Tyler Skowronek, A. Kalia, Hans Fredrik Lindøen Kjellnes, Ana Serrentino, C. Chidiac, T. Mercer, Simon Holyfield
The downturn has impacted our industry in many ways, not only in terms of budget cuts and headcount reductions but also in changing the way organizations work. The downturn has enabled the creation of novel technologies and efficient development plans such as phased development and early production systems that are transforming the industry, and the increased collaboration between operators and suppliers has been unprecedented. This paper discusses recent technology developments that have and will continue to reshape the approach to phased field developments. For many years, the concept of phased field development has focused on reducing the expense of reaching first oil while planning the development for maximum recovery and deploying technology blocks that enable future add-ons for optimal asset return on investment (ROI). Game-changing efficiency resulting from earlier engagement with customers, paired with the latest technology and tools, can maximize the potential of a phased field development. Using real-world development data as a basis, this paper details how operators can use current technology and tools to enable efficient phased field development. The case study discusses the benefits of using integrated field development and planning solutions that provide operators and suppliers a robust cloud-based collaboration solution for planning and evaluating various field development options and associated cost and schedules estimates at the click of a button. The paper then shows the impact that technology such as all-electric solutions, boosting and compression, pipeline solutions, and modular product solutions can have on the decision-making process for upcoming projects.
{"title":"Novel Technology Solutions Enable Phased Field Development to Maximize Returns and Minimize Risks","authors":"Tyler Skowronek, A. Kalia, Hans Fredrik Lindøen Kjellnes, Ana Serrentino, C. Chidiac, T. Mercer, Simon Holyfield","doi":"10.4043/29436-MS","DOIUrl":"https://doi.org/10.4043/29436-MS","url":null,"abstract":"\u0000 The downturn has impacted our industry in many ways, not only in terms of budget cuts and headcount reductions but also in changing the way organizations work. The downturn has enabled the creation of novel technologies and efficient development plans such as phased development and early production systems that are transforming the industry, and the increased collaboration between operators and suppliers has been unprecedented. This paper discusses recent technology developments that have and will continue to reshape the approach to phased field developments.\u0000 For many years, the concept of phased field development has focused on reducing the expense of reaching first oil while planning the development for maximum recovery and deploying technology blocks that enable future add-ons for optimal asset return on investment (ROI). Game-changing efficiency resulting from earlier engagement with customers, paired with the latest technology and tools, can maximize the potential of a phased field development.\u0000 Using real-world development data as a basis, this paper details how operators can use current technology and tools to enable efficient phased field development. The case study discusses the benefits of using integrated field development and planning solutions that provide operators and suppliers a robust cloud-based collaboration solution for planning and evaluating various field development options and associated cost and schedules estimates at the click of a button. The paper then shows the impact that technology such as all-electric solutions, boosting and compression, pipeline solutions, and modular product solutions can have on the decision-making process for upcoming projects.","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":"89872303","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. Sauvin, M. Vanneste, M. Vardy, R. Klinkvort, Forsberg Carl Fredrik
Quantitative integrated ground models are a requirement for proper cost optimal site characterization, for offshore renewables, coastal activities and O&G projects. Geotechnical analyses and interpretations often rely on isolated 1D boreholes. On the other hand, geophysical data are collected in 2D lines and/or 3D volumes. Geophysical data therefore provides the natural link to re-populate geotechnical properties found in the 1D boreholes onto a larger area and thereby build a consistent and robust ground model. The geophysical data can be used to estimate geotechnical data and, as of today, there are a few methods available that can reliably map the dynamic properties from the seismic data (stratigraphic information, P-wave velocities, amplitudes, and their attributes) into geotechnical or geomechanical properties, particularly for shallow sub-surface depth. Being able to predict soil properties away from boreholes is important, as often the field layout changes during the development phase, and hence, information at the specific foundation locations may not be readily available. We have developed a workflow to build quantitative ground models following three approaches: (i) a geometric model in which the seismic data interpretations guide the prediction of geotechnical properties; (ii) a geostatistical approach in which in addition to the structural constraints, we used the seismic velocities to guide the prediction; and (iii) a multi-attribute regression using an artificial neural network (ANN). We apply it to a set of publically available data from the Holland Kust Zuid wind farm site in the Dutch sector of the North Sea. The result of the workflow yields maps or sub-volumes of geotechnical or geomechanical properties across the development site that can be used in further planning or engineering design. In this study, we use the tip resistance from a CPT as an example. The tip resistance derived using all methods generally give good results. Validation against randomly selected CPT shows good correlation between predicted and measured tip resistance. The ANN performs better than the geostatistical approach. However, these two approaches require good data quality and a rather large dataset to be effective. Therefore, using a global dataset not restricted to the Holland Kust Zuid site may improve the prediction. Moreover, using existing empirical correlation and calibration through laboratory testing or by training another ANN model, the geotechnical stiffness/strength parameters such as angle of friction or undrained shear strength could be derived. The next step is to use the results and their uncertainty into a cost assessment for the given foundation concepts.
