piedade, A. Ramos, J. Anjos, A. Azevedo, João Paulo Sanseverino Abdu, F. Terra, Leonardo Pacheco da Silva
During the production phase of the PW1 well, an unintentional operation depressurized the annulus A below its design limit, resulting in a progressive casing collapse from the surface casing to the tubing. Therefore, it was not possible to abandon the well conventionally. This complex abandonment scenario demanded for a rig to drill an intervention well (IW1) and set up the safety barriers. The IW1 well was successfully drilled, intercepting the production well (PW1) at 3,056-m (TD) through a 1.10-m long slotted window. The whole operation was monitored via PDG from the PW1, making possible to identify the exact moment that the interception occurred and safely displacing the cementing fluids, while avoiding the risk of fracturing exposed formations. Numerical simulations and real time monitoring of the injection pressure demonstrated the success of the operation with excellent adherence between the plan and the execution phases. Due to the restrictions imposed by the characteristics of the PW1 reservoir, production tubing and its accessories, such as, slotted liner, ESP, NRV and DHSV, it was necessary to evaluate plugging materials that could be displaced through those restrictions without reaching the fracture limit of formation at the IW1 casing shoe. Ultrafine cement, pure resin and combinations of both were selected for their ability to pass through restrictions and resist to contamination by fluids present in the well, while also developing compressive strength to provide zonal isolation. Optimized plugging formulations were evaluated by passing them through artificial porous media, which simulated the PW1 well restrictions. After 87 operational days, the PW1 well was successfully abandoned. A 79-m long cement plug was set in the annulus A and inside the tubing. The safety barrier was established and verified with pressure tests according to the regulatory criteria imposed by the National Agency of Petroleum, Natural Gas and Biofuels (ANP).
{"title":"Special P&A with Resin and Microcement Pumped from Interception Well Due to Multi-String Collapse","authors":"G. Campos, T. Piedade, A. Ramos, J. Anjos, A. Azevedo, João Paulo Sanseverino Abdu, F. Terra, Leonardo Pacheco da Silva","doi":"10.4043/29281-MS","DOIUrl":"https://doi.org/10.4043/29281-MS","url":null,"abstract":"\u0000 During the production phase of the PW1 well, an unintentional operation depressurized the annulus A below its design limit, resulting in a progressive casing collapse from the surface casing to the tubing. Therefore, it was not possible to abandon the well conventionally. This complex abandonment scenario demanded for a rig to drill an intervention well (IW1) and set up the safety barriers. The IW1 well was successfully drilled, intercepting the production well (PW1) at 3,056-m (TD) through a 1.10-m long slotted window. The whole operation was monitored via PDG from the PW1, making possible to identify the exact moment that the interception occurred and safely displacing the cementing fluids, while avoiding the risk of fracturing exposed formations. Numerical simulations and real time monitoring of the injection pressure demonstrated the success of the operation with excellent adherence between the plan and the execution phases.\u0000 Due to the restrictions imposed by the characteristics of the PW1 reservoir, production tubing and its accessories, such as, slotted liner, ESP, NRV and DHSV, it was necessary to evaluate plugging materials that could be displaced through those restrictions without reaching the fracture limit of formation at the IW1 casing shoe. Ultrafine cement, pure resin and combinations of both were selected for their ability to pass through restrictions and resist to contamination by fluids present in the well, while also developing compressive strength to provide zonal isolation. Optimized plugging formulations were evaluated by passing them through artificial porous media, which simulated the PW1 well restrictions.\u0000 After 87 operational days, the PW1 well was successfully abandoned. A 79-m long cement plug was set in the annulus A and inside the tubing. The safety barrier was established and verified with pressure tests according to the regulatory criteria imposed by the National Agency of Petroleum, Natural Gas and Biofuels (ANP).","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85897231","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to provide insight into a few of the dominant hurdles applicants experience when preparing information for review by the US Bureau of Safety and Environmental Enforcement (BSEE) when applying for a permit to drill. Numerous requirements for the Application for Permit to Drill (APD) exist that can present a complex task of aligning documentation and information across multiple process participants that are not always apparent at the outset. The included information will follow the general path that exists in BSEE APD development, including 30 CFR §250.410, which defines some of those numerous requirements. The paper will include BSEE requirements in 30 CFR §250.410-16, -18 "How do I obtain approval to drill a well?" the BSEE APD Development Phase Flow-chart, 30 CFR §250.731 "BOP Systems and … Components", §250.713 "if I plan to use a MODU", and additional required compliance statements, and explain how the sources of information can differ from project to project and within groupings of defined requirement sets (BSEE 2016). The paper will also include a brief review of requirements set out by other parts of 30 CFR §250, not specifically delineated as part of the APD, but specifically required for execution.
