Optimal route selection for the subsea pipeline is a critical task for the pipeline design process, and the route selected can significantly affect the overall project cost. Therefore, it is necessary to design the routes to be economical and safe. On-bottom stability (OBS) and fixed obstacles like existing crossings and free spans are the main factors that affect the route selection. This article proposes a novel hybrid optimization method based on a typical Machine Learning algorithm for designing an optimal pipeline route. The proposed optimal route design is compared with one of the popular multi-objective optimization method named Genetic Algorithm (GA). The proposed pipeline route selection method uses a Reinforcement Learning (RL) algorithm, a particular type of machine learning method to train a pipeline system that would optimize the route selection of subsea pipelines. The route optimization tool evaluates each possible route by incorporating Onbottom stability criteria based on DNVGL-ST-109 standard and other constraints such as the minimum pipeline route length, static obstacles, pipeline crossings, and free-span section length. The cost function in the optimization method simultaneously handles the minimization of length and cost of mitigating procedures. Genetic Algorithm, a well established optimization method, has been used as a reference to compare the optimal route with the result from the proposed Reinforcement Learning based optimization method. Three different case studies are performed for finding the optimal route selection using the Reinforcement Learning (RL) approach considering the OBS criteria into its cost function and compared with the Genetic Algorithm (GA). The RL method saves upto 20% pipeline length for a complex problem with 15 crossings and 31 free spans. The RL optimization method provides the optimal routes, considering different aspects of the design and the costs associated with the various factors to stabilize a pipeline (mattress, trenching, burying, concrete coating, or even employing a more massive pipe with additional steel wall thickness). OBS criteria significantly influence the best route, indicating that the tool can reduce the pipeline's design time and minimize installation and operational costs of the pipeline. Conventionally the pipeline route optimization is performed by a manual process where the minimum roule length and static obstacles are considered to find an optimum route. The engineering is then performed to fulfill the criteria of this route, and this approach may not lead to an optimized engineering cost. The proposed Reinforced Learning method for route optimization is a mixed type, faster, and cost-efficient approach. It significantly minimizes the pipeline's installation and operational costs up to 20% of the conventional route selection process.
{"title":"Machine Learning-Based Optimization for Subsea Pipeline Route Design","authors":"S. Bhowmik","doi":"10.4043/31031-ms","DOIUrl":"https://doi.org/10.4043/31031-ms","url":null,"abstract":"\u0000 Optimal route selection for the subsea pipeline is a critical task for the pipeline design process, and the route selected can significantly affect the overall project cost. Therefore, it is necessary to design the routes to be economical and safe. On-bottom stability (OBS) and fixed obstacles like existing crossings and free spans are the main factors that affect the route selection. This article proposes a novel hybrid optimization method based on a typical Machine Learning algorithm for designing an optimal pipeline route. The proposed optimal route design is compared with one of the popular multi-objective optimization method named Genetic Algorithm (GA).\u0000 The proposed pipeline route selection method uses a Reinforcement Learning (RL) algorithm, a particular type of machine learning method to train a pipeline system that would optimize the route selection of subsea pipelines. The route optimization tool evaluates each possible route by incorporating Onbottom stability criteria based on DNVGL-ST-109 standard and other constraints such as the minimum pipeline route length, static obstacles, pipeline crossings, and free-span section length. The cost function in the optimization method simultaneously handles the minimization of length and cost of mitigating procedures. Genetic Algorithm, a well established optimization method, has been used as a reference to compare the optimal route with the result from the proposed Reinforcement Learning based optimization method.\u0000 Three different case studies are performed for finding the optimal route selection using the Reinforcement Learning (RL) approach considering the OBS criteria into its cost function and compared with the Genetic Algorithm (GA). The RL method saves upto 20% pipeline length for a complex problem with 15 crossings and 31 free spans. The RL optimization method provides the optimal routes, considering different aspects of the design and the costs associated with the various factors to stabilize a pipeline (mattress, trenching, burying, concrete coating, or even employing a more massive pipe with additional steel wall thickness). OBS criteria significantly influence the best route, indicating that the tool can reduce the pipeline's design time and minimize installation and operational costs of the pipeline.\u0000 Conventionally the pipeline route optimization is performed by a manual process where the minimum roule length and static obstacles are considered to find an optimum route. The engineering is then performed to fulfill the criteria of this route, and this approach may not lead to an optimized engineering cost. The proposed Reinforced Learning method for route optimization is a mixed type, faster, and cost-efficient approach. It significantly minimizes the pipeline's installation and operational costs up to 20% of the conventional route selection process.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82099200","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}
L. Basilio, P. B. Machado, Débora Calaza de Sousa, Agremis Guinho Barbosa, D. R. Juliano, Pauline Santa Rosa Simões Drummond Boeira, M. Andreotti
As the environmental impact is critical for industry sustainability, early quantifying Greenhouse Gas (GHG) emissions of offshore units represents a central role and step-change improvement across the O&G value chain. Developing an overarching realistic model to estimate GHG emissions is a challenge due to the different methodologies available, the complexity of offshore installations, and the degree of uncertainty in the estimation of emission factors. The present work focuses on the earlier stages of new development, notably in Front End Loading-1 (FEL-1) and FEL-2, i.e., opportunity identification and conceptual engineering studies, respectively. The primary objective of this study is to propose an innovative modeling methodology to quantify Greenhouse Gas (GHG) emissions in offshore production facilities. Since E&P companies consider current and future carbon dioxide equivalents (CO2e) emissions as a factor into capital projects economics, this study additionally proposes a semi-empirical model for OPEX calculation considering the impact related to emissions (on a CO2e basis). Emissions of GHG in the O&G industry typically occur from one of the following general source classes: (i) combustion sources, including both stationary devices and mobile equipment; (ii) process emissions and vented sources; (iii) fugitive sources; and (iv) indirect sources. The projection of carbon emission costs along the asset life cycle is performed to simulate the economic impact of such emission on an OPEX perspective. After estimating the CO2e emissions, the procedure consists of using the "Carbon Emission Cost Projection" to calculate the cost of the CO2 emitted and penalize the OPEX of the evaluated alternative. The proposed model can be used to estimate Carbon Footprint for each one of the several conceptual engineering alternatives evaluated during the conceptual phase of the project, improving not only the techno-economic analysis but also the decision-making process of Capital Projects in the O&G Industry.
