Evolving energy needs and the global energy transition call for proper evaluation of how Natural Gas could support a Decarbonisation path, considering Natural Gas well recognised contribution to GHG emission reduction approaching the ambitious Green World. However, the main question is how gas resources can be properly delivered to satisfy a wide range of markets and usages considering that fundamental driver is the goal of reducing carbon footprint. A methodology was developed, named Gas Master Plan (GMP), which is an integrated study with a novel view, looking to synergic opportunities among energy sources while defining economically sustainable business models and meeting Decarbonisation targets. A Gas Master Plan is a multidisciplinary study assessing the best valorisation routes for Natural Gas resources in a specified country or geographical region. This kind of study analyses gas and energy supply/demand balance, understanding current and future markets and looks for adequate destinations, check existing infrastructures and further possible developments carried by Local Governments or private entities, identify potential gas production for all the involved resources, business modelling, understanding the benefits to the global energy transition targets that such resources could deliver and screening monetization opportunities under a strategic plan view. Thus, a GMP is not just an analysis of upstream volumes to verify whether they match commitments and still fit in their future development plans but it is company-wide joint effort to gather ideas, proposals, topics or issues to be addressed and possible solutions. Broadly speaking resources considered in a typical GMP would be: those under an exploration phase, those just discovered for which a proper development has to be realised, those already in production but for which new market opportunities can be scouted in order to improve their benefit on the energy transition paths while seeking further economic returns. The primary result is to develop a strategy to optimize present production and the development and valorisation of future gas assets, identifying the related GHG profile for each opportunity, supporting the decision-making process on new/future gas initiatives with a coherent plan. The resulting outcomes and conclusions may address specific topics on the short to medium term, like associate to a gas field the proper development project to cover gas and energy commercial demand, or set targets achievable on the medium to long term like supporting a low carbon footprint growth in the energy sector and promoting gas-based industries.
{"title":"An Approach to Natural Gas Valorisation Opportunities Screening Along the Decarbonisation Path","authors":"M. Iovane, Marco Flisi","doi":"10.2118/208037-ms","DOIUrl":"https://doi.org/10.2118/208037-ms","url":null,"abstract":"Evolving energy needs and the global energy transition call for proper evaluation of how Natural Gas could support a Decarbonisation path, considering Natural Gas well recognised contribution to GHG emission reduction approaching the ambitious Green World.\u0000 However, the main question is how gas resources can be properly delivered to satisfy a wide range of markets and usages considering that fundamental driver is the goal of reducing carbon footprint.\u0000 A methodology was developed, named Gas Master Plan (GMP), which is an integrated study with a novel view, looking to synergic opportunities among energy sources while defining economically sustainable business models and meeting Decarbonisation targets.\u0000 A Gas Master Plan is a multidisciplinary study assessing the best valorisation routes for Natural Gas resources in a specified country or geographical region. This kind of study analyses gas and energy supply/demand balance, understanding current and future markets and looks for adequate destinations, check existing infrastructures and further possible developments carried by Local Governments or private entities, identify potential gas production for all the involved resources, business modelling, understanding the benefits to the global energy transition targets that such resources could deliver and screening monetization opportunities under a strategic plan view.\u0000 Thus, a GMP is not just an analysis of upstream volumes to verify whether they match commitments and still fit in their future development plans but it is company-wide joint effort to gather ideas, proposals, topics or issues to be addressed and possible solutions.\u0000 Broadly speaking resources considered in a typical GMP would be: those under an exploration phase, those just discovered for which a proper development has to be realised, those already in production but for which new market opportunities can be scouted in order to improve their benefit on the energy transition paths while seeking further economic returns.\u0000 The primary result is to develop a strategy to optimize present production and the development and valorisation of future gas assets, identifying the related GHG profile for each opportunity, supporting the decision-making process on new/future gas initiatives with a coherent plan.\u0000 The resulting outcomes and conclusions may address specific topics on the short to medium term, like associate to a gas field the proper development project to cover gas and energy commercial demand, or set targets achievable on the medium to long term like supporting a low carbon footprint growth in the energy sector and promoting gas-based industries.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81892525","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}
