For drilling contractors, the moment of truth is the operations at the site. If the technician at the site encounters a problem he can't solve, then everything stops. The team has to wait for a subject matter expert (SME) to arrive at the site to diagnose rectify the problem. Such process of SME mobilization and till that time Non-Productive Time (NPT) results in loss of hundreds of thousands of dollars. Hence the key challenge is converting the Sparse to Adequate availability of Right Knowledge at Right Time at Right Place, for the support of technicians. This paper is focused on the approach of moving from Hand Held devices to Hands-Free environment at sites and connecting local/global support to site support systems, to reduce cost, improve HSE and enhance operational performance. The augmented reality technology-enabled, smart glass laced headsets are rugged, zone 1 certified, and are voice-operated which are better than smart tablets which were considered during Technology Qualification Process. Evaluation criteria were: 1. Availability and follow up of the digital work instruction while operating. Moreover, not missing a single step of work instruction while inspection or maintenance continues was noted carefully. 2. Reduced travel/accommodation cost : Normally at the time of shutdown, the rig crew contacts subject matter experts (SME) and (at times) in turn the SME contacts the OEM support team to mobilize service engineers globally. 3. Response time improvement-Availability of support by SME right at the time of need results from better response time to diagnose and fix the issue at hand. Call logging till final resolution process improvement is considered an important metric. Travel restrictions imposed by Covid-19, are also being addressed through the distanced inspection. A hands-free environment is compared vis a vis handheld device. Better training and knowledge transfer are achieved through better communication methods and this goes better with learning by doing. Subsequent text (NLP-speech to text) analysis is planned through deep learning models to derive related predictions. Sparse to Adequate availability of support to rig staff with Right Knowledge at Right Place at Right Time is the key outcome of this Proof of Value project.
对于钻井承包商来说，关键时刻是现场作业。如果现场的技术人员遇到了他无法解决的问题，那么一切都会停止。团队必须等待主题专家(SME)到达现场诊断并纠正问题。中小企业的这种动员和非生产时间(NPT)的过程造成了数十万美元的损失。因此，关键的挑战是将稀疏转换为适当的知识在适当的时间和地点的充分可用性，以支持技术人员。本文的重点是在现场从手持设备转向免提环境，并将本地/全球支持连接到现场支持系统，以降低成本，改善HSE并提高运营绩效。增强现实技术支持的智能玻璃耳机坚固耐用，经过1区认证，并且是语音操作的，比技术认证过程中考虑的智能平板电脑更好。评价标准为:1。操作过程中数字作业指导书的有效性和跟踪。此外，在检查或维修继续进行时，没有遗漏任何一步的工作指导。2. 减少差旅/住宿成本:通常在停工时，钻井人员会联系主题专家(SME)， SME有时会联系OEM支持团队，在全球范围内动员服务工程师。3.响应时间的改进——SME在需要时提供的支持的可用性来自于更好的响应时间，以诊断和修复手头的问题。呼叫记录直到最终解决过程的改进被认为是一个重要的指标。新冠肺炎实施的旅行限制也正在通过远程检查得到解决。将免提环境与手持设备进行比较。更好的培训和知识转移是通过更好的沟通方法实现的，这与边做边学的效果更好。随后的文本(NLP-speech - to - text)分析计划通过深度学习模型得出相关预测。在正确的时间，在正确的地点，为拥有正确知识的钻井人员提供足够的支持是这个价值证明项目的关键成果。
{"title":"Digitally Distanced Inspection & Maintenance at Drilling Rigs : Applied Augmented Reality","authors":"D. Dash, Dileep Chandran Nair, Srinivas Potluri","doi":"10.2118/207284-ms","DOIUrl":"https://doi.org/10.2118/207284-ms","url":null,"abstract":"\u0000 For drilling contractors, the moment of truth is the operations at the site. If the technician at the site encounters a problem he can't solve, then everything stops. The team has to wait for a subject matter expert (SME) to arrive at the site to diagnose rectify the problem. Such process of SME mobilization and till that time Non-Productive Time (NPT) results in loss of hundreds of thousands of dollars. Hence the key challenge is converting the Sparse to Adequate availability of Right Knowledge at Right Time at Right Place, for the support of technicians.\u0000 This paper is focused on the approach of moving from Hand Held devices to Hands-Free environment at sites and connecting local/global support to site support systems, to reduce cost, improve HSE and enhance operational performance. The augmented reality technology-enabled, smart glass laced headsets are rugged, zone 1 certified, and are voice-operated which are better than smart tablets which were considered during Technology Qualification Process. Evaluation criteria were: 1. Availability and follow up of the digital work instruction while operating. Moreover, not missing a single step of work instruction while inspection or maintenance continues was noted carefully. 