{"title":"Analysis of Carbon Footprint Applied to Conceptual Engineering of Offshore Production Units","authors":"L. Basilio, P. B. Machado, Débora Calaza de Sousa, Agremis Guinho Barbosa, D. R. Juliano, Pauline Santa Rosa Simões Drummond Boeira, M. Andreotti","doi":"10.4043/31326-ms","DOIUrl":"https://doi.org/10.4043/31326-ms","url":null,"abstract":"\u0000 As the environmental impact is critical for industry sustainability, early quantifying Greenhouse Gas (GHG) emissions of offshore units represents a central role and step-change improvement across the O&G value chain. Developing an overarching realistic model to estimate GHG emissions is a challenge due to the different methodologies available, the complexity of offshore installations, and the degree of uncertainty in the estimation of emission factors.\u0000 The present work focuses on the earlier stages of new development, notably in Front End Loading-1 (FEL-1) and FEL-2, i.e., opportunity identification and conceptual engineering studies, respectively. The primary objective of this study is to propose an innovative modeling methodology to quantify Greenhouse Gas (GHG) emissions in offshore production facilities. Since E&P companies consider current and future carbon dioxide equivalents (CO2e) emissions as a factor into capital projects economics, this study additionally proposes a semi-empirical model for OPEX calculation considering the impact related to emissions (on a CO2e basis).\u0000 Emissions of GHG in the O&G industry typically occur from one of the following general source classes: (i) combustion sources, including both stationary devices and mobile equipment; (ii) process emissions and vented sources; (iii) fugitive sources; and (iv) indirect sources. The projection of carbon emission costs along the asset life cycle is performed to simulate the economic impact of such emission on an OPEX perspective. After estimating the CO2e emissions, the procedure consists of using the \"Carbon Emission Cost Projection\" to calculate the cost of the CO2 emitted and penalize the OPEX of the evaluated alternative.\u0000 The proposed model can be used to estimate Carbon Footprint for each one of the several conceptual engineering alternatives evaluated during the conceptual phase of the project, improving not only the techno-economic analysis but also the decision-making process of Capital Projects in the O&G Industry.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"145 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80596295","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 major development with multiple rigs delivering extensive multi-laterals encountered a pervasive mud-window issue within the reservoir. The resulting severe mud losses, extensive NPT and formation-damage was also deteriorating with time due to depletion. Conventional approaches to stem losses had failed and adoption of an energized mud-system with acceptable Effective Circulating Density (ECD) was not considered cost effective, pragmatic nor safe. Instead a novel application using Hollow-Glass-Spheres (HGS) was trialled, that demonstrated an effective and highly successful outcome. With 10 rigs drilling 60-70 wells per-year, each with 5,500 to 6,750m in the reservoir, quick resolution of the issue was required. For these reasons the Team at bp Russia looked carefully at alternatives that might fit the mud-window, but that offered a realistic approach for the environment and conditions in Eastern Siberia. The Team identified HGS as an approach to lighten the mud, often used for cementing ECD, application for drilling has been limited. For this approach we required an option with broad capabilities that could be scaled-up and exported to other development areas where such issues existed. This paper will report on the planning, delivery, and execution of a pilot on the Sb. field at TYNGD, in Eastern Siberia. Initially deployed on three wells, including multi-laterals, the paper will walk through the engineering considerations, during the planning and execution phases. Reporting comprehensively on the data gathered and the many lessons learned during the incremental and stepwise deployment. Data will be provided that demonstrated loss-free drilling was achieved where this had not occurred before, with a dramatic reduction in NPT, FLA needs and costs. The paper will also report on the post drilling productivity and comparison with offset wells drilled with conventional mud systems and suffering severe losses. The results of this pilot have beaten all expectations, there have been many insights and the Team are now looking to set a timetable to scale-up across the NOJV. Much has been learned, waste HGS material has been demonstrated to be an effective FLA pill in other sections of the well and centralisation of mud process may offer additional cost savings and improvements. Further efficiencies are expected to be achieved and potential across the Company portfolio could be a major game changer. HGS for cementing is well documented, application for drilling fluids has been less reported and almost exclusively applied to one-off sections/wells. The TYNGD application is novel as this is a major new development with 10 drilling rigs. Application is on multi-laterals and prior offset wells are available for direct comparison. The results of the approach demonstrate a new way of performing well construction in an effective manner for major Field Developments where losses are prevalent.