Continuous fabric maintenance (FM) is crucial for uninterrupted operations on offshore oil and gas platforms. A primary FM goal is managing the onset of coating degradation across the surfaces of offshore platforms. Physical field inspection programs are required to target timely detection and grading of coating conditions. These processes are costly, time-consuming, labour-intensive, and must be conducted on-site. Moreover, the inspection findings are subjective and provide incomplete asset coverage, leading to increased risk of unplanned shutdowns. Risk reduction and increased FM efficiency is achieved using machine learning and computer vision algorithms to analyze full-facility imagery for coating degradation and subsequent ‘degree-of-rusting’ classification of equipment to industry inspection standards. Inspection data is collected for the entirety of an offshore facility using a terrestrial scanner. Coating degradation is detected across the facility using machine learning and computer vision algorithms. Additionally, the inspection data is tagged with unique piping line numbers per design, fixed equipment tags, or unique asset identification numbers. Computer vision algorithms and the detected coating degradation are subsequently used as input to determine the ‘degree-of-rusting’ throughout the facility, and coating condition status is tagged to specific piping or equipment. The degree-of-rusting condition rating follows common industry standards used by inspection engineers (e.g., ISO 4628-3, ASTM D610-01, or European Rust Scale). Atmospheric corrosion is the number one asset integrity threat to offshore platforms. Utilizing this automatic coating condition technology, a comprehensive and objective analysis of a facility's health is provided. Coating condition results are overlaid on inspection imagery for rapid visualisation. Coating condition is associated with individual instances of equipment. This allows for rapid filtering of equipment by coating condition severity, process type, equipment type, etc. Fabric maintenance efficiencies are realized by targeting decks, blocks, or areas with the highest aggregate coating degradation (on process equipment or structurally, as selected by the user) and concentrating remediation efforts on at-risk equipment. With the automated classification of degree-of-rusting, mitigation strategies that extend the life of the asset can be optimised, resulting in efficiency gains and cost savings for the facility. Conventional manual inspections and reporting of coating conditions has low objectivity and increased risk and cost when compared to the proposed method. Drawing on machine learning and computer vision techniques, this work proposes a novel workflow for automatically identifying the degree-of-rusting on assets using industry inspection standards. This contributes directly to greater risk awareness, targeted remediation strategies, improving the overall efficiency of the
{"title":"Automated Painting Survey, Degree of Rusting Classification, and Mapping with Machine Learning","authors":"Eric Ferguson, Toby Dunne, Lloyd Windrim, Suchet Bargoti, Nasir Ahsan, Waleed Altamimi","doi":"10.2118/208119-ms","DOIUrl":"https://doi.org/10.2118/208119-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Continuous fabric maintenance (FM) is crucial for uninterrupted operations on offshore oil and gas platforms. A primary FM goal is managing the onset of coating degradation across the surfaces of offshore platforms. Physical field inspection programs are required to target timely detection and grading of coating conditions. These processes are costly, time-consuming, labour-intensive, and must be conducted on-site. Moreover, the inspection findings are subjective and provide incomplete asset coverage, leading to increased risk of unplanned shutdowns. Risk reduction and increased FM efficiency is achieved using machine learning and computer vision algorithms to analyze full-facility imagery for coating degradation and subsequent ‘degree-of-rusting’ classification of equipment to industry inspection standards.\u0000 \u0000 \u0000 \u0000 Inspection data is collected for the entirety of an offshore facility using a terrestrial scanner. Coating degradation is detected across the facility using machine learning and computer vision algorithms. Additionally, the inspection data is tagged with unique piping line numbers per design, fixed equipment tags, or unique asset identification numbers. Computer vision algorithms and the detected coating degradation are subsequently used as input to determine the ‘degree-of-rusting’ throughout the facility, and coating condition status is tagged to specific piping or equipment. The degree-of-rusting condition rating follows common industry standards used by inspection engineers (e.g., ISO 4628-3, ASTM D610-01, or European Rust Scale).\u0000 \u0000 \u0000 \u0000 Atmospheric corrosion is the number one asset integrity threat to offshore platforms. Utilizing this automatic coating condition technology, a comprehensive and objective analysis of a facility's health is provided. Coating condition results are overlaid on inspection imagery for rapid visualisation. Coating condition is associated with individual instances of equipment. This allows for rapid filtering of equipment by coating condition severity, process type, equipment type, etc. Fabric maintenance efficiencies are realized by targeting decks, blocks, or areas with the highest aggregate coating degradation (on process equipment or structurally, as selected by the user) and concentrating remediation efforts on at-risk equipment. With the automated classification of degree-of-rusting, mitigation strategies that extend the life of the asset can be optimised, resulting in efficiency gains and cost savings for the facility. Conventional manual inspections and reporting of coating conditions has low objectivity and increased risk and cost when compared to the proposed method.\u0000 \u0000 \u0000 \u0000 Drawing on machine learning and computer vision techniques, this work proposes a novel workflow for automatically identifying the degree-of-rusting on assets using industry inspection standards. This contributes directly to greater risk awareness, targeted remediation strategies, improving the overall efficiency of the ","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"307 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79886430","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}
