W. Mills, Kate Al Tameemi, Grant Cole, C. Gill, Lucy Manifold, Graeme Petrie, Jonathan Dietz
The COVID-19 pandemic limited global travel and access to core facilities. However, by adopting an innovative remote core description workflow, potential delays to an important reservoir characterisation study were avoided and mitigated. Over c.1700ft of middle Miocene core from an Onshore well in Abu Dhabi was described using high-resolution core photos, CT scans and CCA data. Detailed (1:20ft scale) descriptions of heterogeneous, mixed lithology sediments from a gas reservoir were produced. The aim when developing the workflow was not to try and replicate the process of in-person core description, but to create a workflow that could be executed remotely, whilst maintaining technical standards. Ideally, we wanted to find a solution that also had the potential to improve the overall quality of core description, by integrating more data from the onset. The workflow used a matrix to generate a confidence score for the description of each cored interval. Factors such as core condition were considered, which highly influences the extractable core information. The confidence score was used to make decisions, such as whether an in-person review of the core was necessary, especially where core condition was below a reasonable threshold. This helped prioritise cored intervals for review, ensuring time in the core store was focused, and allowed accuracy and reliability of the remote description to be assessed. The 4-phase workflow is summarised as: Image extraction of white light (WL), ultraviolet (UV) and computed tomography (CT) core images. Digital chart creation, core-to-log shifts and sample selection: Wireline data, CCA data and core images loaded Core images used to determine core-to-log shifts Thin section, SEM and XRD samples selected Remote core description: Conducted using all core imagery, CCA and wireline data Thin section, SEM and XRD data were used to refine the description when they became available A confidence score was given to each cored interval QC and finalization: Using the results from phase 3, a selection of cored intervals for in-person review was made. Intervals included those with a poor match between remote description and petrographic data, or areas with a low confidence score. Following the review, charts were finalised and quality-checked for data export Using this workflow, ensured work on an important study could continue during the pandemic. Such an approach has continued value for future studies as it increases efficiency and accounts for more data to be considered in core description prior to viewing the core in-person; it has been used on recent studies with great success. Another benefit to this approach is that less time in the core store is required, reducing potential HSE risks and helping to manage core store availability in busy facilities.
{"title":"Problem-Solving in a Pandemic: How the Creation of a New Workflow Improved the Quality and Timeliness of Remote Core Descriptions","authors":"W. Mills, Kate Al Tameemi, Grant Cole, C. Gill, Lucy Manifold, Graeme Petrie, Jonathan Dietz","doi":"10.2118/207629-ms","DOIUrl":"https://doi.org/10.2118/207629-ms","url":null,"abstract":"\u0000 The COVID-19 pandemic limited global travel and access to core facilities. However, by adopting an innovative remote core description workflow, potential delays to an important reservoir characterisation study were avoided and mitigated.\u0000 Over c.1700ft of middle Miocene core from an Onshore well in Abu Dhabi was described using high-resolution core photos, CT scans and CCA data. Detailed (1:20ft scale) descriptions of heterogeneous, mixed lithology sediments from a gas reservoir were produced.\u0000 The aim when developing the workflow was not to try and replicate the process of in-person core description, but to create a workflow that could be executed remotely, whilst maintaining technical standards. Ideally, we wanted to find a solution that also had the potential to improve the overall quality of core description, by integrating more data from the onset.\u0000 The workflow used a matrix to generate a confidence score for the description of each cored interval. Factors such as core condition were considered, which highly influences the extractable core information. The confidence score was used to make decisions, such as whether an in-person review of the core was necessary, especially where core condition was below a reasonable threshold. This helped prioritise cored intervals for review, ensuring time in the core store was focused, and allowed accuracy and reliability of the remote description to be assessed.\u0000 The 4-phase workflow is summarised as:\u0000 Image extraction of white light (WL), ultraviolet (UV) and computed tomography (CT) core images. Digital chart creation, core-to-log shifts and sample selection: Wireline data, CCA data and core images loaded Core images used to determine core-to-log shifts Thin section, SEM and XRD samples selected Remote core description: Conducted using all core imagery, CCA and wireline data Thin section, SEM and XRD data were used to refine the description when they became available A confidence score was given to each cored interval QC and finalization: Using the results from phase 3, a selection of cored intervals for in-person review was made. Intervals included those with a poor match between remote description and petrographic data, or areas with a low confidence score. Following the review, charts were finalised and quality-checked for data export\u0000 Using this workflow, ensured work on an important study could continue during the pandemic. Such an approach has continued value for future studies as it increases efficiency and accounts for more data to be considered in core description prior to viewing the core in-person; it has been used on recent studies with great success.\u0000 Another benefit to this approach is that less time in the core store is required, reducing potential HSE risks and helping to manage core store availability in busy facilities.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78239643","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}