{"title":"Drilling with Glass and Air: Using Hollow Glass Spheres to Address a Wide Ranging Drilling Challenge in a Safe, Efficient and Cost-Effective Manner","authors":"M. Rylance, Y. Tuzov, V.. Sherishorin","doi":"10.4043/31070-ms","DOIUrl":"https://doi.org/10.4043/31070-ms","url":null,"abstract":"\u0000 A major development with multiple rigs delivering extensive multi-laterals encountered a pervasive mud-window issue within the reservoir. The resulting severe mud losses, extensive NPT and formation-damage was also deteriorating with time due to depletion. Conventional approaches to stem losses had failed and adoption of an energized mud-system with acceptable Effective Circulating Density (ECD) was not considered cost effective, pragmatic nor safe. Instead a novel application using Hollow-Glass-Spheres (HGS) was trialled, that demonstrated an effective and highly successful outcome.\u0000 With 10 rigs drilling 60-70 wells per-year, each with 5,500 to 6,750m in the reservoir, quick resolution of the issue was required. For these reasons the Team at bp Russia looked carefully at alternatives that might fit the mud-window, but that offered a realistic approach for the environment and conditions in Eastern Siberia. The Team identified HGS as an approach to lighten the mud, often used for cementing ECD, application for drilling has been limited. For this approach we required an option with broad capabilities that could be scaled-up and exported to other development areas where such issues existed.\u0000 This paper will report on the planning, delivery, and execution of a pilot on the Sb. field at TYNGD, in Eastern Siberia. Initially deployed on three wells, including multi-laterals, the paper will walk through the engineering considerations, during the planning and execution phases. Reporting comprehensively on the data gathered and the many lessons learned during the incremental and stepwise deployment. Data will be provided that demonstrated loss-free drilling was achieved where this had not occurred before, with a dramatic reduction in NPT, FLA needs and costs. The paper will also report on the post drilling productivity and comparison with offset wells drilled with conventional mud systems and suffering severe losses. The results of this pilot have beaten all expectations, there have been many insights and the Team are now looking to set a timetable to scale-up across the NOJV. Much has been learned, waste HGS material has been demonstrated to be an effective FLA pill in other sections of the well and centralisation of mud process may offer additional cost savings and improvements. Further efficiencies are expected to be achieved and potential across the Company portfolio could be a major game changer.\u0000 HGS for cementing is well documented, application for drilling fluids has been less reported and almost exclusively applied to one-off sections/wells. The TYNGD application is novel as this is a major new development with 10 drilling rigs. Application is on multi-laterals and prior offset wells are available for direct comparison. The results of the approach demonstrate a new way of performing well construction in an effective manner for major Field Developments where losses are prevalent.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"103 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80646944","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}
S. Sarkar, M. Horstmann, Tore Oian, Piotr Byrski, George Lawrence, Mark Gast, M. Cecena, Mohamed Saher Dahroug, K. E. Sylta
One of the crucial components of well integrity evaluation in offshore drilling is to determine the cement bond quality assuring proper hydraulic sealing. On the Norwegian Continental Shelf (NCS) an industry standard as informative reference imposes verification of cement length and potential barriers using bonding logs. Traditionally, for the last 50 years, wireline (WL) sonic tools have been extensively used for this purpose. However, the applicability of logging-while-drilling (LWD) sonic tools for quantitative cement evaluation was explored in the recent development drilling campaign on the Dvalin Field in the Norwegian Sea, owing to significant advantages on operational efficiency and tool conveyance in any well trajectory. Cement bond evaluation from conventional peak-to-peak amplitude method has shown robust results up to bond indexes of 0.6 for LWD sonic tools. Above this limit, the casing signal is smaller than the collar signal and the amplitude method loses sensitivity to bonding. This practical challenge in the LWD realm was overcome through the inclusion of attenuation rate measurements, which responds accordingly in higher bonding environments. The two methods are used in a hybrid approach providing a full range quantitative bond index (QBI) introduced by Izuhara et al. (2017). In order to conform with local requirements related to well integrity and to ascertain the QBI potential from LWD monopole sonic, a wireline cement bond log (CBL) was acquired in the first well of the campaign for comparison. This enabled the strategic deployment of LWD QBI service in subsequent wells. LWD sonic monopole data was acquired at a controlled speed of 900ft/h. The high-fidelity waveforms were analyzed in a suitable time window and both amplitude- and attenuation-based bond indexes were derived. The combined hybrid bond index showed an excellent match with the wireline reference CBL, both in zones of high as well as lower cement bonding. The presence of formation arrivals was also in good correlation with zones of proper bonding distinguishable on the QBI results. This established the robustness of the LWD cement logging and ensured its applicability in the rest of the campaign which was carried out successfully. While the results from LWD cement evaluation service are omnidirectional, it comes with a wide range of benefits related to rig cost or conveyance in tough borehole trajectories. Early evaluation of cement quality by LWD sonic tools helps to provide adequate time for taking remedial actions if necessary. The LWD sonic as part of the drilling BHA enables this acquisition and service in non-dedicated runs, with the possibility of multiple passes for observing time-lapse effects. Also, the large sizes of LWD tools relative to the wellbore ensures a lower signal attenuation in the annulus and more effective stabilization, thereby providing a reliable bond index.