Asad Ali, Kevin Maley, Seonyeob Li, Ahmed Al Owaid, Abdullah Al Shehhi
Asset integrity management system (AIMS) consisting of risk based inspection (RBI) and inspection management system (IMS) coupled with digitized equipment records and use of inspection tablets/mobiles will make paperless system for fast and timely decisions & actions. This paper provides a roadmap for implementation of an efficient and cost effective asset integrity management system that will increase the plant reliability & availability, decrease the time and efforts required for inspection, thus ultimately reducing the associated costs of operations. In this paper, the focus is towards digitalized AIMS that should make a company move to digital transformation and enabling it to adapt to industry 4.0 technologies such as artificial intelligence, augmented reality, data analytics, machine learning etc. First step is to perform a gap assessment of existing system to compare what is currently available within organization and what is required for going fully digital for AIM. Next step is to identify software features that are required for AIM digitalization and establish them as point based rating system which are used for rating best suitable software available in the market. Unique features for RBI module, inspection management module and field interface (tablet) module are identified with appropriate weightage to influence the software selection decision. Finally, an estimation of required resources, manpower timeline is provided that will guide in all phases of the implementation. Return on investment on such projects is manifolds. The digitalized AIM will greatly reduce the cost of day to to asset integrity management operations as it will no longer be needed to use multiple paper based reports and separate systems for RBI and IMS functions. Use of field tablet/mobile with possibility of artificial intelligence tools, will significantly reduce the time required for inspectors to do the on site inspection/testing & reporting. Interfacing of digitalized system with ERP/CMMS will automate the work order/notification system. Thus it will reduce an overall effort both in terms of time & money. The roadmap for digitalization of AIMS system will help any organization to make its AIMS digital and achieve the benefits of such system. The methodology provided is unique and can be adopted as best practices by the industry for digitally transforming the AIMS.
{"title":"Roadmap for Digitalized Asset Integrity Management System","authors":"Asad Ali, Kevin Maley, Seonyeob Li, Ahmed Al Owaid, Abdullah Al Shehhi","doi":"10.2118/208117-ms","DOIUrl":"https://doi.org/10.2118/208117-ms","url":null,"abstract":"\u0000 Asset integrity management system (AIMS) consisting of risk based inspection (RBI) and inspection management system (IMS) coupled with digitized equipment records and use of inspection tablets/mobiles will make paperless system for fast and timely decisions & actions. This paper provides a roadmap for implementation of an efficient and cost effective asset integrity management system that will increase the plant reliability & availability, decrease the time and efforts required for inspection, thus ultimately reducing the associated costs of operations. In this paper, the focus is towards digitalized AIMS that should make a company move to digital transformation and enabling it to adapt to industry 4.0 technologies such as artificial intelligence, augmented reality, data analytics, machine learning etc.\u0000 First step is to perform a gap assessment of existing system to compare what is currently available within organization and what is required for going fully digital for AIM. Next step is to identify software features that are required for AIM digitalization and establish them as point based rating system which are used for rating best suitable software available in the market. Unique features for RBI module, inspection management module and field interface (tablet) module are identified with appropriate weightage to influence the software selection decision. Finally, an estimation of required resources, manpower timeline is provided that will guide in all phases of the implementation.\u0000 Return on investment on such projects is manifolds. The digitalized AIM will greatly reduce the cost of day to to asset integrity management operations as it will no longer be needed to use multiple paper based reports and separate systems for RBI and IMS functions. Use of field tablet/mobile with possibility of artificial intelligence tools, will significantly reduce the time required for inspectors to do the on site inspection/testing & reporting. Interfacing of digitalized system with ERP/CMMS will automate the work order/notification system. Thus it will reduce an overall effort both in terms of time & money.\u0000 The roadmap for digitalization of AIMS system will help any organization to make its AIMS digital and achieve the benefits of such system. The methodology provided is unique and can be adopted as best practices by the industry for digitally transforming the AIMS.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90641522","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. Konwar, Bader Alhammadi, Ebrahim Alawainati, Ajithkumar Panicker