{"title":"Machine Learning and Quantitative Ground Models for Improving Offshore Wind Site Characterization","authors":"G. Sauvin, M. Vanneste, M. Vardy, R. Klinkvort, Forsberg Carl Fredrik","doi":"10.4043/29351-MS","DOIUrl":"https://doi.org/10.4043/29351-MS","url":null,"abstract":"\u0000 Quantitative integrated ground models are a requirement for proper cost optimal site characterization, for offshore renewables, coastal activities and O&G projects. Geotechnical analyses and interpretations often rely on isolated 1D boreholes. On the other hand, geophysical data are collected in 2D lines and/or 3D volumes. Geophysical data therefore provides the natural link to re-populate geotechnical properties found in the 1D boreholes onto a larger area and thereby build a consistent and robust ground model. The geophysical data can be used to estimate geotechnical data and, as of today, there are a few methods available that can reliably map the dynamic properties from the seismic data (stratigraphic information, P-wave velocities, amplitudes, and their attributes) into geotechnical or geomechanical properties, particularly for shallow sub-surface depth. Being able to predict soil properties away from boreholes is important, as often the field layout changes during the development phase, and hence, information at the specific foundation locations may not be readily available.\u0000 We have developed a workflow to build quantitative ground models following three approaches: (i) a geometric model in which the seismic data interpretations guide the prediction of geotechnical properties; (ii) a geostatistical approach in which in addition to the structural constraints, we used the seismic velocities to guide the prediction; and (iii) a multi-attribute regression using an artificial neural network (ANN). We apply it to a set of publically available data from the Holland Kust Zuid wind farm site in the Dutch sector of the North Sea. The result of the workflow yields maps or sub-volumes of geotechnical or geomechanical properties across the development site that can be used in further planning or engineering design.\u0000 In this study, we use the tip resistance from a CPT as an example. The tip resistance derived using all methods generally give good results. Validation against randomly selected CPT shows good correlation between predicted and measured tip resistance. The ANN performs better than the geostatistical approach. However, these two approaches require good data quality and a rather large dataset to be effective. Therefore, using a global dataset not restricted to the Holland Kust Zuid site may improve the prediction. Moreover, using existing empirical correlation and calibration through laboratory testing or by training another ANN model, the geotechnical stiffness/strength parameters such as angle of friction or undrained shear strength could be derived.\u0000 The next step is to use the results and their uncertainty into a cost assessment for the given foundation concepts.","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":"74836960","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}
Chen Yu, Yongming Cheng, Guangqiang Yang, Manuel R. Carballo
This paper investigates life extension of the risers used for the Hoover DDCV (a classical Spar) in GoM, based on the latest technology and monitored data. Deepwater development in Gulf of Mexico (GoM) started about two decades ago. It is the time to evaluate the global integrity of the riser systems and explore the possibility of life extension in a structured and systematic way. A Deep Draft Caisson Vessel (DDCV), has been keeping up its class services for the past 17 years since it was installed in 2000. It was expected to extend the riser design life by 10 more years. This paper showed the life extension verification process starting from the initial planning, reviewing of the original design document, gathering and analyzing production and offshore measured data and finally to offshore focused underwater inspection. It introduces the methodology to assess the integrity of Steel Catenary Risers (SCRs) and Top Tensioned Risers (TTRs) used for the DDCV. An independent global performance was analyzed by utilizing latest environmental data, as-built information, measured VIM motion data and the latest analytical tools. It computes the riser global performance including dynamic strength and fatigue with the contributions from wave fatigue, VIM and VIV. The factored riser fatigue life is provided with the original safety factors to meet the intended 10 more years of service life.