{"title":"Application of LWD Multipole Sonic for Quantitative Cement Evaluation – Well Integrity in the Norwegian Continental Shelf","authors":"S. Sarkar, M. Horstmann, Tore Oian, Piotr Byrski, George Lawrence, Mark Gast, M. Cecena, Mohamed Saher Dahroug, K. E. Sylta","doi":"10.4043/31100-ms","DOIUrl":"https://doi.org/10.4043/31100-ms","url":null,"abstract":"\u0000 One of the crucial components of well integrity evaluation in offshore drilling is to determine the cement bond quality assuring proper hydraulic sealing. On the Norwegian Continental Shelf (NCS) an industry standard as informative reference imposes verification of cement length and potential barriers using bonding logs. Traditionally, for the last 50 years, wireline (WL) sonic tools have been extensively used for this purpose. However, the applicability of logging-while-drilling (LWD) sonic tools for quantitative cement evaluation was explored in the recent development drilling campaign on the Dvalin Field in the Norwegian Sea, owing to significant advantages on operational efficiency and tool conveyance in any well trajectory.\u0000 Cement bond evaluation from conventional peak-to-peak amplitude method has shown robust results up to bond indexes of 0.6 for LWD sonic tools. Above this limit, the casing signal is smaller than the collar signal and the amplitude method loses sensitivity to bonding. This practical challenge in the LWD realm was overcome through the inclusion of attenuation rate measurements, which responds accordingly in higher bonding environments. The two methods are used in a hybrid approach providing a full range quantitative bond index (QBI) introduced by Izuhara et al. (2017). In order to conform with local requirements related to well integrity and to ascertain the QBI potential from LWD monopole sonic, a wireline cement bond log (CBL) was acquired in the first well of the campaign for comparison. This enabled the strategic deployment of LWD QBI service in subsequent wells.\u0000 LWD sonic monopole data was acquired at a controlled speed of 900ft/h. The high-fidelity waveforms were analyzed in a suitable time window and both amplitude- and attenuation-based bond indexes were derived. The combined hybrid bond index showed an excellent match with the wireline reference CBL, both in zones of high as well as lower cement bonding. The presence of formation arrivals was also in good correlation with zones of proper bonding distinguishable on the QBI results. This established the robustness of the LWD cement logging and ensured its applicability in the rest of the campaign which was carried out successfully.\u0000 While the results from LWD cement evaluation service are omnidirectional, it comes with a wide range of benefits related to rig cost or conveyance in tough borehole trajectories. Early evaluation of cement quality by LWD sonic tools helps to provide adequate time for taking remedial actions if necessary. The LWD sonic as part of the drilling BHA enables this acquisition and service in non-dedicated runs, with the possibility of multiple passes for observing time-lapse effects. Also, the large sizes of LWD tools relative to the wellbore ensures a lower signal attenuation in the annulus and more effective stabilization, thereby providing a reliable bond index.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72864535","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}
Thiago Geraldo Silva, Luis Kin Miyatake, Rafael Barbosa, A. G. Medeiros, Otavio Ciribelli Borges, M. Oliveira, F. M. Cardoso
This work aims to present a new paradigm in the Exploration & Production (E&P) segment using Artificial Intelligence for rheological mapping of produced fluids and forecasting their properties throughout the production life cycle. The expected gain is to accelerate the process of prioritizing target fields for application of flow improvers and, as a consequence, to generate anticipation of revenue and value creation. Rheological data from laboratory analyses of water-in-oil emulsions from different production fields collected over the years are used in a machine learning framework, which enables a modeling based on supervised learning. The Artificial Intelligence infers the emulsion viscosity as a function of input parameters, such as API gravity, water cut and dehydrated oil viscosity. The modeling of emulsified fluids uses correlations that, in general, do not represent the viscosity emulsion suitably. Currently, an improvement over empirical correlations can be achieved via rheological characterization using tests from onshore laboratories, which have been generating a database for different Petrobras reservoirs over the years. The dataset used in the artificial intelligence framework results in a machine learning model with generalization ability, showing a good match between experimental and calculated data in both training and test datasets. This model is tested with a great deal of oils from different reservoirs, in an extensive range of API gravity, presenting a suitable mean absolute percentage error. In addition to that, the result preserves the expected physical behavior for the emulsion viscosity curve. Consequently, this approach eliminates frequent sampling requirements, which means lower logistical costs and faster actions in the decision making process with respect to flow improvers injection. Moreover, by embedding the AI model into a numerical flow simulation software, the overall flow model can estimate more reliably production curves due to better representation of the rheological fluid characteristics.
{"title":"AI Based Water-in-Oil Emulsions Rheology Model for Value Creation in Deepwater Fields Production Management","authors":"Thiago Geraldo Silva, Luis Kin Miyatake, Rafael Barbosa, A. G. Medeiros, Otavio Ciribelli Borges, M. Oliveira, F. M. Cardoso","doi":"10.4043/31173-ms","DOIUrl":"https://doi.org/10.4043/31173-ms","url":null,"abstract":"\u0000 This work aims to present a new paradigm in the Exploration & Production (E&P) segment using Artificial Intelligence for rheological mapping of produced fluids and forecasting their properties throughout the production life cycle. The expected gain is to accelerate the process of prioritizing target fields for application of flow improvers and, as a consequence, to generate anticipation of revenue and value creation.\u0000 Rheological data from laboratory analyses of water-in-oil emulsions from different production fields collected over the years are used in a machine learning framework, which enables a modeling based on supervised learning. The Artificial Intelligence infers the emulsion viscosity as a function of input parameters, such as API gravity, water cut and dehydrated oil viscosity.\u0000 The modeling of emulsified fluids uses correlations that, in general, do not represent the viscosity emulsion suitably. Currently, an improvement over empirical correlations can be achieved via rheological characterization using tests from onshore laboratories, which have been generating a database for different Petrobras reservoirs over the years.\u0000 The dataset used in the artificial intelligence framework results in a machine learning model with generalization ability, showing a good match between experimental and calculated data in both training and test datasets. This model is tested with a great deal of oils from different reservoirs, in an extensive range of API gravity, presenting a suitable mean absolute percentage error. In addition to that, the result preserves the expected physical behavior for the emulsion viscosity curve. Consequently, this approach eliminates frequent sampling requirements, which means lower logistical costs and faster actions in the decision making process with respect to flow improvers injection. Moreover, by embedding the AI model into a numerical flow simulation software, the overall flow model can estimate more reliably production curves due to better representation of the rheological fluid characteristics.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"134 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76600906","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}