{"title":"Drilling Permit Application Hurdles for Gulf of Mexico Oil and Gas Exploration","authors":"D. Crouch, J. Hoefler","doi":"10.4043/29615-MS","DOIUrl":"https://doi.org/10.4043/29615-MS","url":null,"abstract":"\u0000 The objective of this paper is to provide insight into a few of the dominant hurdles applicants experience when preparing information for review by the US Bureau of Safety and Environmental Enforcement (BSEE) when applying for a permit to drill. Numerous requirements for the Application for Permit to Drill (APD) exist that can present a complex task of aligning documentation and information across multiple process participants that are not always apparent at the outset. The included information will follow the general path that exists in BSEE APD development, including 30 CFR §250.410, which defines some of those numerous requirements.\u0000 The paper will include BSEE requirements in 30 CFR §250.410-16, -18 \"How do I obtain approval to drill a well?\" the BSEE APD Development Phase Flow-chart, 30 CFR §250.731 \"BOP Systems and … Components\", §250.713 \"if I plan to use a MODU\", and additional required compliance statements, and explain how the sources of information can differ from project to project and within groupings of defined requirement sets (BSEE 2016).\u0000 The paper will also include a brief review of requirements set out by other parts of 30 CFR §250, not specifically delineated as part of the APD, but specifically required for execution.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86062932","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this paper is to provide the results of key offshore oil and gas developments across the globe for common strategies and significant exceptions to those strategies. Most oil and gas companies have development processes consisting of the resource and terms attractive enough for development, what is the optimal path for development; detailed engineering and design; build and commission; operate and look back. Within this study, the projects examined reflect different producing basins, fluid type, and water and reservoir depths. Flow Assurance can be expressed as the coupling of multiphase flow and fluid phase behavior. There are only three questions to be answered for a pantheon of problems that can impede flow over the life of the development. The three questions are 1) will there be a flow assurance risk?; 2) how often will the issue require treatment?; and 3) can the risk be effectively managed by thermal, mechanical, and chemical means? The limitations of the strategies are becoming increasingly apparent as the requirements for system performance continue to become more demanding with changing and challenging offshore environment in the current dynamic market. Subsea technologies continue to be asked to facilitate recovering oil and gas while lowering cost while improving safety and operating efficiency to meet current industry challenges. Hence, there is a greater need to understand the flow assurance strategies to reduce overall field development costs and risk, and improve operability and reliability. Key flow assurance strategies adopted in various deepwater projects were considered for this study with an aim to summarize common strategies that arise and exceptions that could provide new strategies going forward.
{"title":"Effective Strategies for Flow Assurance Process Design and Execution","authors":"P. Kondapi, J. Creek, Y. D. Chin, R. Moe","doi":"10.4043/29399-MS","DOIUrl":"https://doi.org/10.4043/29399-MS","url":null,"abstract":"\u0000 The objective of this paper is to provide the results of key offshore oil and gas developments across the globe for common strategies and significant exceptions to those strategies. Most oil and gas companies have development processes consisting of the resource and terms attractive enough for development, what is the optimal path for development; detailed engineering and design; build and commission; operate and look back.\u0000 Within this study, the projects examined reflect different producing basins, fluid type, and water and reservoir depths. Flow Assurance can be expressed as the coupling of multiphase flow and fluid phase behavior. There are only three questions to be answered for a pantheon of problems that can impede flow over the life of the development. The three questions are 1) will there be a flow assurance risk?; 2) how often will the issue require treatment?; and 3) can the risk be effectively managed by thermal, mechanical, and chemical means?\u0000 The limitations of the strategies are becoming increasingly apparent as the requirements for system performance continue to become more demanding with changing and challenging offshore environment in the current dynamic market. Subsea technologies continue to be asked to facilitate recovering oil and gas while lowering cost while improving safety and operating efficiency to meet current industry challenges. Hence, there is a greater need to understand the flow assurance strategies to reduce overall field development costs and risk, and improve operability and reliability.\u0000 Key flow assurance strategies adopted in various deepwater projects were considered for this study with an aim to summarize common strategies that arise and exceptions that could provide new strategies going forward.