{"title":"Life Extension of the Risers Used for the Hoover DDCV in Gulf of Mexico","authors":"Chen Yu, Yongming Cheng, Guangqiang Yang, Manuel R. Carballo","doi":"10.4043/29608-MS","DOIUrl":"https://doi.org/10.4043/29608-MS","url":null,"abstract":"\u0000 This paper investigates life extension of the risers used for the Hoover DDCV (a classical Spar) in GoM, based on the latest technology and monitored data. Deepwater development in Gulf of Mexico (GoM) started about two decades ago. It is the time to evaluate the global integrity of the riser systems and explore the possibility of life extension in a structured and systematic way.\u0000 A Deep Draft Caisson Vessel (DDCV), has been keeping up its class services for the past 17 years since it was installed in 2000. It was expected to extend the riser design life by 10 more years. This paper showed the life extension verification process starting from the initial planning, reviewing of the original design document, gathering and analyzing production and offshore measured data and finally to offshore focused underwater inspection. It introduces the methodology to assess the integrity of Steel Catenary Risers (SCRs) and Top Tensioned Risers (TTRs) used for the DDCV. An independent global performance was analyzed by utilizing latest environmental data, as-built information, measured VIM motion data and the latest analytical tools. It computes the riser global performance including dynamic strength and fatigue with the contributions from wave fatigue, VIM and VIV. The factored riser fatigue life is provided with the original safety factors to meet the intended 10 more years of service life.","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":"75141761","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}
Offshore energy market conditions change rapidly, with consequential demand changes for installation equipment, floating units and support vessels. Newbuilding requires a substantial investment and often takes (too) much time to obtain maximum benefit from an emerging opportunity. Upgrading or conversion of an existing unit can be a good alternative. There are eight different hull types to choose from for floating offshore units. The most common vessel type is the ship-shaped monohull. Within the large pool of existing merchant and offshore vessels, both new and ageing, there are many suitable candidates for upgrades and conversions. Such a new lease of life expands their operational and economical portfolio and serves the offshore industry in reaching spectacular advances in transport, construction and installation performance. When upgrading or converting existing units multiple tiers of capability increase are distinguished. Each tier brings increasing complexity, risks and re-building costs. Options range from life extension and modernization of an older vessel, temporary conversion, capacity upgrade, adding functions, changing the present function, to ultimately the complete transformation of an older merchant cargo vessel into a brand new offshore unit. Major vessel conversions can be competitive with newbuilding options, provided that such a complex conversion project is prepared and managed well. New insights into the market drivers for upgrading and conversion of floating offshore assets are provided. The broad range of offshore vessel modifications presented is an industry first. Some remarkable examples of capacity upgrades, double conversions and complete vessel makeovers are presented.