2. Reduced travel/accommodation cost : Normally at the time of shutdown, the rig crew contacts subject matter experts (SME) and (at times) in turn the SME contacts the OEM support team to mobilize service engineers globally. 3. Response time improvement-Availability of support by SME right at the time of need results from better response time to diagnose and fix the issue at hand. Call logging till final resolution process improvement is considered an important metric. Travel restrictions imposed by Covid-19, are also being addressed through the distanced inspection. A hands-free environment is compared vis a vis handheld device. Better training and knowledge transfer are achieved through better communication methods and this goes better with learning by doing. Subsequent text (NLP-speech to text) analysis is planned through deep learning models to derive related predictions. Sparse to Adequate availability of support to rig staff with Right Knowledge at Right Place at Right Time is the key outcome of this Proof of Value project.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"26 10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82698105","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}
Abdulsallam Al-Mashrafi, M. Fani, F. Asfand, M. Amani, M. Assadi, Nader Mosavat
The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location. Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased. In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method. The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.
{"title":"Downhole Steam Generation for Green Heavy Oil Recovery","authors":"Abdulsallam Al-Mashrafi, M. Fani, F. Asfand, M. Amani, M. Assadi, Nader Mosavat","doi":"10.2118/207597-ms","DOIUrl":"https://doi.org/10.2118/207597-ms","url":null,"abstract":"\u0000 The ultimate target of heavy oil recovery is to enhance oil mobility by transferring steam's thermal energy to the oil phase, incrementing its temperature, and reducing heavy oil's viscosity. While the various types of steam floods such as Cyclic Steam Injection (CSI) and Steam-Assisted Gravity Drainage (SAGD) are widely used worldwide, they have certain limitations that need further improvements. Notably, in surface steam generation systems, downhole steam quality is around 70% which means that 30% of latent heat is lost while steam travels from the surface to the pre-determined downhole location.\u0000 Downhole steam generation (DHSG) can be a viable alternative for the surface steam injection in which steam will be generated downhole instead of on the surface. The asserted method presents significant benefits such as preventing steam quality loss, decreasing the environmental effects, and enhancing the heavy oil recovery by co-injecting the flue gas products such as CO2, and consequently, the economic outcomes will be increased.\u0000 In this research, a comprehensive techno-economic case study has been conducted on a heavy oil reservoir to evaluate the economic and technical advantages of DHSG compared to surface steam generation. Various technical expenses and revenues such as investment costs, operating costs, royalties, and taxes have been considered in a simulation model in MATLAB. This DHSG feasibility assessment has been performed using data of a heavy oil reserve currently under steam flood. Results showed that DHSG could increase up to 50% economic and technical interest than conventional steam injection projects. One of the outstanding benefits of DHSG is the reduction of heat loss. Since steam is produced in-situ, either downhole or in the reservoir, no waste of heat occurs. Typically, most heat losses happen on surface lines and wellbore during steam injection from the surface, which accounts for approximately 32%. Thus, this issue is excluded using the DHSG method.\u0000 The results of the recent effort fit well into the current industry's requirements. DHSG can (1) increase the rate of heavy oil production, (2) decrease the extra expenses, and (3) dwindle the environmental side effects of CO2 emission of surface steam generation. Compared with conventional thermal methods, in DHSG, the steam to oil ratio remains constant with depth change while the desired steam quality can be achieved at any location. The asserted benefits can ultimately optimize the steam injection with a significant reduction in UTC, hence, improved profitability.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90699857","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}