Last year the Department of Energy (DOE) presented a description of the expansion of its research portfolio from one focused on research primarily for onshore applications to one that includes projects specifically for offshore application. That paper (OTC - 30469-MS) also included key research results for the portfolio beginning with projects initiated in 2007. This paper follows on that theme and presents an overview of the Department's current research portfolio focusing on recent-past learnings, current learnings, and research gaps identified from the projects in the current research portfolio 2017-2023. Discussion includes projects that are sponsored by the Department as part of its public-private partnerships with principal investigators from industry and academia, and those projects sponsored by the Department at its National Laboratories. The discussion also includes an overview of activities and projects jointly pursued by DOE and the Department of the Interior's Bureau of Safety and Environmental Enforcement (BSEE) pursuant to the July 2020 Memorandum of Collaboration signed by both agencies. Major insights presented in this paper focus on innovative mid-Technology Readiness Level (mid-TRL) technologies that will enable cost-effective enhanced oil recovery in deepwater and ultra-deepwater including insights for cement and wellbore integrity, flow assurance, life extension of offshore platforms and risers, sensors and telecommunications, early kick detection, chemical delivery, data analytics involving big data sets and modeling, and advanced sensors for EOR operations. Many of the projects reviewed in this paper are part of the portfolio of projects that are sponsored by the Department at the National Laboratories while at the same time includes projects that are cost-shared with private sector and research partners in academia. The breadth of the portfolio illustrates the overall approach of the offshore research portfolio especially for enhanced oil recovery. Recently the National Petroleum Council completed a study for the Secretary of Energy titled Meeting the Dual Challenge: A roadmap to at-scale deployment of carbon capture, use, and storage in which the potential for the use and potential long-term storage of CO2 used in enhanced oil recovery is considered for both onshore and offshore settings (NPC 2019).
{"title":"Technologies for Advancing Offshore Enhanced Oil Recovery Capabilities","authors":"E. Melchert, R. Long","doi":"10.4043/31227-ms","DOIUrl":"https://doi.org/10.4043/31227-ms","url":null,"abstract":"\u0000 Last year the Department of Energy (DOE) presented a description of the expansion of its research portfolio from one focused on research primarily for onshore applications to one that includes projects specifically for offshore application. That paper (OTC - 30469-MS) also included key research results for the portfolio beginning with projects initiated in 2007. This paper follows on that theme and presents an overview of the Department's current research portfolio focusing on recent-past learnings, current learnings, and research gaps identified from the projects in the current research portfolio 2017-2023.\u0000 Discussion includes projects that are sponsored by the Department as part of its public-private partnerships with principal investigators from industry and academia, and those projects sponsored by the Department at its National Laboratories. The discussion also includes an overview of activities and projects jointly pursued by DOE and the Department of the Interior's Bureau of Safety and Environmental Enforcement (BSEE) pursuant to the July 2020 Memorandum of Collaboration signed by both agencies.\u0000 Major insights presented in this paper focus on innovative mid-Technology Readiness Level (mid-TRL) technologies that will enable cost-effective enhanced oil recovery in deepwater and ultra-deepwater including insights for cement and wellbore integrity, flow assurance, life extension of offshore platforms and risers, sensors and telecommunications, early kick detection, chemical delivery, data analytics involving big data sets and modeling, and advanced sensors for EOR operations.\u0000 Many of the projects reviewed in this paper are part of the portfolio of projects that are sponsored by the Department at the National Laboratories while at the same time includes projects that are cost-shared with private sector and research partners in academia. The breadth of the portfolio illustrates the overall approach of the offshore research portfolio especially for enhanced oil recovery.\u0000 Recently the National Petroleum Council completed a study for the Secretary of Energy titled Meeting the Dual Challenge: A roadmap to at-scale deployment of carbon capture, use, and storage in which the potential for the use and potential long-term storage of CO2 used in enhanced oil recovery is considered for both onshore and offshore settings (NPC 2019).","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"86 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77627396","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}
Jouni Hartikainen, Pekka Kaunisto, James L. Walls, A. Voutilainen, P. Laakkonen, O. Lehtikangas
Separators can over the length of field life be exposed to operating conditions outside the set design conditions, which can cause operating issues in terms of separator efficiency, operating expenditures and potential need for frequent maintenance and/or retrofitting new internals. In mature operations with heavy oils, there can be severe issues with Water-in-Oil and Oil-in-Water emulsion layers. In late life operations, enhanced oil recovery (EOR) efforts with polymer injection can also take place to produce more, but at the same time making the separator function in terms of phase separation even more complex. Emulsion thickness and residence time optimization in separators and tanks are key issues in the oil and gas operations. Real-time data of the full level profiling is complicated and has been based on instruments with varying reliability and performance. Operations have been relying on other process parameters and bottle tests. However, in this work, separator profiler utilizing electrical tomography was used for monitoring separator content online, especially fluid interface levels as well as emulsion and foam layer thicknesses. In addition, effect of polymer injection to the wells is investigated. From the single profiler, data for the separator fluid levels, emulsion and foam thicknesses can be derived. The profiler used is a safe-to-use non-radioactive probe-type measurement sensor which is installed through an existing separator nozzle. The actual separator profiler with dimensions 5 cm diameter and 3 m length was installed downstream of the inlet cyclones and the flow distribution baffles in the three-phase separator located at one of the production fields in the Middle East. Water-oil interface, turbulent water-in-oil dispersion band, oil-gas interface and foam layer thickness were monitored continuously for several months with varying flowrates and operation conditions. Later, effect of polymer injection was also investigated. Interface level and layer monitoring results will be given and discussed. The results show that the profiler is highly useful for monitoring the separator fluid distribution online, building a rigid data analytics model over time that can be utilized by the operations to improve and optimize the performance. This paper shares novel information on operational experience of data analytics used for three-phase separators operating in a heavy oil field with polymer injection. The sensor type used is novel to the industry with high robustness and reliability generating multiple data points per second, enabling a highly detailed analytics model generating new possibilities for operational optimization through digitalization. In addition, commissioning and monitoring of the sensor was done remotely during covid-19 shutdown without the need of external personnel entering the field demonstrating remote commissioning and digital oil field concepts.