{"title":"Upgrading and Conversion Opportunities for Floating Offshore Units","authors":"A. M. Wijngaarden, N. Daniels","doi":"10.4043/29313-MS","DOIUrl":"https://doi.org/10.4043/29313-MS","url":null,"abstract":"\u0000 Offshore energy market conditions change rapidly, with consequential demand changes for installation equipment, floating units and support vessels. Newbuilding requires a substantial investment and often takes (too) much time to obtain maximum benefit from an emerging opportunity. Upgrading or conversion of an existing unit can be a good alternative.\u0000 There are eight different hull types to choose from for floating offshore units. The most common vessel type is the ship-shaped monohull. Within the large pool of existing merchant and offshore vessels, both new and ageing, there are many suitable candidates for upgrades and conversions. Such a new lease of life expands their operational and economical portfolio and serves the offshore industry in reaching spectacular advances in transport, construction and installation performance.\u0000 When upgrading or converting existing units multiple tiers of capability increase are distinguished. Each tier brings increasing complexity, risks and re-building costs. Options range from life extension and modernization of an older vessel, temporary conversion, capacity upgrade, adding functions, changing the present function, to ultimately the complete transformation of an older merchant cargo vessel into a brand new offshore unit. Major vessel conversions can be competitive with newbuilding options, provided that such a complex conversion project is prepared and managed well.\u0000 New insights into the market drivers for upgrading and conversion of floating offshore assets are provided. The broad range of offshore vessel modifications presented is an industry first. Some remarkable examples of capacity upgrades, double conversions and complete vessel makeovers are 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":"79480558","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}
K. Falk, Ole Kaare Ulsvik, Siv Engen, Elisabet Syverud
This paper explores how the oil and gas industry has applied systems engineering and lean product development principles to develop a Configure-to-Order strategy and enable supplier-led solutions. The purpose has been to enable shorter time to delivedy and lower cost. We have developed a life-cycle model for customer and supplier needs. Our model from the subsea industry is based primarily on own experience and needs to be further explored and validated. The paper also exemplifies challenges connected to a successful implementation of a Configure-to-Order strategy. There are three essential elements. The first element is that customers must communicate functional requirements with associated performance requirements. The second is that engineers must consider modularity during product design. And, the third is that supplier gets access to relevant operational data in a way that does not harm the customer. The principle of respecting both customer and supplier need and viewpoints is a key to success when it comes to supplier-led solutions.
{"title":"Systems Engineering Principles to Enable Supplier-Led Solutions","authors":"K. Falk, Ole Kaare Ulsvik, Siv Engen, Elisabet Syverud","doi":"10.4043/29403-MS","DOIUrl":"https://doi.org/10.4043/29403-MS","url":null,"abstract":"\u0000 This paper explores how the oil and gas industry has applied systems engineering and lean product development principles to develop a Configure-to-Order strategy and enable supplier-led solutions. The purpose has been to enable shorter time to delivedy and lower cost. We have developed a life-cycle model for customer and supplier needs. Our model from the subsea industry is based primarily on own experience and needs to be further explored and validated. The paper also exemplifies challenges connected to a successful implementation of a Configure-to-Order strategy. There are three essential elements. The first element is that customers must communicate functional requirements with associated performance requirements. The second is that engineers must consider modularity during product design. And, the third is that supplier gets access to relevant operational data in a way that does not harm the customer. The principle of respecting both customer and supplier need and viewpoints is a key to success when it comes to supplier-led solutions.","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":"74527124","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}
Degradable plug-and-perf systems made of degradable alloys and polymers are being used extensively for multi-stage stimulation (MSS). This paper reviews the degradable materials available in the market, including degradable magnesium and aluminum alloys and degradable plastics and elastomers, compares their degradation mechanisms, and discusses the factors affecting their degradation behavior. A series of degradable aluminum alloys with good mechanical properties, and a tunable range of degradation rates were developed in Schlumberger for MSS applications. Key parameters, such as material formulation, temperature, and hydrostatic pressure are used to control the degradation behavior of these degradable alloys. Predictive models are established to predict the degradation time window under a broad range of downhole conditions for improved completions job planning. Comprehensive testing has been done to verify the performance of the materials in the simulated downhole conditions. In addition, field operation results are available to validate the performance of the degradable fracturing plugs made of these degradable alloys. Degradable materials enable degradable fracturing plug applications and eliminate the need for mechanical intervention. They receive more and more attention in the MSS market. We will see more rapid growth of their applications in the coming years.
