The 2014 Wood Review is a report reviewing UK offshore oil and gas recovery and its regulation, led by Sir Ian Wood. The report identifies and addresses key challenges in the UK petroleum industry, among them the lack of a strong regulatory body and a decommissioning strategy. The UK petroleum industry is mature, and Norway may benefit from UK's experiences in decommissioning. The article investigates the applicability of the Wood Review recommendations for decommissioning in Norway. The analysis of the recommendations in the Wood Review is carried out by a SWOT-analysis of the general recommendations with a high potential impact on decommissioning as well as the five recommendations specific to decommissioning. The recommendations in the Wood Review were broadly accepted by UK authorities and formed the basis for numerous initiatives aimed at improving policies and practices in UK decommissioning. The key initiatives are presented to illustrate how the Wood Review recommendations has been interpreted. A summary of the key differences between the petroleum industries and the regulatory authorities in Norway and the UK is provided for background. Decommissioning in Norway face similar challenges to those identified in the Wood Review. The analysis indicates that several of the UK initiatives following the recommendations in the Wood Review has the potential of improving decommissioning in Norway. Differences in regulatory regimes between the regions may complicate the implementation of some of the initiatives following the Wood Review in Norway. In most cases only minor changes to regulations and/or practices are required. Recent UK initiatives with a high impact on decommissioning include increased focus on sharing of information and lessons learned, increased collaboration, the development of a decommissioning strategy, benchmarking of decommissioning cost estimates for all projects and the development and publishing of annual UK decommissioning cost estimates. There are indications that the Norwegian Petroleum Directorate (NPD) and the Norwegian Ministry of Petroleum and Energy (MPE) are falling behind their UK counterparts in key areas. Norway has limited experience with decommissioning, and scrupulous analysis of lessons learned in other regions is essential. Decommissioning of Norwegian offshore infrastructure is a major undertaking and even minor improvements may have a substantial impact on personnel risk, risk to the environment or the total decommissioning expenditure. The Norwegian regulatory regime has been an integral part of the Norwegian petroleum industry's success in previous decades, and changes to the regime require careful deliberation. The recent implementation of initiatives aimed at improving decommissioning regulations and practices in the UK represents a unique learning opportunity for Norwegian authorities. The analysis suggest that Norway may benefit from adopting some of the UK initiatives following the Wood Review
{"title":"Initiatives in UK Offshore Decommissioning Following the Wood Review: Applicability for Decommissioning in Norway","authors":"Rune Vikane, J. Selvik, E. Abrahamsen","doi":"10.2118/205439-ms","DOIUrl":"https://doi.org/10.2118/205439-ms","url":null,"abstract":"\u0000 The 2014 Wood Review is a report reviewing UK offshore oil and gas recovery and its regulation, led by Sir Ian Wood. The report identifies and addresses key challenges in the UK petroleum industry, among them the lack of a strong regulatory body and a decommissioning strategy. The UK petroleum industry is mature, and Norway may benefit from UK's experiences in decommissioning. The article investigates the applicability of the Wood Review recommendations for decommissioning in Norway.\u0000 The analysis of the recommendations in the Wood Review is carried out by a SWOT-analysis of the general recommendations with a high potential impact on decommissioning as well as the five recommendations specific to decommissioning. The recommendations in the Wood Review were broadly accepted by UK authorities and formed the basis for numerous initiatives aimed at improving policies and practices in UK decommissioning. The key initiatives are presented to illustrate how the Wood Review recommendations has been interpreted. A summary of the key differences between the petroleum industries and the regulatory authorities in Norway and the UK is provided for background.\u0000 Decommissioning in Norway face similar challenges to those identified in the Wood Review. The analysis indicates that several of the UK initiatives following the recommendations in the Wood Review has the potential of improving decommissioning in Norway. Differences in regulatory regimes between the regions may complicate the implementation of some of the initiatives following the Wood Review in Norway. In most cases only minor changes to regulations and/or practices are required. Recent UK initiatives with a high impact on decommissioning include increased focus on sharing of information and lessons learned, increased collaboration, the development of a decommissioning strategy, benchmarking of decommissioning cost estimates for all projects and the development and publishing of annual UK decommissioning cost estimates. There are indications that the Norwegian Petroleum Directorate (NPD) and the Norwegian Ministry of Petroleum and Energy (MPE) are falling behind their UK counterparts in key areas. Norway has limited experience with decommissioning, and scrupulous analysis of lessons learned in other regions is essential. Decommissioning of Norwegian offshore infrastructure is a major undertaking and even minor improvements may have a substantial impact on personnel risk, risk to the environment or the total decommissioning expenditure.\u0000 The Norwegian regulatory regime has been an integral part of the Norwegian petroleum industry's success in previous decades, and changes to the regime require careful deliberation. The recent implementation of initiatives aimed at improving decommissioning regulations and practices in the UK represents a unique learning opportunity for Norwegian authorities. The analysis suggest that Norway may benefit from adopting some of the UK initiatives following the Wood Review","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"161 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127414733","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}