Juan Manuel Arroyave, J. L. Paredes, Fabian Castro, Jhon Rubiano, Carlos Gandara, Miguel Molano, German A. Cotes, Marino Ríos, Guillermo Sanchez
Well Integrity is a critical compliance requirement during oil and gas operations. Abandonment procedures must ensure that all hydrocarbon sources are properly isolated and effective barriers are placed. This paper describes the use of resin systems to isolate annular gas migration identified during the Obiwan – 1 well abandonment in Colombia. The main challenge was to select and design fluid systems capable to fill tight spaces and isolate the annular channel. Resin systems are high-strength, elastic polymers which act as dependable barriers to isolate fluid flow. They can be designed as a solid-free, pure liquid or may contain solids (cement with a formulated percent of resin). Solid-free formulations are ideal for remedial operations, such as isolating annular gas. Acoustic logging enabled identification of the influx zones. Annular isolation was achieved by executing two cementing remedial operations using the bradenhead squeeze technique. A tailored resin system was selected to deliver the proper barrier addressing the influx zones after injectivity tests were performed in each interval. For the first intervention a solids-free resin system was used, and for the second one a resin-cement composite system was applied. During cementing remedial operations, it was determined that the resin systems were able to achieve deep penetration into the channels more readily and form a seal. The correct system was selected for each case, and during execution, the required volume was injected to intersect and properly isolate the annular gas channel. As a result, the tailored resin systems isolated the gas channel eliminating annular pressure and gas migration to surface. In addition, a post remedial operation acoustic log indicated that the influx zones were successfully isolated. Well abandonment was accomplished according to country regulatory requirements and delivered dependable barriers both annular and interior pipe sections. Use of resin to repair channels of this type exhibited a higher success rate and improved reliability in comparison to conventional particulate-laden fluids, which helps to decrease costs for additional remedial treatments.
{"title":"Deep Penetration Resin Systems Overcome Annular Gas Migration: Case History","authors":"Juan Manuel Arroyave, J. L. Paredes, Fabian Castro, Jhon Rubiano, Carlos Gandara, Miguel Molano, German A. Cotes, Marino Ríos, Guillermo Sanchez","doi":"10.2118/207221-ms","DOIUrl":"https://doi.org/10.2118/207221-ms","url":null,"abstract":"\u0000 Well Integrity is a critical compliance requirement during oil and gas operations. Abandonment procedures must ensure that all hydrocarbon sources are properly isolated and effective barriers are placed.\u0000 This paper describes the use of resin systems to isolate annular gas migration identified during the Obiwan – 1 well abandonment in Colombia. The main challenge was to select and design fluid systems capable to fill tight spaces and isolate the annular channel.\u0000 Resin systems are high-strength, elastic polymers which act as dependable barriers to isolate fluid flow. They can be designed as a solid-free, pure liquid or may contain solids (cement with a formulated percent of resin). Solid-free formulations are ideal for remedial operations, such as isolating annular gas.\u0000 Acoustic logging enabled identification of the influx zones. Annular isolation was achieved by executing two cementing remedial operations using the bradenhead squeeze technique. A tailored resin system was selected to deliver the proper barrier addressing the influx zones after injectivity tests were performed in each interval. For the first intervention a solids-free resin system was used, and for the second one a resin-cement composite system was applied.\u0000 During cementing remedial operations, it was determined that the resin systems were able to achieve deep penetration into the channels more readily and form a seal. The correct system was selected for each case, and during execution, the required volume was injected to intersect and properly isolate the annular gas channel.\u0000 As a result, the tailored resin systems isolated the gas channel eliminating annular pressure and gas migration to surface. In addition, a post remedial operation acoustic log indicated that the influx zones were successfully isolated. Well abandonment was accomplished according to country regulatory requirements and delivered dependable barriers both annular and interior pipe sections.\u0000 Use of resin to repair channels of this type exhibited a higher success rate and improved reliability in comparison to conventional particulate-laden fluids, which helps to decrease costs for additional remedial treatments.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80049773","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}