The buildup of high casing-casing annulus (CCA) pressure compromises the well integrity and can lead to serious incidents if left untreated. Potential sources of water causing the elevated CCA pressure are either trapped water in the cement column or water from a constant feeding source. This study utilizes inorganic geochemical techniques to determine the provenance of CCA produced water as trigger for high pressure in newly drilled wells. Affinities in the hydrochemical (major, minor and trace elements) and stable isotopic (δ2H, δ18O) composition are monitored to identify single fluid types, multi-component mixing and secondary fluid alteration processes. As a proof-of-concept, geochemical fingerprints of CCA produced water from three wells were correlated with potential source candidates, i.e., utilized drilling fluids (mud filtrate, supply water) from the target well site, Early - Late Cretaceous aquifers and Late Jurassic - Late Triassic formation waters from adjacent wells and fields. Geochemical affinities of CCA water with groundwater from an Early Cretaceous aquifer postulate the presence one single horizon for active water inflow. Non-reactive elements (Na, Cl) and environmental isotopes (δ2H, δ18O) were found to be most suited tools for fluid identification. 2H/1H and 18O/16O ratios of supply water and mud filtrate are close to global meteoric water composition, whereas formation waters are enriched in 18O. Elevated SO4 and K concentrations and extreme alkaline conditions for CCA water indicates the occurrence of minor secondary alteration processes, such the contact of inflowing groundwater with cement or fluid mixing with minor portions of KCl additives. The presented technology in this study enables the detection of high CCA pressure and fluid leakages sources, thereby allowing workover engineers to plan for potential remedial actions prior to moving the rig to the affected well; hence significantly reducing operational costs. Appropriate remedial solutions can be prompted for safe well abandonment as well as to resume operation at the earliest time.
{"title":"Geochemical Techniques to Detect Sources of Fluids in Highly Pressured Casing-Casing Annuli CCA","authors":"Dr. Peter Birkle, Hamdi A. AlRamadan","doi":"10.2118/208146-ms","DOIUrl":"https://doi.org/10.2118/208146-ms","url":null,"abstract":"\u0000 The buildup of high casing-casing annulus (CCA) pressure compromises the well integrity and can lead to serious incidents if left untreated. Potential sources of water causing the elevated CCA pressure are either trapped water in the cement column or water from a constant feeding source. This study utilizes inorganic geochemical techniques to determine the provenance of CCA produced water as trigger for high pressure in newly drilled wells. Affinities in the hydrochemical (major, minor and trace elements) and stable isotopic (δ2H, δ18O) composition are monitored to identify single fluid types, multi-component mixing and secondary fluid alteration processes. As a proof-of-concept, geochemical fingerprints of CCA produced water from three wells were correlated with potential source candidates, i.e., utilized drilling fluids (mud filtrate, supply water) from the target well site, Early - Late Cretaceous aquifers and Late Jurassic - Late Triassic formation waters from adjacent wells and fields. Geochemical affinities of CCA water with groundwater from an Early Cretaceous aquifer postulate the presence one single horizon for active water inflow. Non-reactive elements (Na, Cl) and environmental isotopes (δ2H, δ18O) were found to be most suited tools for fluid identification. 2H/1H and 18O/16O ratios of supply water and mud filtrate are close to global meteoric water composition, whereas formation waters are enriched in 18O. Elevated SO4 and K concentrations and extreme alkaline conditions for CCA water indicates the occurrence of minor secondary alteration processes, such the contact of inflowing groundwater with cement or fluid mixing with minor portions of KCl additives. The presented technology in this study enables the detection of high CCA pressure and fluid leakages sources, thereby allowing workover engineers to plan for potential remedial actions prior to moving the rig to the affected well; hence significantly reducing operational costs. Appropriate remedial solutions can be prompted for safe well abandonment as well as to resume operation at the earliest time.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81946582","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}