{"title":"Three-Phase Separator Online Measurement and Data Analytics for Fluid Interface and Emulsion Thickness Utilizing a Single Emulsion Watch Profiler","authors":"Jouni Hartikainen, Pekka Kaunisto, James L. Walls, A. Voutilainen, P. Laakkonen, O. Lehtikangas","doi":"10.4043/31315-ms","DOIUrl":"https://doi.org/10.4043/31315-ms","url":null,"abstract":"\u0000 Separators can over the length of field life be exposed to operating conditions outside the set design conditions, which can cause operating issues in terms of separator efficiency, operating expenditures and potential need for frequent maintenance and/or retrofitting new internals. In mature operations with heavy oils, there can be severe issues with Water-in-Oil and Oil-in-Water emulsion layers. In late life operations, enhanced oil recovery (EOR) efforts with polymer injection can also take place to produce more, but at the same time making the separator function in terms of phase separation even more complex. Emulsion thickness and residence time optimization in separators and tanks are key issues in the oil and gas operations. Real-time data of the full level profiling is complicated and has been based on instruments with varying reliability and performance. Operations have been relying on other process parameters and bottle tests. However, in this work, separator profiler utilizing electrical tomography was used for monitoring separator content online, especially fluid interface levels as well as emulsion and foam layer thicknesses. In addition, effect of polymer injection to the wells is investigated. From the single profiler, data for the separator fluid levels, emulsion and foam thicknesses can be derived.\u0000 The profiler used is a safe-to-use non-radioactive probe-type measurement sensor which is installed through an existing separator nozzle. The actual separator profiler with dimensions 5 cm diameter and 3 m length was installed downstream of the inlet cyclones and the flow distribution baffles in the three-phase separator located at one of the production fields in the Middle East. Water-oil interface, turbulent water-in-oil dispersion band, oil-gas interface and foam layer thickness were monitored continuously for several months with varying flowrates and operation conditions. Later, effect of polymer injection was also investigated. Interface level and layer monitoring results will be given and discussed.\u0000 The results show that the profiler is highly useful for monitoring the separator fluid distribution online, building a rigid data analytics model over time that can be utilized by the operations to improve and optimize the performance.\u0000 This paper shares novel information on operational experience of data analytics used for three-phase separators operating in a heavy oil field with polymer injection. The sensor type used is novel to the industry with high robustness and reliability generating multiple data points per second, enabling a highly detailed analytics model generating new possibilities for operational optimization through digitalization. In addition, commissioning and monitoring of the sensor was done remotely during covid-19 shutdown without the need of external personnel entering the field demonstrating remote commissioning and digital oil field concepts.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73682234","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}
C. O’beirne, P. Watson, C. O’Loughlin, D. White, Alexander Hodson, S. Ang, S. Frankenmolen, Jesper Hoj-Hansen, M. Kuo, T. Roe
Pipe clamping mattresses (PCMs) are a relatively new system for providing anchoring force to pipelines, to mitigate offshore flowline ‘walking’. They represent a cost-effective and highly efficient alternative to anchor piles, rock dump and conventional concrete mattresses. The system comprises a hinged concrete structure that clamps onto a section of laid pipeline, with concrete ballast logs securing the clamping action – with the benefit that 100% of the submerged weight of the PCM contributes to axial friction. PCMs have been applied successfully to one deepwater project, but performance data showing the influence of soil type, and allowing a general design framework to be established, has not yet been available. This paper addresses this gap by investigating the performance of PCMs through three series of centrifuge tests, supported by three Operators. Each series comprises tests on a different reconstituted deepwater soil as follows: (a) West African clay; (b) Gulf of Mexico clay; and (c) carbonate silty sand. In each test, a scaled pipeline is installed in-flight and cycled axially to represent its prior operating life. Scaled PCM models and ballast units are then installed onto the pipe in-flight, mimicking the use of PCMs to mitigate pipeline walking during operation. After installation of the PCMs, further axial cycles are applied, with the system settlement and changes in axial resistance and excess pore pressure measured. The paper shows the performance and applicability of PCMs for a range of soil types, highlighting variations in axial resistance and settlement. The suite of results will help to calibrate design tools for industry, removing unnecessary conservatism and enabling an optimised pipeline anchoring solution to be designed. Key results are equivalent friction factors for the combined pipe-PCM system and PCM settlement, which both show behaviour dependent on soil type. In the clay soils, friction increases significantly over time due to ‘consolidation hardening’. This provides validation of an important effect that has only recently been recognised in pipeline design. In contrast, hardening behavior is not evident in silty sand – although the study suggests there is potential for increasing resistance associated with settlement, which appears to mobilize additional (wedging) stress around the pipeline. Upon PCM installation, the pipelines embed further due to the added weight. Additional settlement occurs during cycling of the system, due to immediate soil deformation and consolidation-related compression. The magnitude of embedment is greater for the clay soils, but in all cases does not cause the clamping action to release. Overall, the efficiency of the PCM system in providing a high level of anchoring force per unit weight placed on the seabed is confirmed. Long term anchoring forces in the range 50-100% of the submerged weight of the PCM are demonstrated. This is several times more efficient than the commonly used