{"title":"Degradable Materials for Multi-Stage Stimulation","authors":"Hui-lin Tu, I. Aviles, M. Dardis","doi":"10.4043/29282-MS","DOIUrl":"https://doi.org/10.4043/29282-MS","url":null,"abstract":"\u0000 Degradable plug-and-perf systems made of degradable alloys and polymers are being used extensively for multi-stage stimulation (MSS). This paper reviews the degradable materials available in the market, including degradable magnesium and aluminum alloys and degradable plastics and elastomers, compares their degradation mechanisms, and discusses the factors affecting their degradation behavior.\u0000 A series of degradable aluminum alloys with good mechanical properties, and a tunable range of degradation rates were developed in Schlumberger for MSS applications. Key parameters, such as material formulation, temperature, and hydrostatic pressure are used to control the degradation behavior of these degradable alloys. Predictive models are established to predict the degradation time window under a broad range of downhole conditions for improved completions job planning. Comprehensive testing has been done to verify the performance of the materials in the simulated downhole conditions. In addition, field operation results are available to validate the performance of the degradable fracturing plugs made of these degradable alloys.\u0000 Degradable materials enable degradable fracturing plug applications and eliminate the need for mechanical intervention. They receive more and more attention in the MSS market. We will see more rapid growth of their applications in the coming years.","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":"74879051","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 FPSO Kaombo Norte came on stream on July 27th offshore Angola. When both its FPSOs will be at plateau, Kaombo, the biggest deep offshore project in Angola will account for 15% of the country's oil production. It produces light oil from six fields scattered over an 800-square-kilometer area. Gindungo, Gengibre, and Caril fields are connected to the Norte FPSO while Mostarda, Canela, and Louro fields will be producing on FPSO Sul. The full development stands out for its subsea network size with more than 300 kilometers of lines on the seabed within 1500-2000m water depth, including subsea production wells more than 25km away from the production facility. In order to secure a safe First-Oil and to smoothly start-up the production, a detailed and cross-functional study was carried out. The first step was to start from a clean slate by forgetting all previous startup scenarios: the three loops candidate to start-up hydrocarbon production were re-analyzed in depth to evaluate strengths and weaknesses. A task force composed of all involved disciplines, including contractors, was put in place in order to apply a cross-functional approach. Constraints from reservoir up to topsides were analyzed providing an overall picture and clear ranking to develop the start-up strategy. An ambitious planning of the commissioning activities combined with a relatively short-term reservoir management were crucial to lock production loop priorities with water injection and gas export systems readiness. The work jointly performed contributed to serene environment for a safe start-up and ramp-up. Following the assessment, decision was made to start first the most "powerful" reservoir despite a challenging flowline. The relatively high initial pressure and oil undersaturation, the robust open-hole gravel-pack completions and high productivity wells were beneficial to stabilize the multiphase flow in the subsea network. Improvement of the production was rapidly made with the start-up of the second production loop only fifteen days after. Postponement of the water injection system and the availability of the riser base gas lift were judiciously calculated: the readiness of these systems arrived in due time to respectively slow down the natural depletion of the reservoirs and improve the wells eruptivity and stability of the flowlines. Our capacity to re-invent ourselves and leave behind individual priorities conducted to a collective success captured in the outstanding production levels since early days of field life.
{"title":"Kaombo Start-Up Strategy: Together We Throve!","authors":"J. Rolland, O. Bahabanian, Lorena Pena, S. Rouyer","doi":"10.4043/29637-MS","DOIUrl":"https://doi.org/10.4043/29637-MS","url":null,"abstract":"\u0000 The FPSO Kaombo Norte came on stream on July 27th offshore Angola. When both its FPSOs will be at plateau, Kaombo, the biggest deep offshore project in Angola will account for 15% of the country's oil production. It produces light oil from six fields scattered over an 800-square-kilometer area. Gindungo, Gengibre, and Caril fields are connected to the Norte FPSO while Mostarda, Canela, and Louro fields will be producing on FPSO Sul. The full development stands out for its subsea network size with more than 300 kilometers of lines on the seabed within 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.