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86068900","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The use of a unique, data-driven approach to remote condition monitoring of equipment maintenance has enabled a major offshore E&P producer to build and operate a a low-manned platform — a key step in its strategic goal to reduce per-barrel production costs to below $7. The field is 112 miles (180 km) off Norway’s coast, with the platform drawing first oil in December 2016. In January 2019 — after operating identical offshore and onshore platform control rooms — the company started conducting remote condition monitoring of platform machinery exclusively from its control room onshore in Trondheim, Norway, 620 miles (1,000 km) away. With the remote equipment condition monitoring done onshore, the operator is better able to optimize maintenance work and schedules. At the same time, it has contributed to a big reduction in the number of offshore personnel otherwise required, reducing operating costs and personnel risks substantially. In May 2018, Siemens entered into a long-term partnership with the operator to continue developing digital solutions in a closed-loop lifecycle approach, utilizing the digital twin concept from pre-FEED and FEED stages through construction, commissioning, and operations, with operations expected to continue for a minimum of 20-years. This paper will provide an update to a 2018 OTC conference presentation when this use case was introduced. Last year’s paper was based on operations and observations during 2017, the platform’s first full year of operation.
{"title":"Updated Case Study: The Pursuit of an Ultra-Low Manned Platform Pays Dividends in the North Sea","authors":"S. Settemsdal","doi":"10.4043/29606-MS","DOIUrl":"https://doi.org/10.4043/29606-MS","url":null,"abstract":"\u0000 The use of a unique, data-driven approach to remote condition monitoring of equipment maintenance has enabled a major offshore E&P producer to build and operate a a low-manned platform — a key step in its strategic goal to reduce per-barrel production costs to below $7. The field is 112 miles (180 km) off Norway’s coast, with the platform drawing first oil in December 2016. In January 2019 — after operating identical offshore and onshore platform control rooms — the company started conducting remote condition monitoring of platform machinery exclusively from its control room onshore in Trondheim, Norway, 620 miles (1,000 km) away. With the remote equipment condition monitoring done onshore, the operator is better able to optimize maintenance work and schedules. At the same time, it has contributed to a big reduction in the number of offshore personnel otherwise required, reducing operating costs and personnel risks substantially. In May 2018, Siemens entered into a long-term partnership with the operator to continue developing digital solutions in a closed-loop lifecycle approach, utilizing the digital twin concept from pre-FEED and FEED stages through construction, commissioning, and operations, with operations expected to continue for a minimum of 20-years. This paper will provide an update to a 2018 OTC conference presentation when this use case was introduced. Last year’s paper was based on operations and observations during 2017, the platform’s first full year of operation.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91436961","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}
J. Dalgliesh, Allen Jones, A. Palanisamy, Justin Schmauser
Artificial intelligence and machine learning algorithms provide energy companies with the possibility to digitally re-construct well histories, using both public and company specific historical well data. In this paper we discuss how oil and gas companies are creating a digital knowledge layer for oil and gas wells that provide a timeline of significant well events. Examples of key timeline events include, when drilling problems such as kicks happened, when blowout preventers were tested, when bottom hole pressures were taken, and when well interventions were done. This new generation of AI-driven applications are powered by a combination of a computational knowledge graphs and AI algorithms. These AI algorithms encode the expertise of subject-matter experts such as Petro-technical engineers and combine their experience with decades of historical well-events data extracted from databases, documents, and sensors to automatically create well event timelines. This technology enriches and combines companies’ internal siloed well data with public well data to create an integrated digital knowledge layer for wells. Engineers can optimize the life cycle of the wells by visually exploring this interactive timeline to understand and make decisions about the well. Petro-technical engineers have easy access to knowledge related to people, equipment, vendors, wells and more, so they can make better, more informed decisions faster. We show how we train the application's machine learning algorithms to read hundreds of thousands of historical reports to harvest knowledge about the well and store the extracted knowledge in an enterprise digital knowledge layer. By using the knowledge harvested and captured by this AI-driven application, experienced engineers can make better decisions that optimize the operations of their upstream assets.