The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation. Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir. Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area. Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injecti
{"title":"A Holistic Study on Performance Evaluation of Horizontal Wells and its Implications on Tight Spacing Drilling Strategy in Mauddud Reservoir","authors":"L. Konwar, Bader Alhammadi, Ebrahim Alawainati, Ajithkumar Panicker","doi":"10.2118/207972-ms","DOIUrl":"https://doi.org/10.2118/207972-ms","url":null,"abstract":"\u0000 The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation.\u0000 Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir.\u0000 Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area.\u0000 Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injecti","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"122 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86336496","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}
Brett Bouldin, Ahmed Alshmakhy, Ahmed Khaled Bazuhair, Muzoon Hasan Alzaabi, Jarl André Fellinghaug
Downhole wireless communication in the form of mud pulse telemetry enabled directional drilling over the past 60 years and has been hugely successful. Technologies like Measurement While Drilling (MWD), Logging While Drilling (LWD), and Geosteering would simply not exist without it. But in the Production and Producing end of the business, applications for downhole wireless communication have been less clear, especially where long distances and long-term monitoring are concerned. Several wireless technologies are in use today for long-term production applications. Electromagnetic (EM), acoustic, and pressure pulse telemetries are finding application as wireless production gauges, drill stem test tools, and drilling alternatives to pressure pulse. But the large-scale vision of, "Breaking the Wire!" in production wells has not yet occurred. Permanent Downhole Gauges (PDG) with an umbilical to surface are still the product of choice for long-term production monitoring. A history of wireless approaches in production applications will be given and the different methods used in the industry will be explained. A comparison and contrast of wireless telemetry methods will be explored, explained, and evaluated. Advantages and disadvantages will be listed for each approach. A ranking system will be employed to illustrate the evaluation results of the different wireless telemetry methods. New variants for wireless telemetry, power supplies, and measurement methods will be proposed. Preferred applications for each gauge type will be given. Downhole gauges can be improved by integrating pressure pulse, a downhole power generator, and downhole flow rate measurement into a single unit. The overall size can be ten times shorter than existing systems while still generating a larger wireless signal. Such a system would make wireless downhole gauges much more practical and should significantly increase their uptake in the industry. Real-time measurement of downhole pressure and downhole flow rate transforms the accuracy and effectiveness of Pressure Transient Analysis (PTA). Better reservoir understanding can be gained by using only drawdown tests, without shutting in the well. Smaller tools are generally more cost effective.
{"title":"A Review of Downhole Wireless Technologies and Improvements","authors":"Brett Bouldin, Ahmed Alshmakhy, Ahmed Khaled Bazuhair, Muzoon Hasan Alzaabi, Jarl André Fellinghaug","doi":"10.2118/207466-ms","DOIUrl":"https://doi.org/10.2118/207466-ms","url":null,"abstract":"\u0000 Downhole wireless communication in the form of mud pulse telemetry enabled directional drilling over the past 60 years and has been hugely successful. Technologies like Measurement While Drilling (MWD), Logging While Drilling (LWD), and Geosteering would simply not exist without it. But in the Production and Producing end of the business, applications for downhole wireless communication have been less clear, especially where long distances and long-term monitoring are concerned. Several wireless technologies are in use today for long-term production applications. Electromagnetic (EM), acoustic, and pressure pulse telemetries are finding application as wireless production gauges, drill stem test tools, and drilling alternatives to pressure pulse. But the large-scale vision of, \"Breaking the Wire!\" in production wells has not yet occurred. Permanent Downhole Gauges (PDG) with an umbilical to surface are still the product of choice for long-term production monitoring. A history of wireless approaches in production applications will be given and the different methods used in the industry will be explained. A comparison and contrast of wireless telemetry methods will be explored, explained, and evaluated. Advantages and disadvantages will be listed for each approach. A ranking system will be employed to illustrate the evaluation results of the different wireless telemetry methods. New variants for wireless telemetry, power supplies, and measurement methods will be proposed. Preferred applications for each gauge type will be given. Downhole gauges can be improved by integrating pressure pulse, a downhole power generator, and downhole flow rate measurement into a single unit. The overall size can be ten times shorter than existing systems while still generating a larger wireless signal. Such a system would make wireless downhole gauges much more practical and should significantly increase their uptake in the industry. Real-time measurement of downhole pressure and downhole flow rate transforms the accuracy and effectiveness of Pressure Transient Analysis (PTA). Better reservoir understanding can be gained by using only drawdown tests, without shutting in the well. Smaller tools are generally more cost effective.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"1993 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82744724","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}