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}
Khaled Al Blooshi, H. Mohammed, Khalid Yousef Al Awadhi, Pedro Carreiras, Maitha Al Mansoori, Waad Saeed Al Ameri, Mouza Sulaiman Al Houqani, Amal ALwedami, Rasha Humaid Saleh, A. Alsaeedi, Ayesha Al Hemeiri
ADNOC has identified digital technology as a key enabler of sustainable value creation as it delivers its 2030 smart growth strategy. The Transformation Management Office (TMO) has been established to accelerate delivery of ADNOC's digital transformation, actively manage its digital portfolio, build digital capabilities, lead the digital empowerment of local talent and institute a ‘new way to operate’. By doing so, it supports ADNOC's ambition to be a data-driven organization, adopting new ways of working, and delivering greater value, while adapting swiftly to competitive threats to its core business. ADNOC's digital transformation is changing the way the organization operates. The adoption of digital technologies, including big data, Artificial Intelligence and Machine Learning and robotics will optimize production, improve efficiency, reduce risk and de-risk multibillion dollar projects. To achieve this requires a change of company culture across the full value chain. The decision to establish the Transformation Management Office was a recognition that ADNOC must evolve to meet the realities of the new energy era by adopting advanced digital technologies to ensure we remain resilient and agile, by making the most of our resources, enhancing our performance, empowering our people and delivering greater value for our shareholders, Abu Dhabi and the UAE.
{"title":"Transformation Management Office as a Vehicle to Accelerate Digital Transformation","authors":"Khaled Al Blooshi, H. Mohammed, Khalid Yousef Al Awadhi, Pedro Carreiras, Maitha Al Mansoori, Waad Saeed Al Ameri, Mouza Sulaiman Al Houqani, Amal ALwedami, Rasha Humaid Saleh, A. Alsaeedi, Ayesha Al Hemeiri","doi":"10.2118/207222-ms","DOIUrl":"https://doi.org/10.2118/207222-ms","url":null,"abstract":"\u0000 ADNOC has identified digital technology as a key enabler of sustainable value creation as it delivers its 2030 smart growth strategy. The Transformation Management Office (TMO) has been established to accelerate delivery of ADNOC's digital transformation, actively manage its digital portfolio, build digital capabilities, lead the digital empowerment of local talent and institute a ‘new way to operate’. By doing so, it supports ADNOC's ambition to be a data-driven organization, adopting new ways of working, and delivering greater value, while adapting swiftly to competitive threats to its core business.\u0000 ADNOC's digital transformation is changing the way the organization operates. The adoption of digital technologies, including big data, Artificial Intelligence and Machine Learning and robotics will optimize production, improve efficiency, reduce risk and de-risk multibillion dollar projects. To achieve this requires a change of company culture across the full value chain. The decision to establish the Transformation Management Office was a recognition that ADNOC must evolve to meet the realities of the new energy era by adopting advanced digital technologies to ensure we remain resilient and agile, by making the most of our resources, enhancing our performance, empowering our people and delivering greater value for our shareholders, Abu Dhabi and the UAE.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73447594","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}
Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development. The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring. In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design. Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.
{"title":"Realtime Wellbore Digitalization for Stimulations Using Multi-Well Fiber Optics","authors":"Xinyang Li, A. Chavarria, Y. Oukaci","doi":"10.2118/207710-ms","DOIUrl":"https://doi.org/10.2118/207710-ms","url":null,"abstract":"\u0000 Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development.\u0000 The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring.\u0000 In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design.\u0000 Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90146267","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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