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}
If we learned anything from the year 2020, it is that we need to be more prepared for the unexpected. We need to be working to enable our business to be more resilient in the face of unexpected challenges. We strongly believe that for the industrial sector, the most effective way to enable resiliency is to ensure you have integrity in your operational technology (OT). The objective of this paper is to identify and manage the risk that arose from managing plants remotely. As a result of COVID-19, people started working and managing from home. While this needed to be done to keep businesses running, many risks were introduced as well. How to manage them effectively to reduce cyber risk to an acceptable level will be discussed. Industrial frameworks to identify security gaps, and thus risk, were considered, such as ISA-99/IEC-62443, NIST, ISO-27001, and Top CIS controls. New practices critical infrastructure followed to reduce infection rates were identified from interviews and surveys conducted by PAS, part of Hexagon, of our customers who work with critical infrastructure. These new practices were then compared to the industrial risk management framework to identify the severity of the threats. Once these were identified, mitigation plans were recommended to reduce the risk to an acceptable level. Because of this rapid shift to run the plant remotely, there was an over-provisioning of access in the early stages of the pandemic – i.e., giving more direct access to the industrial control system environment. This was not wise from a security standpoint, but the priority was to keep businesses up and running, so they were ready to take that risk. Now that some organizations have decided to continue with remote work, it is imperative to verify all remote access considers the least privileged access concept. Remote access is like a bridge that bypasses all the controls implemented. Having a remote access vulnerability will help bad actors break into the network and cause catastrophic damage. Though this paper focuses on remote access risk introduced by the COVID-19 pandemic, you can apply the findings to all remote access into critical infrastructure.
{"title":"Covid Best Practices for Cyber Risk Management","authors":"Syed M. Belal, Md. Abdur Rahman","doi":"10.2118/208113-ms","DOIUrl":"https://doi.org/10.2118/208113-ms","url":null,"abstract":"\u0000 If we learned anything from the year 2020, it is that we need to be more prepared for the unexpected. We need to be working to enable our business to be more resilient in the face of unexpected challenges. We strongly believe that for the industrial sector, the most effective way to enable resiliency is to ensure you have integrity in your operational technology (OT).\u0000 The objective of this paper is to identify and manage the risk that arose from managing plants remotely. As a result of COVID-19, people started working and managing from home. While this needed to be done to keep businesses running, many risks were introduced as well. How to manage them effectively to reduce cyber risk to an acceptable level will be discussed.\u0000 Industrial frameworks to identify security gaps, and thus risk, were considered, such as ISA-99/IEC-62443, NIST, ISO-27001, and Top CIS controls. New practices critical infrastructure followed to reduce infection rates were identified from interviews and surveys conducted by PAS, part of Hexagon, of our customers who work with critical infrastructure. These new practices were then compared to the industrial risk management framework to identify the severity of the threats. Once these were identified, mitigation plans were recommended to reduce the risk to an acceptable level.\u0000 Because of this rapid shift to run the plant remotely, there was an over-provisioning of access in the early stages of the pandemic – i.e., giving more direct access to the industrial control system environment. This was not wise from a security standpoint, but the priority was to keep businesses up and running, so they were ready to take that risk.\u0000 Now that some organizations have decided to continue with remote work, it is imperative to verify all remote access considers the least privileged access concept.\u0000 Remote access is like a bridge that bypasses all the controls implemented. Having a remote access vulnerability will help bad actors break into the network and cause catastrophic damage. Though this paper focuses on remote access risk introduced by the COVID-19 pandemic, you can apply the findings to all remote access into critical infrastructure.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84266448","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}
M. Battashi, R. Farajzadeh, A. Bimani, M. Abri, R. Mjeni, V. Karpan, A. Fadili, J. van Wunnik
This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones. It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.