Between January 2015 and early 2021, about 76 of the approximately 2,160 small-to-medium independent companies in the tight oil sector filed for Chapter 11 protection. These filings mostly occurred in 2016 and 2019. These companies were negatively impacted by the low oil prices in these years owing to their lack of financial discipline and poor financial risk assessments. As a result, they declared bankruptcy. News outlets tend to amplify bankruptcy filing announcements in the oil and gas sector. Nevertheless, our analysis shows that these bankruptcy declarations do not imply that the shale oil and gas sector collapsed. The ailing operators in 2019 were responsible for about 8.5% of total tight oil production in the United States. This volume did not disappear from the market because of the Chapter 11 provisions. Instead, the ailing operators either became more efficient and financially disciplined or transferred their assets to more efficient operators. Over 33 independent companies have ultimately emerged from bankruptcy. These companies successfully reached debt restructuring resolutions with their investors, transferred equity ownership to investors or sold or leased their assets to other operators. Companies that failed to adapt exited the oil market through either liquidation or acquisitions by other companies. Going forward, more consolidations are expected in the shale industry, especially among medium-to-large independent producers that accrued large debts in previous years. These producers will either enter bankruptcy owing to financial headwinds and market uncertainty or be acquired by larger companies. This analysis shows that bankruptcies in the tight oil sector may be viewed positively or negatively depending on the situation and perspective. Bankruptcies do incur different types of costs and losses to many parties. However, consolidation that improves the efficiency of resource allocation can be viewed as a positive sign for the economy. Operators, equity owners, debtors-in-possession and the oil and gas industry can therefore view bankruptcies within the industry differently.
{"title":"How Do Bankruptcies in the Shale Sector Induce Operators to Focus on Value Creation?","authors":"Majed Ayed Alsuwailem, Malik Selemankhel","doi":"10.2118/207910-ms","DOIUrl":"https://doi.org/10.2118/207910-ms","url":null,"abstract":"\u0000 Between January 2015 and early 2021, about 76 of the approximately 2,160 small-to-medium independent companies in the tight oil sector filed for Chapter 11 protection. These filings mostly occurred in 2016 and 2019. These companies were negatively impacted by the low oil prices in these years owing to their lack of financial discipline and poor financial risk assessments. As a result, they declared bankruptcy.\u0000 News outlets tend to amplify bankruptcy filing announcements in the oil and gas sector. Nevertheless, our analysis shows that these bankruptcy declarations do not imply that the shale oil and gas sector collapsed. The ailing operators in 2019 were responsible for about 8.5% of total tight oil production in the United States. This volume did not disappear from the market because of the Chapter 11 provisions. Instead, the ailing operators either became more efficient and financially disciplined or transferred their assets to more efficient operators.\u0000 Over 33 independent companies have ultimately emerged from bankruptcy. These companies successfully reached debt restructuring resolutions with their investors, transferred equity ownership to investors or sold or leased their assets to other operators. Companies that failed to adapt exited the oil market through either liquidation or acquisitions by other companies.\u0000 Going forward, more consolidations are expected in the shale industry, especially among medium-to-large independent producers that accrued large debts in previous years. These producers will either enter bankruptcy owing to financial headwinds and market uncertainty or be acquired by larger companies. This analysis shows that bankruptcies in the tight oil sector may be viewed positively or negatively depending on the situation and perspective. Bankruptcies do incur different types of costs and losses to many parties. However, consolidation that improves the efficiency of resource allocation can be viewed as a positive sign for the economy. Operators, equity owners, debtors-in-possession and the oil and gas industry can therefore view bankruptcies within the industry differently.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73212555","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}
During the past decade, drilling automation systems have been an attractive target for a lot of operating and drilling companies. Despite progress in automation in various industries, like mining and downstream, the drilling industry has lagged far behind in the real application of autonomous technologies implementation. This can be attributed to harsh environment, high level of uncertainty in input data, and that majority of stock is legacy drilling rigs, resulting in capital intensive implementations. In the past years there have been several attempts to create fully automated rigs, that includes surface automation and drilling automation. Such solutions are very attractive, because they allow people to move out of hazardous zones and, at the same time, improve performance. However, the main deficiency of such an approach is the very high capital investment required for development of highly