{"title":"Pipe Clamping Mattresses to Mitigate Flowline Walking; Physical Modelling Trials on Three Offshore Soils","authors":"C. O’beirne, P. Watson, C. O’Loughlin, D. White, Alexander Hodson, S. Ang, S. Frankenmolen, Jesper Hoj-Hansen, M. Kuo, T. Roe","doi":"10.4043/31064-ms","DOIUrl":"https://doi.org/10.4043/31064-ms","url":null,"abstract":"\u0000 Pipe clamping mattresses (PCMs) are a relatively new system for providing anchoring force to pipelines, to mitigate offshore flowline ‘walking’. They represent a cost-effective and highly efficient alternative to anchor piles, rock dump and conventional concrete mattresses. The system comprises a hinged concrete structure that clamps onto a section of laid pipeline, with concrete ballast logs securing the clamping action – with the benefit that 100% of the submerged weight of the PCM contributes to axial friction. PCMs have been applied successfully to one deepwater project, but performance data showing the influence of soil type, and allowing a general design framework to be established, has not yet been available.\u0000 This paper addresses this gap by investigating the performance of PCMs through three series of centrifuge tests, supported by three Operators. Each series comprises tests on a different reconstituted deepwater soil as follows: (a) West African clay; (b) Gulf of Mexico clay; and (c) carbonate silty sand. In each test, a scaled pipeline is installed in-flight and cycled axially to represent its prior operating life. Scaled PCM models and ballast units are then installed onto the pipe in-flight, mimicking the use of PCMs to mitigate pipeline walking during operation. After installation of the PCMs, further axial cycles are applied, with the system settlement and changes in axial resistance and excess pore pressure measured.\u0000 The paper shows the performance and applicability of PCMs for a range of soil types, highlighting variations in axial resistance and settlement. The suite of results will help to calibrate design tools for industry, removing unnecessary conservatism and enabling an optimised pipeline anchoring solution to be designed.\u0000 Key results are equivalent friction factors for the combined pipe-PCM system and PCM settlement, which both show behaviour dependent on soil type. In the clay soils, friction increases significantly over time due to ‘consolidation hardening’. This provides validation of an important effect that has only recently been recognised in pipeline design. In contrast, hardening behavior is not evident in silty sand – although the study suggests there is potential for increasing resistance associated with settlement, which appears to mobilize additional (wedging) stress around the pipeline. Upon PCM installation, the pipelines embed further due to the added weight. Additional settlement occurs during cycling of the system, due to immediate soil deformation and consolidation-related compression. The magnitude of embedment is greater for the clay soils, but in all cases does not cause the clamping action to release.\u0000 Overall, the efficiency of the PCM system in providing a high level of anchoring force per unit weight placed on the seabed is confirmed. Long term anchoring forces in the range 50-100% of the submerged weight of the PCM are demonstrated. This is several times more efficient than the commonly used","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90184923","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}
Engineering simulation has become the pivotal tool for research and development in industries including offshore oil & gas, aerospace, automotive, mobile/off-highway, health care, and others. This case study will explore the financial and time-based savings achieved through detailed simulations and a system-based design approach in two hydraulic valve development projects. The applications in this scope include subsea blowout preventer and off-highway mobile equipment controls. Tools like 1D system simulation, computational fluid dynamics, and finite element analysis are widely accepted; verification and validation (V&V) of these models is imperative in building confidence in simulation. Some V&V reference standards have been developed by groups like ASME and API, but they do not encompass all aspects of simulation regularly utilized by the modern analyst. This places the onus for the creation of V&V guidelines onto individual analysts and their respective employers. Lack of detail in these guidelines can lead to flawed interpretations of results and a corresponding loss of trust in analytical methods. Interdisciplinary organizations can provide forums to help bridge these gaps and create more comprehensive V&V guidelines. Through a study of the development cycles of a subsea valve and an off-highway mobile valve, examples will be outlined which illustrate the benefit of extensive upfront simulation validated by physical testing. Simulation work serves as a cost avoidance measure against many cycles of building and testing prototypes beyond what is truly required in the early stages of design. Accurate simulation is a key component of successful product development, but another often neglected factor is the collaboration between subject matter experts from the component suppliers and the OEM or system integrator. High performance teams comprised of seasoned designers, analysts, and market experts can collaborate to create devices that excel when integrated into a final product. Component designers may wish to isolate the design problem to the component in question, but critical engineering detail will be missed by avoiding a system approach. Expanding the scope of the design analysis to include as much of the application as possible as well as utilizing V&V techniques (beyond minimum industry standards) is key to ensuring that laboratory test data is representative of how a product will perform in its intended application. As the industry continues to evolve, powerful digital twins of systems like blowout preventers can be used for OEM validation of new technology proposed for these systems. However, the fidelity of these digital twins is contingent upon the inputs from thoroughly validated analytical models of the components that comprise the system. By collaborating across the customer-supplier value chain and investing heavily in simulation, offshore manufacturers can strategically position themselves to win in times when both customer
{"title":"Lies, Damned Lies, and Simulation Results: How to Change the Conversation and Build a Thriving Simulation Ecosystem","authors":"Bipin Kashid, Mitch Eichler","doi":"10.4043/30953-ms","DOIUrl":"https://doi.org/10.4043/30953-ms","url":null,"abstract":"\u0000 Engineering simulation has become the pivotal tool for research and development in industries including offshore oil & gas, aerospace, automotive, mobile/off-highway, health care, and others. This case study will explore the financial and time-based savings achieved through detailed simulations and a system-based design approach in two hydraulic valve development projects. The applications in this scope include subsea blowout preventer and off-highway mobile equipment controls.\u0000 Tools like 1D system simulation, computational fluid dynamics, and finite element analysis are widely accepted; verification and validation (V&V) of these models is imperative in building confidence in simulation. Some V&V reference standards have been developed by groups like ASME and API, but they do not encompass all aspects of simulation regularly utilized by the modern analyst. This places the onus for the creation of V&V guidelines onto individual analysts and their respective employers. Lack of detail in these guidelines can lead to flawed interpretations of results and a corresponding loss of trust in analytical methods. Interdisciplinary organizations can provide forums to help bridge these gaps and create more comprehensive V&V guidelines.