Maximizing operational efficiency is a critical challenge in oil and gas production, particularly important for mature assets in the North Sea. The causes of production shortfalls are numerous, distributed across a wide range of disciplines, technical and non-technical causes. The primary reason to apply Natural Language Processing (NLP) and text mining on several years of shortfall history was the need to support efficiently the evaluation of digital transformation use-case screenings and value mapping exercises, through a proper mapping of the issues faced. Obviously, this mapping contributed as well to reflect on operational surveillance and maintenance strategies to reduce the production shortfalls. This paper presents a methodology where the historical records of descriptions, comments and results of investigation regarding production shortfalls are revisited, adding to existing shortfall classifications and statistics, in particular in two domains: richer first root-cause mapping, and a series of advanced visualizations and analytics. The methodology put in place uses natural-language pre-processing techniques, combined with keyword-based text-mining and classification techniques. The limitations associated to the size and quality of these language datasets will be described, and the results discussed, highlighting the value of reaching high level of data granularity while defeating the ‘more information, less attention’ bias. At the same time, visual designs are introduced to display efficiently the different dimensions of this data (impact, frequency evolution through time, location in term of field and affected systems, root causes and other cause-related categories). The ambition in the domain of visualization is to create User Experience-friendly shortfall analytics, that can be displayed in smart rooms and collaborative rooms, where display's efficiency is higher when user-interactions are kept minimal, number of charts is limited and multiple dimensions do not collide. The paper is based on several applications across the North Sea. This case study and the associated lessons learned regarding natural language processing and text mining applied to similar technical concise data are answering several frequently asked questions on the value of the textual data records gathered over years.
{"title":"Natural Language Processing and Text Mining Approaches in Production Shortfalls Analytics: Methodology, Case-Study and Value in the North Sea","authors":"Edgar Bernier, S. Perrier","doi":"10.2118/205443-ms","DOIUrl":"https://doi.org/10.2118/205443-ms","url":null,"abstract":"\u0000 Maximizing operational efficiency is a critical challenge in oil and gas production, particularly important for mature assets in the North Sea. The causes of production shortfalls are numerous, distributed across a wide range of disciplines, technical and non-technical causes.\u0000 The primary reason to apply Natural Language Processing (NLP) and text mining on several years of shortfall history was the need to support efficiently the evaluation of digital transformation use-case screenings and value mapping exercises, through a proper mapping of the issues faced. Obviously, this mapping contributed as well to reflect on operational surveillance and maintenance strategies to reduce the production shortfalls.\u0000 This paper presents a methodology where the historical records of descriptions, comments and results of investigation regarding production shortfalls are revisited, adding to existing shortfall classifications and statistics, in particular in two domains: richer first root-cause mapping, and a series of advanced visualizations and analytics.\u0000 The methodology put in place uses natural-language pre-processing techniques, combined with keyword-based text-mining and classification techniques. The limitations associated to the size and quality of these language datasets will be described, and the results discussed, highlighting the value of reaching high level of data granularity while defeating the ‘more information, less attention’ bias.\u0000 At the same time, visual designs are introduced to display efficiently the different dimensions of this data (impact, frequency evolution through time, location in term of field and affected systems, root causes and other cause-related categories). The ambition in the domain of visualization is to create User Experience-friendly shortfall analytics, that can be displayed in smart rooms and collaborative rooms, where display's efficiency is higher when user-interactions are kept minimal, number of charts is limited and multiple dimensions do not collide.\u0000 The paper is based on several applications across the North Sea. This case study and the associated lessons learned regarding natural language processing and text mining applied to similar technical concise data are answering several frequently asked questions on the value of the textual data records gathered over years.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129949909","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}
Working towards a net zero future requires change and adaptation from us all. Innovation offers many potential solutions on how to successfully make that change within the oil and gas industry. Consequently, maximising the value that technological innovation presents is vital for delivering a sustainable net zero. Yet, the oil and gas industry has developed a reputation for being conservative and reluctant to adopt new technology, with companies sometimes referred to as "fast followers". In recent years, the industry has begun to change with an incremental increase in innovation activities. Despite these efforts, and a need to accelerate innovation, there appears to be a resistance to adopt new technology. Evidence from O&G industry bodies indicate that psychological factors play a key role in technology adoption; not surprisingly, as workers, managers, investors, and regulators can all have a powerful influence on an organisation's receptivity to new technology. Recent research has provided insight into the psychological factors that influence technology uptake decisions in the oil and gas industry. Through a series of studies, the psychological technology adoption framework (P-TAF) was developed which outlined the 15 key psychological factors that influence technology adoption decisions. These are organised into 6 categories: personality, attitudes, motivations, cognitive factors, social factors, and organisational level factors. The work emphasised the influence that overarching organisational culture can have on how people respond to and introduce technology within their company. Whilst technology readiness levels are commonly applied to start-ups and their innovations, less is known about the readiness culture which facilitates innovation uptake. To bridge this gap, a preliminary measure of organisational innovation adoption culture was developed as based upon the previous psychological research, empirical innovation measures, and organisational culture models. This was piloted as an online survey with 36 people working in the technology space in O&G in June 2020. These results were used to later refine the culture measure to develop a 33-item scale consisting of eight categories. This new measure was deployed as part of an industry benchmarking study of innovation adoption culture within O&G consisting of 82 managers from 12 companies and in December 2020. Participating organisations were given the opportunity to receive a snapshot of their technology adoption culture. An overview of the measure and a summary of survey results will be given during the presentation as well as recommendations on how to support an innovation adoption culture. A considerable volume of new technology needs to be developed and adopted to be able to reach net zero and understanding the psychological and cultural barriers is imperative to delivering that.