bespoke rigs (Slagmulder 2016). And in the current business environment, with high volatility in oil and gas prices, plus the huge negative effect of the Covid-19 crisis on the world's economic situation, it would be hard to imagine that there are a lot of companies willing to make such a risky investment. In addition to this, due to the lack of demand, the market is full of relatively new, high-performance rigs. Taking all these into account, the obvious question is whether it makes sense to invest money and time into the development of drilling automation. The answer should be yes, for three substantial reasons:Automation improves personal safety, by moving people out of danger zones;Automation improves process safety, by transferring execution from person to machine, which reduces the risk of human error;Automation improves efficiency by bringing consistency to drilling and through the use of self-learning algorithms, which allow machines to drill each successive well better than the previous. This paper will not look into surface automation, such as pipe-handling, chemical and mud handling on site. The paper is focused on the subsurface, namely on the drilling automation process, the challenges that need to be overcome to deploy a vendor agnostic system on a majority of existing rigs. A vendor agnostic system is a modification of an operator's autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs, and have minimum footprint on the rigs for operational use. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance
{"title":"Step Change Transformation of Legacy Rigs to Autonomous Drilling Rigs","authors":"S. Ziatdinov, Titto Thomas Philip","doi":"10.2118/207551-ms","DOIUrl":"https://doi.org/10.2118/207551-ms","url":null,"abstract":"\u0000 During the past decade, drilling automation systems have been an attractive target for a lot of operating and drilling companies. Despite progress in automation in various industries, like mining and downstream, the drilling industry has lagged far behind in the real application of autonomous technologies implementation. This can be attributed to harsh environment, high level of uncertainty in input data, and that majority of stock is legacy drilling rigs, resulting in capital intensive implementations. In the past years there have been several attempts to create fully automated rigs, that includes surface automation and drilling automation. Such solutions are very attractive, because they allow people to move out of hazardous zones and, at the same time, improve performance. However, the main deficiency of such an approach is the very high capital investment required for development of highly bespoke rigs (Slagmulder 2016). And in the current business environment, with high volatility in oil and gas prices, plus the huge negative effect of the Covid-19 crisis on the world's economic situation, it would be hard to imagine that there are a lot of companies willing to make such a risky investment. In addition to this, due to the lack of demand, the market is full of relatively new, high-performance rigs.\u0000 Taking all these into account, the obvious question is whether it makes sense to invest money and time into the development of drilling automation. The answer should be yes, for three substantial reasons:Automation improves personal safety, by moving people out of danger zones;Automation improves process safety, by transferring execution from person to machine, which reduces the risk of human error;Automation improves efficiency by bringing consistency to drilling and through the use of self-learning algorithms, which allow machines to drill each successive well better than the previous.\u0000 This paper will not look into surface automation, such as pipe-handling, chemical and mud handling on site. The paper is focused on the subsurface, namely on the drilling automation process, the challenges that need to be overcome to deploy a vendor agnostic system on a majority of existing rigs.\u0000 A vendor agnostic system is a modification of an operator's autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs, and have minimum footprint on the rigs for operational use. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"85 6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77074977","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}
Hilal Mudhafar Al Riyami, Hilal Mohammed Al Sheibani, Hamed Ali Al Subhi, Hussain Taqi Al Ajmi, Zeinab Youssef Zohny, Azzan Qais Al Kindy
Production performance forecasting is considered as one of the most challenging and time consuming tasks in petroleum engineering disciplines, it has important implications on decision-making, planning production and processing of facilities. In Petroleum Development Oman (PDO), which is the major petroleum company in Oman, production forecast provides a technical input basis for the economic decisions throughout the exploration and production lifecycle. Reservoir engineers spend more than 250 days per year to complete this process. PDO Forecast Management System (FMS) was introduced to transform the conventional forecasting of gas production. Employing the latest state-of-the-art technologies in the field of data management and machine learning (ML), PDO FMS aims at optimizing and automating the process of capturing, reporting, and predicting hydrocarbon production. This new system covers the full forecast processes including long and short-term forecasting for gas, condensate, and water production. As a pilot project, PDO FMS was deployed on a cluster of 272 wells and relied on agile project management approach to realize the benefits during the development phase. Deployment of the new system resulted in a significant reduction of the forecasting time, optimization of manpower and forecasting accuracy.