{"title":"AI-Driven Well Timelines for Well Optimization","authors":"J. Dalgliesh, Allen Jones, A. Palanisamy, Justin Schmauser","doi":"10.4043/29487-MS","DOIUrl":"https://doi.org/10.4043/29487-MS","url":null,"abstract":"\u0000 Artificial intelligence and machine learning algorithms provide energy companies with the possibility to digitally re-construct well histories, using both public and company specific historical well data.\u0000 In this paper we discuss how oil and gas companies are creating a digital knowledge layer for oil and gas wells that provide a timeline of significant well events. Examples of key timeline events include, when drilling problems such as kicks happened, when blowout preventers were tested, when bottom hole pressures were taken, and when well interventions were done.\u0000 This new generation of AI-driven applications are powered by a combination of a computational knowledge graphs and AI algorithms. These AI algorithms encode the expertise of subject-matter experts such as Petro-technical engineers and combine their experience with decades of historical well-events data extracted from databases, documents, and sensors to automatically create well event timelines. This technology enriches and combines companies’ internal siloed well data with public well data to create an integrated digital knowledge layer for wells. Engineers can optimize the life cycle of the wells by visually exploring this interactive timeline to understand and make decisions about the well.\u0000 Petro-technical engineers have easy access to knowledge related to people, equipment, vendors, wells and more, so they can make better, more informed decisions faster. We show how we train the application's machine learning algorithms to read hundreds of thousands of historical reports to harvest knowledge about the well and store the extracted knowledge in an enterprise digital knowledge layer. By using the knowledge harvested and captured by this AI-driven application, experienced engineers can make better decisions that optimize the operations of their upstream assets.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86541469","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Sum, Xianwei Zhang, Jeong-Hoon Sa, B. Lee, T. Austvik, Xiaoyun Li, K. Askvik
Deadlegs are defined as pipe sections in intermittent use for production or special services in oil/gas production systems. Deadlegs often pose hydrate control challenges to gas and oil production systems as the fluid inside is close to stagnant and therefore can be rapidly cooled by the environment without proper insulation or heat tracing. Water vapor can condense in the deadleg, resulting in a potential hydrate risk. Over time the deadleg may be blocked completely by hydrates. The hydrate challenges, if not properly managed, can cause severe consequences in terms of safety and cost for oil/gas productions. A systematic study has been performed to better understand the process and mechanism of hydrate deposition in deadlegs. To study hydrate deposition in deadlegs experimentally, laboratory scale deadleg systems were designed and built to consider pipe sizes of 1-, 2-, 3-, and 4-in. inner diameter and approximately 50 in. long. The pipes were gas-filled and saturated with water from a reservoir at the bottom of the pipe. The experimental work focused on measuring hydrate deposition, and in some cases, plugging, for different water reservoir temperatures (30 to 80 °C), pipe wall temperatures (-10 to 15 °C), and duration (1 to 84 days). The results from measurements provided insights into the dynamic process of hydrate deposition, such as the mechanism for hydrate deposition, plugging, and distribution along the pipe.
{"title":"Hydrate Management for Hydrate Deposition in Gas-Filled Vertical Pipes","authors":"A. Sum, Xianwei Zhang, Jeong-Hoon Sa, B. Lee, T. Austvik, Xiaoyun Li, K. Askvik","doi":"10.4043/29632-MS","DOIUrl":"https://doi.org/10.4043/29632-MS","url":null,"abstract":"\u0000 Deadlegs are defined as pipe sections in intermittent use for production or special services in oil/gas production systems. Deadlegs often pose hydrate control challenges to gas and oil production systems as the fluid inside is close to stagnant and therefore can be rapidly cooled by the environment without proper insulation or heat tracing. Water vapor can condense in the deadleg, resulting in a potential hydrate risk. Over time the deadleg may be blocked completely by hydrates. The hydrate challenges, if not properly managed, can cause severe consequences in terms of safety and cost for oil/gas productions. A systematic study has been performed to better understand the process and mechanism of hydrate deposition in deadlegs. To study hydrate deposition in deadlegs experimentally, laboratory scale deadleg systems were designed and built to consider pipe sizes of 1-, 2-, 3-, and 4-in. inner diameter and approximately 50 in. long. The pipes were gas-filled and saturated with water from a reservoir at the bottom of the pipe. The experimental work focused on measuring hydrate deposition, and in some cases, plugging, for different water reservoir temperatures (30 to 80 °C), pipe wall temperatures (-10 to 15 °C), and duration (1 to 84 days). The results from measurements provided insights into the dynamic process of hydrate deposition, such as the mechanism for hydrate deposition, plugging, and distribution along the pipe.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79509383","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}