{"title":"Accelerating Technology Adoption: A Benchmarking Study of Organisational Innovation Adoption Culture in Upstream Oil and Gas","authors":"Ruby Roberts, R. Flin, Luca Corradi","doi":"10.2118/205448-ms","DOIUrl":"https://doi.org/10.2118/205448-ms","url":null,"abstract":"\u0000 Working towards a net zero future requires change and adaptation from us all. Innovation offers many potential solutions on how to successfully make that change within the oil and gas industry. Consequently, maximising the value that technological innovation presents is vital for delivering a sustainable net zero. Yet, the oil and gas industry has developed a reputation for being conservative and reluctant to adopt new technology, with companies sometimes referred to as \"fast followers\". In recent years, the industry has begun to change with an incremental increase in innovation activities. Despite these efforts, and a need to accelerate innovation, there appears to be a resistance to adopt new technology.\u0000 Evidence from O&G industry bodies indicate that psychological factors play a key role in technology adoption; not surprisingly, as workers, managers, investors, and regulators can all have a powerful influence on an organisation's receptivity to new technology. Recent research has provided insight into the psychological factors that influence technology uptake decisions in the oil and gas industry. Through a series of studies, the psychological technology adoption framework (P-TAF) was developed which outlined the 15 key psychological factors that influence technology adoption decisions. These are organised into 6 categories: personality, attitudes, motivations, cognitive factors, social factors, and organisational level factors. The work emphasised the influence that overarching organisational culture can have on how people respond to and introduce technology within their company. Whilst technology readiness levels are commonly applied to start-ups and their innovations, less is known about the readiness culture which facilitates innovation uptake.\u0000 To bridge this gap, a preliminary measure of organisational innovation adoption culture was developed as based upon the previous psychological research, empirical innovation measures, and organisational culture models. This was piloted as an online survey with 36 people working in the technology space in O&G in June 2020. These results were used to later refine the culture measure to develop a 33-item scale consisting of eight categories. This new measure was deployed as part of an industry benchmarking study of innovation adoption culture within O&G consisting of 82 managers from 12 companies and in December 2020. Participating organisations were given the opportunity to receive a snapshot of their technology adoption culture. An overview of the measure and a summary of survey results will be given during the presentation as well as recommendations on how to support an innovation adoption culture. A considerable volume of new technology needs to be developed and adopted to be able to reach net zero and understanding the psychological and cultural barriers is imperative to delivering that.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134638235","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the past 70 years the world has relied extensively for its energy needs based on hydrocarbons produced significantly offshore. In recent years many installations with fixed platforms and pipelines are reaching the end of their useful life and are required by law to be decommissioned and removed if an approved alternative use cannot be found. This process coincides with focus on decarbonization arising from global warming and climate change. The conventional way of decommissioning is to remove the structure and take it onshore for disposal. Such an activity costs around £28 million for smaller UKCS installations in the Southern North Sea. Possible alternative solutions include their use as a research-leisure complex and artificial reef. Such an approach would have less impact on the environment and it is therefore worthwhile to explore the feasibility of repurposing these decommissioned UKCS platforms. The paper begins by highlighting the background to UKCS offshore decommissioning and farming fish life-cycle. This is followed by a critical review of the three options of total and partial removals and leave-on-site. It is found that repurposing decommissioned platforms for aquaculture farm has not been given sufficient attention and thus offers scope for a project to explore the feasibility of such a solution. Existing offshore fish farming in various countries are examined before using a decision-making matrix to select the most suitable UKCS installation for conversion and this led to using a normally unattended gas platform for the case study. The focus for this paper is on design and operation of an unattended fish farm and its cost benefit analysis. The former covers fish cage selection, capacity calculation, fish handling procedures, fish feed characteristics, feed demand, designing feed logistics and storage system. The processing facilities are layout on two decks and power needs are generated using a hybrid system of diesel and Li-ion battery. The possibility of using renewable sources by connecting to wind energy grids was also considered. For the latter capital and operating expenditure, revenue generated and maintenance costs are estimated before performing net present value prediction of the profitability of the fish farm over 10 years with for example up to 8 cages and three discount rates. The main conclusions derived are: It is technically feasible to convert a decommissioned gas platform to a fish farm and the operation can be economic. However, liability transfer implications in a repurposed offshore decommissioned gas platforms to fish farms were not established to verify the project viability. The conversion of unattended offshore gas platforms in the UKCS to an automated offshore fish farm is a novel solution which has not been implemented in the North Sea before. The work will provide an economic and environmental friendly solution to decommissioning offshore platforms and provide with a possible profitable investmen