\u0000 In order to secure a safe First-Oil and to smoothly start-up the production, a detailed and cross-functional study was carried out. The first step was to start from a clean slate by forgetting all previous startup scenarios: the three loops candidate to start-up hydrocarbon production were re-analyzed in depth to evaluate strengths and weaknesses. A task force composed of all involved disciplines, including contractors, was put in place in order to apply a cross-functional approach. Constraints from reservoir up to topsides were analyzed providing an overall picture and clear ranking to develop the start-up strategy. An ambitious planning of the commissioning activities combined with a relatively short-term reservoir management were crucial to lock production loop priorities with water injection and gas export systems readiness. The work jointly performed contributed to serene environment for a safe start-up and ramp-up.\u0000 Following the assessment, decision was made to start first the most \"powerful\" reservoir despite a challenging flowline. The relatively high initial pressure and oil undersaturation, the robust open-hole gravel-pack completions and high productivity wells were beneficial to stabilize the multiphase flow in the subsea network. Improvement of the production was rapidly made with the start-up of the second production loop only fifteen days after. Postponement of the water injection system and the availability of the riser base gas lift were judiciously calculated: the readiness of these systems arrived in due time to respectively slow down the natural depletion of the reservoirs and improve the wells eruptivity and stability of the flowlines. Our capacity to re-invent ourselves and leave behind individual priorities conducted to a collective success captured in the outstanding production levels since early days of field life.","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":"83255564","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}
R. Sheppard, R. Spong, M. Sauls, P. Hosch, M. Danaczko, F. Puskar, S. Leverette
As the Gulf of Mexico (GOM) fleet of Tension Leg Platforms (TLPs) ages, the need for more explicit Integrity Management (IM) and life extension guidance, particularly for the tendons, has grown. Recent industry efforts have developed Structural Integrity Management (SIM) guidance for fixed and floating systems, but tendon-specific guidance is less detailed. The Bureau of Safety and Environmental Enforcement commissioned the study described in this paper to develop this guidance including providing greater definition of IM and life extension processes for tendon systems, and describing an approach for demonstrating the reliability of tendon systems subjected to fatigue degradation. Four primary objectives are addressed: 1) tendon IM, 2) tendon life extension, 3) tendon fatigue, and 4) tendon component post-service testing. These topics were addressed through the input of subject matter experts, interfacing with TLP operators, and developing analytical tools. The study looked at current industry practice for the design and management of tendon systems; how current SIM approaches can be applied to the unique features of TLP tendons; what are the critical features of tendons to be addressed as part of a life extension program; tendon fatigue factors of safety; how reliability approaches can be used to better define risks related to operating beyond the original service life; and how forensic testing of recovered tendon components can be used to gain a better understanding of tendon performance expectations.
{"title":"Integrity Management Process of Tension Leg Platforms","authors":"R. Sheppard, R. Spong, M. Sauls, P. Hosch, M. Danaczko, F. Puskar, S. Leverette","doi":"10.4043/29661-MS","DOIUrl":"https://doi.org/10.4043/29661-MS","url":null,"abstract":"\u0000 As the Gulf of Mexico (GOM) fleet of Tension Leg Platforms (TLPs) ages, the need for more explicit Integrity Management (IM) and life extension guidance, particularly for the tendons, has grown. Recent industry efforts have developed Structural Integrity Management (SIM) guidance for fixed and floating systems, but tendon-specific guidance is less detailed. The Bureau of Safety and Environmental Enforcement commissioned the study described in this paper to develop this guidance including providing greater definition of IM and life extension processes for tendon systems, and describing an approach for demonstrating the reliability of tendon systems subjected to fatigue degradation.\u0000 Four primary objectives are addressed: 1) tendon IM, 2) tendon life extension, 3) tendon fatigue, and 4) tendon component post-service testing. These topics were addressed through the input of subject matter experts, interfacing with TLP operators, and developing analytical tools. The study looked at current industry practice for the design and management of tendon systems; how current SIM approaches can be applied to the unique features of TLP tendons; what are the critical features of tendons to be addressed as part of a life extension program; tendon fatigue factors of safety; how reliability approaches can be used to better define risks related to operating beyond the original service life; and how forensic testing of recovered tendon components can be used to gain a better understanding of tendon performance expectations.","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":"78067066","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 complexities of non-technical risks (NTRs) continue to pose serious threats throughout the lifecycle of hydrocarbon projects. Existing studies emphasise mainly internal organisational and operational issues, with a limited focus on factors in the external environment (where NTRs are frequently found). To shine light on this increasingly important topic, this paper provides insight into the complex relationship between NTRs and schedule overruns, and puts forward a ranked list