Christophe Vielliard, K. Hester, F. Roccaforte, A. D. Lullo, L. Assecondi, Hesham Elkhafif, A. Ewis, S. Sabbagh, Harald Solheim, A. Lupeau
The Zohr subsea production system, around 180 km off the coast of Egypt in 1,500-m water depth, was configured with a novel metering system providing the necessary functionalities for optimized hydrate inhibition. Different subsea measurements from startup and normal production phases were obtained and combined to extract valuable information regarding water production and to monitor hydrate inhibitor dosage in real time. Conventional hydrate inhibition system overdesign and overdosage would have had a significant impact on the technical and financial viability of the Zohr development, considering that no monoethylene glycol (MEG) regeneration capability was available at startup due to the fast-track nature of the project. Therefore, it was critical to limit the use of MEG, selected as hydrate inhibitor, in order to manage the available storage capacity. A data interpretation model was developed for the subsea water analysis sensor based on flow loop testing and analytical methods, allowing for real-time measurement of the MEG dosage for each well. Flow assurance modeling was performed to validate subsea measurements, and to explore model limitations and enhancements. Field data comparisons provided unprecedented insight into unexpected reservoir behavior several weeks faster than measuring fluids arriving onshore, considering the 220-km tieback distance. Indeed, the produced fluids at startup contained water at an order of magnitude more than initially expected, which would normally have resulted in underinhibition and a possible hydrate blockage risk. The subsea measurement system allows for MEG dosage to be monitored and injection flow rates to be adjusted in real time, from the first day of production, to respond to the fluids produced subsea. With only two wells initially producing in a 26-in, 220-km-long flowline, up to 5 weeks were required until produced water was received onshore for sampling. Data analytics were applied to validate the measurements obtained, identify trends, and anticipate onshore fluid arrival conditions weeks in advance. The field data also allowed to identify areas requiring improvement and to specify additional functionality development needs. The use of innovative subsea metering and measurement systems has enabled a safe startup of the field while meeting the first-gas target date. This is the first time in the industry that a direct hydrate inhibitor concentration monitoring and control, aimed at real-time hydrate management, has been achieved subsea for gas fields. The success of this innovative application of a subsea water analysis sensor was made possible through an unusual level of collaboration and openness between the field operators and subsea hardware providers. The cooperation that occurred on the Zohr Field development, from early engineering activities to operational support, has allowed for the combined team to advance the data interpretation models, improve the concept and obtain great value f
{"title":"Real-Time Subsea Hydrate Management in the World's Longest Subsea Tieback","authors":"Christophe Vielliard, K. Hester, F. Roccaforte, A. D. Lullo, L. Assecondi, Hesham Elkhafif, A. Ewis, S. Sabbagh, Harald Solheim, A. Lupeau","doi":"10.4043/29232-MS","DOIUrl":"https://doi.org/10.4043/29232-MS","url":null,"abstract":"\u0000 The Zohr subsea production system, around 180 km off the coast of Egypt in 1,500-m water depth, was configured with a novel metering system providing the necessary functionalities for optimized hydrate inhibition. Different subsea measurements from startup and normal production phases were obtained and combined to extract valuable information regarding water production and to monitor hydrate inhibitor dosage in real time.\u0000 Conventional hydrate inhibition system overdesign and overdosage would have had a significant impact on the technical and financial viability of the Zohr development, considering that no monoethylene glycol (MEG) regeneration capability was available at startup due to the fast-track nature of the project. Therefore, it was critical to limit the use of MEG, selected as hydrate inhibitor, in order to manage the available storage capacity.\u0000 A data interpretation model was developed for the subsea water analysis sensor based on flow loop testing and analytical methods, allowing for real-time measurement of the MEG dosage for each well. Flow assurance modeling was performed to validate subsea measurements, and to explore model limitations and enhancements.\u0000 Field data comparisons provided unprecedented insight into unexpected reservoir behavior several weeks faster than measuring fluids arriving onshore, considering the 220-km tieback distance. Indeed, the produced fluids at startup contained water at an order of magnitude more than initially expected, which would normally have resulted in underinhibition and a possible hydrate blockage risk. The subsea measurement system allows for MEG dosage to be monitored and injection flow rates to be adjusted in real time, from the first day of production, to respond to the fluids produced subsea. With only two wells initially producing in a 26-in, 220-km-long flowline, up to 5 weeks were required until produced water was received onshore for sampling. Data analytics were applied to validate the measurements obtained, identify trends, and anticipate onshore fluid arrival conditions weeks in advance. The field data also allowed to identify areas requiring improvement and to specify additional functionality development needs.