{"title":"Feasibility of Repurposing Offshore Decommissioned Gas Rigs into Fish Farms","authors":"Saptarshi Pal, C. Kuo","doi":"10.2118/205446-ms","DOIUrl":"https://doi.org/10.2118/205446-ms","url":null,"abstract":"\u0000 In the past 70 years the world has relied extensively for its energy needs based on hydrocarbons produced significantly offshore. In recent years many installations with fixed platforms and pipelines are reaching the end of their useful life and are required by law to be decommissioned and removed if an approved alternative use cannot be found. This process coincides with focus on decarbonization arising from global warming and climate change. The conventional way of decommissioning is to remove the structure and take it onshore for disposal. Such an activity costs around £28 million for smaller UKCS installations in the Southern North Sea. Possible alternative solutions include their use as a research-leisure complex and artificial reef. Such an approach would have less impact on the environment and it is therefore worthwhile to explore the feasibility of repurposing these decommissioned UKCS platforms.\u0000 The paper begins by highlighting the background to UKCS offshore decommissioning and farming fish life-cycle. This is followed by a critical review of the three options of total and partial removals and leave-on-site. It is found that repurposing decommissioned platforms for aquaculture farm has not been given sufficient attention and thus offers scope for a project to explore the feasibility of such a solution. Existing offshore fish farming in various countries are examined before using a decision-making matrix to select the most suitable UKCS installation for conversion and this led to using a normally unattended gas platform for the case study.\u0000 The focus for this paper is on design and operation of an unattended fish farm and its cost benefit analysis. The former covers fish cage selection, capacity calculation, fish handling procedures, fish feed characteristics, feed demand, designing feed logistics and storage system. The processing facilities are layout on two decks and power needs are generated using a hybrid system of diesel and Li-ion battery. The possibility of using renewable sources by connecting to wind energy grids was also considered. For the latter capital and operating expenditure, revenue generated and maintenance costs are estimated before performing net present value prediction of the profitability of the fish farm over 10 years with for example up to 8 cages and three discount rates.\u0000 The main conclusions derived are: It is technically feasible to convert a decommissioned gas platform to a fish farm and the operation can be economic. However, liability transfer implications in a repurposed offshore decommissioned gas platforms to fish farms were not established to verify the project viability.\u0000 The conversion of unattended offshore gas platforms in the UKCS to an automated offshore fish farm is a novel solution which has not been implemented in the North Sea before. The work will provide an economic and environmental friendly solution to decommissioning offshore platforms and provide with a possible profitable investmen","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121183610","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}
Thousands of wells will enter the plug and abandonment (P&A) phase across the Norwegian Continental Shelf (NCS), either for permanent well abandonment or section abandonment with subsequent sidetracks. In the medium and long term, more wells will be added to follow the same path as exploration, drilling, and production continues. The cost of abandonment operations demands improvement of how P&A operations are performed. A critical, and often time-consuming operation, of well or section abandonment is to cut and pull (C&P) some of the casing strings. Uncertainties about the status of the annular contents and the material within it, such as settled solids, contaminated cement, or well geometry might pose restraints that could hinder the C&P efficiency. The uncertainties may cause operations to deviate from the plan, increasing the time and the costs required. New-generation ultrasonic tools, in combination with sonic tools, provide information about the annulus material with a detailed map of the axial and azimuthal variations of the annulus contents. The geometric position of the inner pipe can be determined relative to the outer casing or borehole using advanced measurements. Logging with ultrasonic and sonic tools is a noninvasive method that can increase the efficiency of C&P operations. In this paper we discuss three case studies of wells ranging from 2 to 40 years old. Some of the wells have reached the end of their economic life and are now ready for permanent plug and abandonment (PP&A) or slot recovery. Each case is unique with different casing sizes being retrieved, along with varied annulus contents observed from ultrasonic and sonic log data. The innovative use of the data interpretation with advanced workflows decreased uncertainties about the annulus contents and enabled following an informed C&P strategy. In all three cases, the casing sections were retrieved without difficulties from the recommended depths of the analysis. Casing milling was performed in intervals where C&P was not supported by the data analysis.