{"title":"Insights into Oil Recovery Mechanism by Nothing-Alternating-Polymer NAP Concept","authors":"M. Battashi, R. Farajzadeh, A. Bimani, M. Abri, R. Mjeni, V. Karpan, A. Fadili, J. van Wunnik","doi":"10.2118/207743-ms","DOIUrl":"https://doi.org/10.2118/207743-ms","url":null,"abstract":"\u0000 This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones.\u0000 It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87053165","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}
New wells are continuously drilled to improve the recovery of shale gas reservoirs. Production processes of parent wells will induce stress changes in the reservoir and then affect infill wells’ fracturing design. In this paper, we employed an integrated numerical method to simulate the hydraulic fracturing and production processes with single one method, thus the fracturing scheme of the infill well can be optimized. The integrated numerical method is based on the finite element method (FEM), which is named as the discontinuous discrete fracture method (DDFM). The DDFM can be used with conventional finite element mesh, which is perfectly compatible with the discrete fracture model (DFM). The fully coupled solution of DDFM is validated by two problems, including Mandel problem's analytical solution and the numerical solutions of the single fracture propagation. When predict the shale gas production, a new diffusion equation is modified to describe the shale gas flow, and the simulation results showed a good agreement with the field data. At last, this paper takes an infill well construction in a shale gas reservoir in south China as an example. The hydraulic fractures of parent wells are interpreted from micro-seismic data and described with DFM to reduce the computational cost. Then the infill well's hydraulic fractures are described using DDFM. After simulating the production process of two parent wells, we get the current formation pressure and stress state. Aims at obtaining the maximum profit of the whole well region, by comparing the gas production of different fracturing schemes, we can choose the optimal fracturing scheme of the infill well.
{"title":"The Optimization of Infill Well Fracturing Using an Integrated Numerical Simulation Method of Fracturing and Production Processes","authors":"S. Wei, Yan Jin, Xing-gang Liu, Yang Xia","doi":"10.2118/207978-ms","DOIUrl":"https://doi.org/10.2118/207978-ms","url":null,"abstract":"\u0000 New wells are continuously drilled to improve the recovery of shale gas reservoirs. Production processes of parent wells will induce stress changes in the reservoir and then affect infill wells’ fracturing design. In this paper, we employed an integrated numerical method to simulate the hydraulic fracturing and production processes with single one method, thus the fracturing scheme of the infill well can be optimized. The integrated numerical method is based on the finite element method (FEM), which is named as the discontinuous discrete fracture method (DDFM). The DDFM can be used with conventional finite element mesh, which is perfectly compatible with the discrete fracture model (DFM). The fully coupled solution of DDFM is validated by two problems, including Mandel problem's analytical solution and the numerical solutions of the single fracture propagation. When predict the shale gas production, a new diffusion equation is modified to describe the shale gas flow, and the simulation results showed a good agreement with the field data. At last, this paper takes an infill well construction in a shale gas reservoir in south China as an example. The hydraulic fractures of parent wells are interpreted from micro-seismic data and described with DFM to reduce the computational cost. Then the infill well's hydraulic fractures are described using DDFM. After simulating the production process of two parent wells, we get the current formation pressure and stress state. Aims at obtaining the maximum profit of the whole well region, by comparing the gas production of different fracturing schemes, we can choose the optimal fracturing scheme of the infill well.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86296344","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}
Vitaly Virt, V. Kosolapov, V. Nagimov, A. Salamatin, Y. Fesina, A. Alekseeva, Yu.I. Yakhina, E. Skutina
Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.
{"title":"Individual Fracture Efficiency Monitoring in Horizontal Wells by Using a New 3d Fine-Grid Temperature Modelling","authors":"Vitaly Virt, V. Kosolapov, V. Nagimov, A. Salamatin, Y. Fesina, A. Alekseeva, Yu.I. Yakhina, E. Skutina","doi":"10.2118/207237-ms","DOIUrl":"https://doi.org/10.2118/207237-ms","url":null,"abstract":"\u0000 Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81558350","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}
Thaer I. Ismail, E. Al-Shalabi, M. Bedewi, W. Alameri
Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance. This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery. The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.
{"title":"Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model","authors":"Thaer I. Ismail, E. Al-Shalabi, M. Bedewi, W. Alameri","doi":"10.2118/207449-ms","DOIUrl":"https://doi.org/10.2118/207449-ms","url":null,"abstract":"\u0000 Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance.\u0000 This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery.\u0000 The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84213789","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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