{"title":"Petroleum Development Oman Forecasting Management System","authors":"Hilal Mudhafar Al Riyami, Hilal Mohammed Al Sheibani, Hamed Ali Al Subhi, Hussain Taqi Al Ajmi, Zeinab Youssef Zohny, Azzan Qais Al Kindy","doi":"10.2118/208108-ms","DOIUrl":"https://doi.org/10.2118/208108-ms","url":null,"abstract":"\u0000 Production performance forecasting is considered as one of the most challenging and time consuming tasks in petroleum engineering disciplines, it has important implications on decision-making, planning production and processing of facilities. In Petroleum Development Oman (PDO), which is the major petroleum company in Oman, production forecast provides a technical input basis for the economic decisions throughout the exploration and production lifecycle. Reservoir engineers spend more than 250 days per year to complete this process. PDO Forecast Management System (FMS) was introduced to transform the conventional forecasting of gas production. Employing the latest state-of-the-art technologies in the field of data management and machine learning (ML), PDO FMS aims at optimizing and automating the process of capturing, reporting, and predicting hydrocarbon production. This new system covers the full forecast processes including long and short-term forecasting for gas, condensate, and water production. As a pilot project, PDO FMS was deployed on a cluster of 272 wells and relied on agile project management approach to realize the benefits during the development phase. Deployment of the new system resulted in a significant reduction of the forecasting time, optimization of manpower and forecasting accuracy.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77190496","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}
Ali Salim Al Sheidi, Hatim Abdul Raheem Al Balushi, Zahra Al Rawahi, Yahya Hilal Al Amri, D. Mansur
This paper discusses the journey of finding alternate solution for having to run the Expandable Liners operations in the Fahud field which is already one of the most operationally challenging fields to drill in Petroleum Development Oman (PDO), due to the presence of a gas cap in highly fractured and depleted limestone formations with total losses and the need for dynamic annulus fill to maintain primary well control. In Fahud field, there is a highly reactive shale formation within reservoir limestone formation. Due to high likelihood of total losses, this shale formation caused bore hole instability challenges while drilling. And with more depletion took place, the challenges became more frequently to occurred. In 2001, expandable tubular liner was introduced to address these bore hole instability challenges while drilling highly reactive shale formation under total losses in the 8-1/2″ section. The use of expandable technology was sustained over the years in delivering all wells drilled to traverse this reactive shale column. Previously before 2001, wells used to have fat well design by installations of extra casing to cover the formations and problematic zones. Also, Fahud field was not depleted as it is now, and the problematic shale zone used to drill by normal conventional way without any issue using inhibition frilling fluid. Petroleum Development Oman (PDO) identified expandable liner as a preferred alternative to ‘Fat’ well design. The ‘Fat’ well design would have a large hole size through potential loss zones, resulting in unmanageable volumes of water being required. Expandable liber was fast-tracked - various technical options were considered by PDO with expandable liner technology being identified as the best solution to address the problem of the shale column. However, the deployment of expandable tubular liner technology supported to drill & deliver wells but also has its associated challenges incurring additional time and cost with reasonable installation and low operations success rate due to number of operational steps required prior and after the expandable liner. Adding to that, all the challenges associated with each step. The installation of the expandable liner required eight operational steps with multiple trips to under-ream, install and expand, cement, caliper log and drill through the liner which increased the probability of something going wrong due to mainly the challenging well profile and multiple operations steps. The expandable liners technology was required when the target formation was below the reactive shale interval. The team carried out a study of previous deployments with the intention of identifying well planning and operational contributors to the installation difficulties and operations failures, with a view of eliminating the need for installing the expandable liner and drilling the well to the desired landing point at designed section total depth. Most of the unsuccessful installation rates wer
{"title":"Step Change in Delivering High Fracture Wells by Eliminating Expandable Liner","authors":"Ali Salim Al Sheidi, Hatim Abdul Raheem Al Balushi, Zahra Al Rawahi, Yahya Hilal Al Amri, D. Mansur","doi":"10.2118/207934-ms","DOIUrl":"https://doi.org/10.2118/207934-ms","url":null,"abstract":"\u0000 This paper discusses the journey of finding alternate solution for having to run the Expandable Liners operations in the Fahud field which is already one of the most operationally challenging fields to drill in Petroleum Development Oman (PDO), due to the presence of a gas cap in highly fractured and depleted limestone formations with total losses and the need for dynamic annulus fill to maintain primary well control.\u0000 In Fahud field, there is a highly reactive shale formation within reservoir limestone formation. Due to high likelihood of total losses, this shale formation caused bore hole instability challenges while drilling. And with more depletion took place, the challenges became more frequently to occurred.