{"title":"Optimizing Casing Cut and Pull Operations Efficiency Using Ultrasonic Logging Data","authors":"Tonje Winther, G. O. Palacio, Amit Govil","doi":"10.2118/205431-ms","DOIUrl":"https://doi.org/10.2118/205431-ms","url":null,"abstract":"\u0000 Thousands of wells will enter the plug and abandonment (P&A) phase across the Norwegian Continental Shelf (NCS), either for permanent well abandonment or section abandonment with subsequent sidetracks. In the medium and long term, more wells will be added to follow the same path as exploration, drilling, and production continues.\u0000 The cost of abandonment operations demands improvement of how P&A operations are performed. A critical, and often time-consuming operation, of well or section abandonment is to cut and pull (C&P) some of the casing strings. Uncertainties about the status of the annular contents and the material within it, such as settled solids, contaminated cement, or well geometry might pose restraints that could hinder the C&P efficiency. The uncertainties may cause operations to deviate from the plan, increasing the time and the costs required.\u0000 New-generation ultrasonic tools, in combination with sonic tools, provide information about the annulus material with a detailed map of the axial and azimuthal variations of the annulus contents. The geometric position of the inner pipe can be determined relative to the outer casing or borehole using advanced measurements. Logging with ultrasonic and sonic tools is a noninvasive method that can increase the efficiency of C&P operations.\u0000 In this paper we discuss three case studies of wells ranging from 2 to 40 years old. Some of the wells have reached the end of their economic life and are now ready for permanent plug and abandonment (PP&A) or slot recovery. Each case is unique with different casing sizes being retrieved, along with varied annulus contents observed from ultrasonic and sonic log data. The innovative use of the data interpretation with advanced workflows decreased uncertainties about the annulus contents and enabled following an informed C&P strategy. In all three cases, the casing sections were retrieved without difficulties from the recommended depths of the analysis. Casing milling was performed in intervals where C&P was not supported by the data analysis.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128631027","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. Holdway, Mark Patrick Dowling, I. Bell, Iain Laing
The purpose of conducting this LCA was to calculate the potential environmental impacts of the repurposing of John Lawrie Tubulars products sourced from North Sea Oil and Gas fields and to compare repurposed steel tubulars to those made from prime steel1throughout their lifecycle. The analysis includes multiple environmental characterization indicators associated with the material processing, on-site operations, and supply chain. The benefits of repurposed tubulars are consistently beneficial across all environmental indicators when compared to prime steel tubulars. The life cycle analysis results show that for every tonne of steel tubular repurposed there is a 97.21% saving of carbon emissions over a prime steel seamless equivalent and is 97.78% for welded steel tubulars (cradle to gate). Further characterization analysis (cradle to site) showed that distribution presented the highest impact (47%) with materials (26%) and material transportation (15%). The average delivery in the UK adds 56.53kgCO2eto John Lawrie's tubular steel giving a cradle to delivery at the customers gate of 118.53kgCO2eper tonne2. The combined material and distribution carbon footprint of repurposed tubular products (cradle to site) has ~6% of the impact of those made from prime steel. With growing pressure on the construction industry amongst others to be more resource efficient, and to lower embodied carbon, material reuse strategies are critical to meet targets. Considering the potential of the results for environmental impact reduction there is the need to further develop and promote the application of repurposed steel tubulars. This data can be used to demonstrate the environmental impacts and benefits of refurbished tubulars and supports the efficacy of environmental claims and contribution to circular economy. With both the construction and energy industries focused on finding innovative ways in which to reduce their emissions and support the Scottish and UK Governments in bringing all greenhouse gas emissions (GHG) to net zero by 2050, this study details one way these industries can help drive the changes required.