\u0000 Through a study of the development cycles of a subsea valve and an off-highway mobile valve, examples will be outlined which illustrate the benefit of extensive upfront simulation validated by physical testing. Simulation work serves as a cost avoidance measure against many cycles of building and testing prototypes beyond what is truly required in the early stages of design.\u0000 Accurate simulation is a key component of successful product development, but another often neglected factor is the collaboration between subject matter experts from the component suppliers and the OEM or system integrator. High performance teams comprised of seasoned designers, analysts, and market experts can collaborate to create devices that excel when integrated into a final product. Component designers may wish to isolate the design problem to the component in question, but critical engineering detail will be missed by avoiding a system approach. Expanding the scope of the design analysis to include as much of the application as possible as well as utilizing V&V techniques (beyond minimum industry standards) is key to ensuring that laboratory test data is representative of how a product will perform in its intended application.\u0000 As the industry continues to evolve, powerful digital twins of systems like blowout preventers can be used for OEM validation of new technology proposed for these systems. However, the fidelity of these digital twins is contingent upon the inputs from thoroughly validated analytical models of the components that comprise the system.\u0000 By collaborating across the customer-supplier value chain and investing heavily in simulation, offshore manufacturers can strategically position themselves to win in times when both customer ","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84890335","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}
Additive manufacturing (AM) makes it possible to produce parts on demand, close to operations, with significantly reduced lead times compared to conventional manufacturing. However, without standardization or guidelines, additively manufactured parts could raise the risk of unexpected or premature failures due to inherent variation of mechanical and metallurgical properties associated with this new technology. This is especially true when the reduced lead time is the desired advantage, where speed may be prioritized over quality. A standardised framework is proposed to free up value locked in physical warehouse inventory and reduce inventory management cost through digital warehousing in a safe and cost-efficient way. Through a joint industry project, with participating companies throughout the entire AM value chain, we propose an assurance framework that answers questions such as: can the digital drawing be available when needed? Can the parts be made ‘first time’ right when needed? Can it be made with the same quality at another location next time? Which party is responsible for the different stages? What requirements should be in place for the companies who wish to manufacture on demand? The digital warehouse assurance framework discussed in this work demonstrates that digital warehousing powered by AM could potentially shorten lead times for sourcing parts and reduce the need for costly storage, maintenance and coordination of spare parts that are rarely used. We also discuss the different variants of digital warehousing we may see, and the roles and responsibilities various digital warehouse stakeholders have for facilitating unambiguous communication. AM is already disrupting supply chains in many other industries, but it is in its infancy in the oil & gas, offshore and maritime sectors as they ponder challenges with intellectual property (IP) and usage rights for original equipment manufacturers (OEM) designs, standardization of technology interfaces and the lack of knowledge and trust of the technology. The digital warehouse quality assurance framework proposed and discussed in this work is unique and has potential to not only accelerate adoption of AM in oil & gas and offshore sectors, but also contribute to a significant reduction of emissions, including greenhouse gases.
{"title":"Quality Assurance Framework to Enable Additive Manufacturing Based Digital Warehousing for Oil and Gas Industry","authors":"S. Kandukuri, Ole-Bjørn Ellingsen Moe","doi":"10.4043/31261-ms","DOIUrl":"https://doi.org/10.4043/31261-ms","url":null,"abstract":"\u0000 Additive manufacturing (AM) makes it possible to produce parts on demand, close to operations, with significantly reduced lead times compared to conventional manufacturing. However, without standardization or guidelines, additively manufactured parts could raise the risk of unexpected or premature failures due to inherent variation of mechanical and metallurgical properties associated with this new technology. This is especially true when the reduced lead time is the desired advantage, where speed may be prioritized over quality. A standardised framework is proposed to free up value locked in physical warehouse inventory and reduce inventory management cost through digital warehousing in a safe and cost-efficient way. Through a joint industry project, with participating companies throughout the entire AM value chain, we propose an assurance framework that answers questions such as: can the digital drawing be available when needed? Can the parts be made ‘first time’ right when needed? Can it be made with the same quality at another location next time? Which party is responsible for the different stages? What requirements should be in place for the companies who wish to manufacture on demand?\u0000 The digital warehouse assurance framework discussed in this work demonstrates that digital warehousing powered by AM could potentially shorten lead times for sourcing parts and reduce the need for costly storage, maintenance and coordination of spare parts that are rarely used. We also discuss the different variants of digital warehousing we may see, and the roles and responsibilities various digital warehouse stakeholders have for facilitating unambiguous communication.\u0000 AM is already disrupting supply chains in many other industries, but it is in its infancy in the oil & gas, offshore and maritime sectors as they ponder challenges with intellectual property (IP) and usage rights for original equipment manufacturers (OEM) designs, standardization of technology interfaces and the lack of knowledge and trust of the technology. The digital warehouse quality assurance framework proposed and discussed in this work is unique and has potential to not only accelerate adoption of AM in oil & gas and offshore sectors, but also contribute to a significant reduction of emissions, including greenhouse gases.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84180599","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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