identifying the NTRs that have had the most significant impact on delays in upstream gas projects in Australia. Data was gathered through an extensive literature review, interviews with industry experts, and a survey to identify relevant NTRs. From these data sources, a predictive model was developed for assessing the impact of NTRs on upstream gas project delays. The survey was circulated among participants directly involved in offshore and onshore (particularly the upstream stage) gas projects, who were requested to indicate via five-point Likert scale the frequency of occurrence and severity of each NTR. We identified 18 NTRs categorised into the political and regulatory risks, economic/financial risks, social risks, and environmental risks that cause severe challenges in upstream gas projects. The findings reveal that, overall, 78% of participants believed that NTRs cause more severe delays in the upstream stage than in the mid- and downstream stages of gas projects in Australia. Roughly 39% of respondents from the offshore group mentioned that environmental issues were more significant, whereas for onshore projects, social risks were considered dominant. Our analysis shows the relative criticality of NTRs. The top five critical NTRs causing major delays were found to be ‘fluctuations in oil prices’, ‘difficulty in obtaining land/access right’, ‘delay in approval from regulatory bodies’, ‘socio-cultural issues’, and ‘environmental restrictions’. Spearman’s rank correlation test was used to show a high degree of agreement between offshore and onshore project participants in their perceptions about the relative criticality of different NTRs. Factor analysis was applied to examine the clustering effects among NTRs, and multivariate regression modelling assisted in deriving a predictive model to forecast the influence of NTRs on project delays. Identifying and prioritising critical NTRs that interplay within the project environment, and thereby delay project execution, will increase stakeholder confidence, build trust and integrity, and improve transparency. In this way, this study will help practitioners and decision-makers to anticipate potential delays, and enable them to plan accordingly to minimise their effects on capital project delivery.
{"title":"Influence of Non-Technical Risks on Project Schedule Overrun: The Perspective of Upstream Gas Projects in Australia","authors":"Munmun Basak, V. Coffey, Robert K. Perrons","doi":"10.4043/29238-MS","DOIUrl":"https://doi.org/10.4043/29238-MS","url":null,"abstract":"The complexities of non-technical risks (NTRs) continue to pose serious threats throughout the lifecycle of hydrocarbon projects. Existing studies emphasise mainly internal organisational and operational issues, with a limited focus on factors in the external environment (where NTRs are frequently found). To shine light on this increasingly important topic, this paper provides insight into the complex relationship between NTRs and schedule overruns, and puts forward a ranked list identifying the NTRs that have had the most significant impact on delays in upstream gas projects in Australia. Data was gathered through an extensive literature review, interviews with industry experts, and a survey to identify relevant NTRs. From these data sources, a predictive model was developed for assessing the impact of NTRs on upstream gas project delays. The survey was circulated among participants directly involved in offshore and onshore (particularly the upstream stage) gas projects, who were requested to indicate via five-point Likert scale the frequency of occurrence and severity of each NTR. We identified 18 NTRs categorised into the political and regulatory risks, economic/financial risks, social risks, and environmental risks that cause severe challenges in upstream gas projects. The findings reveal that, overall, 78% of participants believed that NTRs cause more severe delays in the upstream stage than in the mid- and downstream stages of gas projects in Australia. Roughly 39% of respondents from the offshore group mentioned that environmental issues were more significant, whereas for onshore projects, social risks were considered dominant. Our analysis shows the relative criticality of NTRs. The top five critical NTRs causing major delays were found to be ‘fluctuations in oil prices’, ‘difficulty in obtaining land/access right’, ‘delay in approval from regulatory bodies’, ‘socio-cultural issues’, and ‘environmental restrictions’. Spearman’s rank correlation test was used to show a high degree of agreement between offshore and onshore project participants in their perceptions about the relative criticality of different NTRs. Factor analysis was applied to examine the clustering effects among NTRs, and multivariate regression modelling assisted in deriving a predictive model to forecast the influence of NTRs on project delays. Identifying and prioritising critical NTRs that interplay within the project environment, and thereby delay project execution, will increase stakeholder confidence, build trust and integrity, and improve transparency. In this way, this study will help practitioners and decision-makers to anticipate potential delays, and enable them to plan accordingly to minimise their effects on capital project delivery.","PeriodicalId":10948,"journal":{"name":"Day 2 Tue, May 07, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87723234","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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