{"title":"The Environmental Benefits of Repurposing Tubular Steel from North Sea Oil and Gas Fields","authors":"R. Holdway, Mark Patrick Dowling, I. Bell, Iain Laing","doi":"10.2118/205468-ms","DOIUrl":"https://doi.org/10.2118/205468-ms","url":null,"abstract":"\u0000 The purpose of conducting this LCA was to calculate the potential environmental impacts of the repurposing of John Lawrie Tubulars products sourced from North Sea Oil and Gas fields and to compare repurposed steel tubulars to those made from prime steel1throughout their lifecycle.\u0000 The analysis includes multiple environmental characterization indicators associated with the material processing, on-site operations, and supply chain. The benefits of repurposed tubulars are consistently beneficial across all environmental indicators when compared to prime steel tubulars. The life cycle analysis results show that for every tonne of steel tubular repurposed there is a 97.21% saving of carbon emissions over a prime steel seamless equivalent and is 97.78% for welded steel tubulars (cradle to gate).\u0000 Further characterization analysis (cradle to site) showed that distribution presented the highest impact (47%) with materials (26%) and material transportation (15%). The average delivery in the UK adds 56.53kgCO2eto John Lawrie's tubular steel giving a cradle to delivery at the customers gate of 118.53kgCO2eper tonne2. The combined material and distribution carbon footprint of repurposed tubular products (cradle to site) has ~6% of the impact of those made from prime steel.\u0000 With growing pressure on the construction industry amongst others to be more resource efficient, and to lower embodied carbon, material reuse strategies are critical to meet targets. Considering the potential of the results for environmental impact reduction there is the need to further develop and promote the application of repurposed steel tubulars. This data can be used to demonstrate the environmental impacts and benefits of refurbished tubulars and supports the efficacy of environmental claims and contribution to circular economy.\u0000 With both the construction and energy industries focused on finding innovative ways in which to reduce their emissions and support the Scottish and UK Governments in bringing all greenhouse gas emissions (GHG) to net zero by 2050, this study details one way these industries can help drive the changes required.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"280 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128635034","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}
Well clean-up is one of the most complex operations performed at the wellsite today. During clean-up, a well is flowing for the first time after initial completion or workover operations through temporary surface facilities to either conduct a welltest or to simply condition the well before connecting it to production facilities. Currently, there are no practical recommendations available that would summarize clean-up experiences and guide operating companies through the process of efficiently planning well clean-up operations. Conventional well clean-up operations are inherently challenging owing to the requirements for accurate data measurements, safe handling and disposal of produced fluids (hydrocarbons, completion brine, water, and solids). Experience has shown that it is nearly impossible to perform well clean up within pre-defined constraints and target criteria without an appropriate design, equipment selection and operations planning to account for the specificities of each situation. Steady-state flow simulators have been the standard tool to model pressure and temperature changes along the wellbore and through temporary production system during well clean-up process. Those assume either final stabilized conditions or a limited number of intermediate ones and formed the basis for equipment selection. But this approach has critical limitations in modelling flowing well behavior and fast-changing flowing conditions, and therefore in assessing operational flow assurance risks and the dynamic capability of the surface plant to handle produced fluids. The paper describes in detail today's challenges during well clean-up operations that combine the need for operational safety, minimal environmental footprint and flow assurance considerations that have to be balanced with costs and production performance optimization. The paper provides practical recommendations and presents multiple case studies highlighting the results and lessons learned from applying a novel, unique workflow based on the application of a transient-multiphase flow simulator. Combined with modern well-testing equipment such as modern test separators, remotely actuated adjustable chokes or environmentally friendly fluid disposal techniques, such advanced design allows performing clean-up operations efficiently while remaining within time, rates, pressure or emissions limits.
{"title":"Fast, Environmentally Sound and Efficient Well Clean-Up Operations: Lessons Learned and Best Practices from Operations Around the World","authors":"Y. Shumakov, F. Hollaender, A. Zhandin","doi":"10.2118/205419-ms","DOIUrl":"https://doi.org/10.2118/205419-ms","url":null,"abstract":"\u0000 Well clean-up is one of the most complex operations performed at the wellsite today. During clean-up, a well is flowing for the first time after initial completion or workover operations through temporary surface facilities to either conduct a welltest or to simply condition the well before connecting it to production facilities. Currently, there are no practical recommendations available that would summarize clean-up experiences and guide operating companies through the process of efficiently planning well clean-up operations.\u0000 Conventional well clean-up operations are inherently challenging owing to the requirements for accurate data measurements, safe handling and disposal of produced fluids (hydrocarbons, completion brine, water, and solids). Experience has shown that it is nearly impossible to perform well clean up within pre-defined constraints and target criteria without an appropriate design, equipment selection and operations planning to account for the specificities of each situation.\u0000 Steady-state flow simulators have been the standard tool to model pressure and temperature changes along the wellbore and through temporary production system during well clean-up process. Those assume either final stabilized conditions or a limited number of intermediate ones and formed the basis for equipment selection. But this approach has critical limitations in modelling flowing well behavior and fast-changing flowing conditions, and therefore in assessing operational flow assurance risks and the dynamic capability of the surface plant to handle produced fluids.\u0000 The paper describes in detail today's challenges during well clean-up operations that combine the need for operational safety, minimal environmental footprint and flow assurance considerations that have to be balanced with costs and production performance optimization. The paper provides practical recommendations and presents multiple case studies highlighting the results and lessons learned from applying a novel, unique workflow based on the application of a transient-multiphase flow simulator. Combined with modern well-testing equipment such as modern test separators, remotely actuated adjustable chokes or environmentally friendly fluid disposal techniques, such advanced design allows performing clean-up operations efficiently while remaining within time, rates, pressure or emissions limits.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131491532","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}
Employing novel drilling, and tunneling methods are active area of study since 1930s. In the present report, an Experimental study of the thermal impact of laser and plasma torch on carbonated rocks as part of thermal assisted drilling operation is presented. The experimental findings are then evaluated and verified by the Kirch's equations for stresses and strains around a cylindrical borehole. Since it is vital to carefully studying the wellbore stability in this type of drilling method, especially if it is associated with underbalanced drilling (UBD) and or Managed pressure drilling (MPD), further numerical investigations are carried out to highlight the necessary considerations in this regard.