\u0000 In 2001, expandable tubular liner was introduced to address these bore hole instability challenges while drilling highly reactive shale formation under total losses in the 8-1/2″ section. The use of expandable technology was sustained over the years in delivering all wells drilled to traverse this reactive shale column. Previously before 2001, wells used to have fat well design by installations of extra casing to cover the formations and problematic zones. Also, Fahud field was not depleted as it is now, and the problematic shale zone used to drill by normal conventional way without any issue using inhibition frilling fluid. Petroleum Development Oman (PDO) identified expandable liner as a preferred alternative to ‘Fat’ well design. The ‘Fat’ well design would have a large hole size through potential loss zones, resulting in unmanageable volumes of water being required. Expandable liber was fast-tracked - various technical options were considered by PDO with expandable liner technology being identified as the best solution to address the problem of the shale column.\u0000 However, the deployment of expandable tubular liner technology supported to drill & deliver wells but also has its associated challenges incurring additional time and cost with reasonable installation and low operations success rate due to number of operational steps required prior and after the expandable liner. Adding to that, all the challenges associated with each step. The installation of the expandable liner required eight operational steps with multiple trips to under-ream, install and expand, cement, caliper log and drill through the liner which increased the probability of something going wrong due to mainly the challenging well profile and multiple operations steps. The expandable liners technology was required when the target formation was below the reactive shale interval.\u0000 The team carried out a study of previous deployments with the intention of identifying well planning and operational contributors to the installation difficulties and operations failures, with a view of eliminating the need for installing the expandable liner and drilling the well to the desired landing point at designed section total depth.\u0000 Most of the unsuccessful installation rates wer","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77743415","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}
At a subsurface level, controlling uneven production and early gas breakthrough are big challenges. It is very difficult to achieve the target production while preventing unnecessary flaring from high gas to oil ratio (GOR) wells. To keep the associated gas within surface compression capacity, the High GOR wells are shut in or partially choked by production programmers through a manual work-process, which doesn't always give optimum results. PDO developed a control solution to ensure produced gas always remains within surface compression capacity while ensuring maximum production. The solution achieves this by continuously monitoring flaring and choking the high GOR wells whenever needed. It does this sequentially from highest to lowest GOR wells choking is done to an optimum level by controlling its flow line pressure above certain target. The concept revolves around automating production programmer's task and optimizing it via continuous monitoring and control in DCS, which allows wells to deliver the full potential up to the surface facility constraints with reduced operator intervention. This novel idea is to integrate subsurface and surface facility Optimization via well control. This was implemented in two of the assets in PDO where frequent flaring was identified. Both facilities have limited compression capacity and number of high GOR wells out of several Gas Oil Gravity Drainage (GOGD) producer wells. In order to achieve the goal of "Zero" flaring, the wells are choked in order from highest to lowest GOR, automatically, up to the optimum limit set by either their respective flow line pressures or to defined lower optimum limit, and optimize the production by opening the wells up to its optimum target, when there is no flare. The similar concept is now being replicated in other assets following a LEAN approach.
{"title":"Well Automation Based on Flaring","authors":"Surabhi Patni, Vinay Kumar Sharma","doi":"10.2118/207555-ms","DOIUrl":"https://doi.org/10.2118/207555-ms","url":null,"abstract":"\u0000 At a subsurface level, controlling uneven production and early gas breakthrough are big challenges. It is very difficult to achieve the target production while preventing unnecessary flaring from high gas to oil ratio (GOR) wells. To keep the associated gas within surface compression capacity, the High GOR wells are shut in or partially choked by production programmers through a manual work-process, which doesn't always give optimum results.\u0000 PDO developed a control solution to ensure produced gas always remains within surface compression capacity while ensuring maximum production. The solution achieves this by continuously monitoring flaring and choking the high GOR wells whenever needed. It does this sequentially from highest to lowest GOR wells choking is done to an optimum level by controlling its flow line pressure above certain target.\u0000 The concept revolves around automating production programmer's task and optimizing it via continuous monitoring and control in DCS, which allows wells to deliver the full potential up to the surface facility constraints with reduced operator intervention.\u0000 This novel idea is to integrate subsurface and surface facility Optimization via well control. This was implemented in two of the assets in PDO where frequent flaring was identified. Both facilities have limited compression capacity and number of high GOR wells out of several Gas Oil Gravity Drainage (GOGD) producer wells. In order to achieve the goal of \"Zero\" flaring, the wells are choked in order from highest to lowest GOR, automatically, up to the optimum limit set by either their respective flow line pressures or to defined lower optimum limit, and optimize the production by opening the wells up to its optimum target, when there is no flare. The similar concept is now being replicated in other assets following a LEAN approach.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"14 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82878687","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：