\u0000 The use of innovative subsea metering and measurement systems has enabled a safe startup of the field while meeting the first-gas target date. This is the first time in the industry that a direct hydrate inhibitor concentration monitoring and control, aimed at real-time hydrate management, has been achieved subsea for gas fields. The success of this innovative application of a subsea water analysis sensor was made possible through an unusual level of collaboration and openness between the field operators and subsea hardware providers. The cooperation that occurred on the Zohr Field development, from early engineering activities to operational support, has allowed for the combined team to advance the data interpretation models, improve the concept and obtain great value f","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84315666","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}
Gary H. Farrow, A. Potts, Simon Dimopoulos, A. Kilner
The first phase of the Chain FEARS (Finite Element Analysis of Residual Strength) Joint Industry Project (JIP) aimed to develop guidance for the determination of a rational discard criteria for mooring chains subject to severe pitting corrosion which, based on current code requirements, would otherwise require immediate removal and replacement. Critical to the development of rational discard criteria is the ability to accurately estimate the residual strength of a corrosion and wear degraded chain, and to have as a benchmark for loss in strength, an accurate estimate of the chain in its as-new condition. A Finite Element Analyses (FEA) residual capacity assessment method was first developed and correlated against available break strength test data of corrosion degraded links [1], and the Predicted Break Load (PBL) of as-new links was established as a benchmark for loss of strength [2]. The validated FEA method for the determination of chain residual capacity was employed as a basis to establish an understanding of the effects of corroded chain and to determine the underlying relationship between loss of chain capacity and both uniform and mega pitting corrosion levels. The investigation sought through the conduct a series of FEA assessments employing a parametric model of idealized degraded chain links to derive the theoretical relationship beteen the residual capacity for varying levels of uniform corrosion, and the residual capacity for varying size, locations and shapes of mega pit corrosion degradation. This paper presents the findings of the investigation into the effects of uniform and mega pitting corrosion on degraded chain residual capacity and the correlation of the relationship with physical break test data, the findings of which forms the basis for development of a rational guideline for chain discard criteria whereby degraded mooring chain can be assessed in respect of the need for replacement.
{"title":"Effects of Uniform and Mega Pitting Corrosion on Residual Strength of Degraded Offshore Mooring Chain","authors":"Gary H. Farrow, A. Potts, Simon Dimopoulos, A. Kilner","doi":"10.4043/29402-MS","DOIUrl":"https://doi.org/10.4043/29402-MS","url":null,"abstract":"\u0000 The first phase of the Chain FEARS (Finite Element Analysis of Residual Strength) Joint Industry Project (JIP) aimed to develop guidance for the determination of a rational discard criteria for mooring chains subject to severe pitting corrosion which, based on current code requirements, would otherwise require immediate removal and replacement.\u0000 Critical to the development of rational discard criteria is the ability to accurately estimate the residual strength of a corrosion and wear degraded chain, and to have as a benchmark for loss in strength, an accurate estimate of the chain in its as-new condition. A Finite Element Analyses (FEA) residual capacity assessment method was first developed and correlated against available break strength test data of corrosion degraded links [1], and the Predicted Break Load (PBL) of as-new links was established as a benchmark for loss of strength [2].\u0000 The validated FEA method for the determination of chain residual capacity was employed as a basis to establish an understanding of the effects of corroded chain and to determine the underlying relationship between loss of chain capacity and both uniform and mega pitting corrosion levels. The investigation sought through the conduct a series of FEA assessments employing a parametric model of idealized degraded chain links to derive the theoretical relationship beteen the residual capacity for varying levels of uniform corrosion, and the residual capacity for varying size, locations and shapes of mega pit corrosion degradation.\u0000 This paper presents the findings of the investigation into the effects of uniform and mega pitting corrosion on degraded chain residual capacity and the correlation of the relationship with physical break test data, the findings of which forms the basis for development of a rational guideline for chain discard criteria whereby degraded mooring chain can be assessed in respect of the need for replacement.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83307671","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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