{"title":"Application of Laser and Plasma for Thermal Assisted Drilling in Carbonated Formations","authors":"M. Bazargan","doi":"10.2118/205462-ms","DOIUrl":"https://doi.org/10.2118/205462-ms","url":null,"abstract":"\u0000 Employing novel drilling, and tunneling methods are active area of study since 1930s. In the present report, an Experimental study of the thermal impact of laser and plasma torch on carbonated rocks as part of thermal assisted drilling operation is presented. The experimental findings are then evaluated and verified by the Kirch's equations for stresses and strains around a cylindrical borehole. Since it is vital to carefully studying the wellbore stability in this type of drilling method, especially if it is associated with underbalanced drilling (UBD) and or Managed pressure drilling (MPD), further numerical investigations are carried out to highlight the necessary considerations in this regard.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115095200","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}
Aaron C. Hammer, Tom D Gonzalez, Herb P Dhuet, Hege Andresen, Siv Merete M Sunde, Elshan Jabrayilov, Iris Sok Yee Kam, Torstein Tviet
The Troll Phase 3 (TP3) wells were designed to enable high gas rates and sand free production for an expected lifetime of 40 years with a minimum pressure drop. By taking reservoir and production properties into account, open-hole gravel pack (GP) sand screens in the lower completion and big bore tubing in the upper completion were selected. To further reduce the pressure loss in the well, reduce rig time and cost, and reduce deployment risks, eliminating the intermediate completion was proposed. Traditionally, an intermediate completion is required to serve as a gas-tight barrier for running of the upper completion, mainly due to historical limitations of the GP extension (GP sleeve) not being a barrier qualified to API 19AC Validation grade V0 (referred to as V0 hereafter) after pumping sand slurry through it (post-erosion). An extensive qualification program was completed to qualify the GP system to API 11D1 and API 19AC V0 for use as a gas-tight barrier post-erosion. This allows the GP system to serve as a primary barrier while installing the upper completion and temporarily abandoning the well. The GP packer was qualified to API 11D1 V0 with the additional requirement to perform entire qualification in as-rolled casing and including a plug-in-tailpipe load case. The GP sleeve provided the most technically challenging requirements: a full-scale erosion test, immediate closure of the sleeve after pumping operation, followed by API 19AC Annex A V0 validation. Challenges were encountered trying to meet the rigorous V0 (zero bubble) acceptance criteria post-erosion. A significantly different approach was developed to achieve gas-tight performance in debris-laden environments. The new design successfully passed the post-erosion API 19AC V0 qualification to the full rating of the GP sleeve. The GP system development and qualification enabled the industry-first V0 post-erosion GP system for Equinor, which eliminates the need for an intermediate completion. This state-of-the-art gravel pack system enabled the simplified high gas rate, big-bore well design, not previously possible given well barrier considerations. The reduced pressure drop across the lower completion is expected to yield a higher gas production rate for the 40 years expected well life, contributing significant value to the TP3 project.
{"title":"Development of API 11D1 and API 19AC Validation Grade V0 Barrier-Qualified Gravel Pack System for Troll Phase 3 Big-Bore, High-Rate Gas Completions on the Norwegian Continental Shelf","authors":"Aaron C. Hammer, Tom D Gonzalez, Herb P Dhuet, Hege Andresen, Siv Merete M Sunde, Elshan Jabrayilov, Iris Sok Yee Kam, Torstein Tviet","doi":"10.2118/205403-ms","DOIUrl":"https://doi.org/10.2118/205403-ms","url":null,"abstract":"\u0000 The Troll Phase 3 (TP3) wells were designed to enable high gas rates and sand free production for an expected lifetime of 40 years with a minimum pressure drop. By taking reservoir and production properties into account, open-hole gravel pack (GP) sand screens in the lower completion and big bore tubing in the upper completion were selected. To further reduce the pressure loss in the well, reduce rig time and cost, and reduce deployment risks, eliminating the intermediate completion was proposed. Traditionally, an intermediate completion is required to serve as a gas-tight barrier for running of the upper completion, mainly due to historical limitations of the GP extension (GP sleeve) not being a barrier qualified to API 19AC Validation grade V0 (referred to as V0 hereafter) after pumping sand slurry through it (post-erosion). An extensive qualification program was completed to qualify the GP system to API 11D1 and API 19AC V0 for use as a gas-tight barrier post-erosion. This allows the GP system to serve as a primary barrier while installing the upper completion and temporarily abandoning the well. The GP packer was qualified to API 11D1 V0 with the additional requirement to perform entire qualification in as-rolled casing and including a plug-in-tailpipe load case. The GP sleeve provided the most technically challenging requirements: a full-scale erosion test, immediate closure of the sleeve after pumping operation, followed by API 19AC Annex A V0 validation. Challenges were encountered trying to meet the rigorous V0 (zero bubble) acceptance criteria post-erosion. A significantly different approach was developed to achieve gas-tight performance in debris-laden environments. The new design successfully passed the post-erosion API 19AC V0 qualification to the full rating of the GP sleeve. The GP system development and qualification enabled the industry-first V0 post-erosion GP system for Equinor, which eliminates the need for an intermediate completion. This state-of-the-art gravel pack system enabled the simplified high gas rate, big-bore well design, not previously possible given well barrier considerations. The reduced pressure drop across the lower completion is expected to yield a higher gas production rate for the 40 years expected well life, contributing significant value to the TP3 project.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122370132","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}
Georgios Nikolakopoulos-Skelly, M. Giddins, Rong Xu, Chioma Ezeogu, M. Jackson
In this paper, we describe an approach to designing monitoring schemes for carbon dioxide sequestration in saline aquifers. Changes in key parameters are investigated over timescales of up to a thousand years. The study addresses movement of the CO2 plume, possible locations for observation wells and the period for which a storage location should be monitored. For the initial sensitivity analysis, we use a simple homogeneous reservoir simulation model to understand how reservoir, operational and model parameters affect the amount of mobile CO2 remaining at different times over the storage period. The parameters with the greatest impact are taken forward to uncertainty studies, which are conducted on two reservoir models with more realistic geological characteristics: one with lateral extensive baffles and one with sand channels. For these cases, we investigate the movement of the CO2 plume and its arrival at possible locations for an observation well. Results from the sensitivity analysis indicate that the most influential parameters are horizontal permeability, dipping angle, critical gas saturation, salinity, the period of injection and the capillary pressure curve. The results from the uncertainty studies indicate that for the two heterogeneous models, a reasonable monitoring period is in the range of 60 to 150 years and that the movement of the plume probably stops after approximately 100 years. The arrival time of CO2 at the observation well can be predicted with greater confidence when the well is in close proximity to the injector and in the direction in which CO2 will preferably move. A correlation analysis on the uncertain parameters shows that the main contributor affecting the amount of mobile CO2 is critical gas saturation, followed by dipping angle and the period of injection. While previous studies focus on how different parameters affect immobilization of CO2, this study aims to develop a methodology to plan long-term monitoring of mobile CO2. Prediction of the expected plume movement can help to determine suitable observation well locations and reasonable timescales for the monitoring process.
{"title":"Reservoir Simulation Studies for Planning Monitoring Schemes for CO2 Storage","authors":"Georgios Nikolakopoulos-Skelly, M. Giddins, Rong Xu, Chioma Ezeogu, M. Jackson","doi":"10.2118/205453-ms","DOIUrl":"https://doi.org/10.2118/205453-ms","url":null,"abstract":"\u0000 In this paper, we describe an approach to designing monitoring schemes for carbon dioxide sequestration in saline aquifers. Changes in key parameters are investigated over timescales of up to a thousand years. The study addresses movement of the CO2 plume, possible locations for observation wells and the period for which a storage location should be monitored.\u0000 For the initial sensitivity analysis, we use a simple homogeneous reservoir simulation model to understand how reservoir, operational and model parameters affect the amount of mobile CO2 remaining at different times over the storage period. The parameters with the greatest impact are taken forward to uncertainty studies, which are conducted on two reservoir models with more realistic geological characteristics: one with lateral extensive baffles and one with sand channels. For these cases, we investigate the movement of the CO2 plume and its arrival at possible locations for an observation well.\u0000 Results from the sensitivity analysis indicate that the most influential parameters are horizontal permeability, dipping angle, critical gas saturation, salinity, the period of injection and the capillary pressure curve. The results from the uncertainty studies indicate that for the two heterogeneous models, a reasonable monitoring period is in the range of 60 to 150 years and that the movement of the plume probably stops after approximately 100 years. The arrival time of CO2 at the observation well can be predicted with greater confidence when the well is in close proximity to the injector and in the direction in which CO2 will preferably move. A correlation analysis on the uncertain parameters shows that the main contributor affecting the amount of mobile CO2 is critical gas saturation, followed by dipping angle and the period of injection.\u0000 While previous studies focus on how different parameters affect immobilization of CO2, this study aims to develop a methodology to plan long-term monitoring of mobile CO2. Prediction of the expected plume movement can help to determine suitable observation well locations and reasonable timescales for the monitoring process.","PeriodicalId":277521,"journal":{"name":"Day 2 Wed, September 08, 2021","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-09-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130645888","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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