F. L. Landaeta Rivas, M. Cotten, P. Bimastianto, S. Khambete, S. A. Al Ameri, Erwan Couzigou, A. Al-Marzouqi, Wiliem Pausin, Nadeem Hidayat Ullah, Ahsan Qadir
COVID-19 pandemic shifted the conventional working paradigms, forcing an accelerated adaptability to remote working, ensuring the wellbeing of the employees without sacrificing the effectiveness, in compliance to 100% HSE. To overcome this challenge, Drilling Real Time Operations Center (RTOC) transformed the conventional Monitoring Onsite Hub into a full virtual collaborative remote center operated from each individual's place. This paper describes how RTOC successfully, continued to support drilling operations off-site through secure portal during work-from-home period. RTOC ensured to have the sufficient connectivity resources and security protocols to access the IT company environment and execute the tasks at the same productivity level, as operating from the hub. The platform design involved virtual machine remoting in an integrated communication environment, in synergy with the conventional ways of communication. Several data access points were developed to ensure an unstoppable link between operational teams and the data deliverables. To grantee productivity, KPIs were established and closely monitored, e.g. active rigs count, connectivity issues, software support, real-time drilling performance reporting, engineering computations, with continuous quality audits. Despite several challenges at start due to change in the nature of the work, RTOC successfully overcame the difficulties by having proper procedures and infrastructure in place. The virtual collaborative environment allowed the team to operate the center remotely and meet the targets for deliverables. Defining a clear communication protocol created efficiency when addressing data aggregation problems. As a result, RTOC was able to maintain the resolution time for data aggregation issues and continue to produce drilling performance reports within time. RTOC launched a mobile application for drilling real-time monitoring to support user mobility prior to the mandate of work-from-home policy. RTOC continued to support drilling operations during work-from-home period by providing real-time computations for drilling operations, doing real-time interactions for drilling events and introducing data analytics platform for users to analyze drilling performance. In summary, systematic implementation of the workflows and following clear chain of command have proven to be effective in ensuring business continuity of RTOC. Building trust and respect helped boost the morale and productivity of the team while ensuring their safety and wellbeing. The pandemic has been, indeed, a tough period for the world but the shift of working lifestyle was indeed a unique experience. It broadened the horizon for RTOC to develop advanced collaboration tools and upgrade the infrastructure to be future-ready for higher mobility. This novelty can also be adopted as standard procedure for Emergency Response Plan.
{"title":"Managing Drilling Real-Time Center Remotely Amid Covid-19 Pandemic in Compliance to 100% HSE","authors":"F. L. Landaeta Rivas, M. Cotten, P. Bimastianto, S. Khambete, S. A. Al Ameri, Erwan Couzigou, A. Al-Marzouqi, Wiliem Pausin, Nadeem Hidayat Ullah, Ahsan Qadir","doi":"10.2118/208153-ms","DOIUrl":"https://doi.org/10.2118/208153-ms","url":null,"abstract":"\u0000 COVID-19 pandemic shifted the conventional working paradigms, forcing an accelerated adaptability to remote working, ensuring the wellbeing of the employees without sacrificing the effectiveness, in compliance to 100% HSE. To overcome this challenge, Drilling Real Time Operations Center (RTOC) transformed the conventional Monitoring Onsite Hub into a full virtual collaborative remote center operated from each individual's place. This paper describes how RTOC successfully, continued to support drilling operations off-site through secure portal during work-from-home period.\u0000 RTOC ensured to have the sufficient connectivity resources and security protocols to access the IT company environment and execute the tasks at the same productivity level, as operating from the hub.\u0000 The platform design involved virtual machine remoting in an integrated communication environment, in synergy with the conventional ways of communication. Several data access points were developed to ensure an unstoppable link between operational teams and the data deliverables.\u0000 To grantee productivity, KPIs were established and closely monitored, e.g. active rigs count, connectivity issues, software support, real-time drilling performance reporting, engineering computations, with continuous quality audits.\u0000 Despite several challenges at start due to change in the nature of the work, RTOC successfully overcame the difficulties by having proper procedures and infrastructure in place. The virtual collaborative environment allowed the team to operate the center remotely and meet the targets for deliverables. Defining a clear communication protocol created efficiency when addressing data aggregation problems. As a result, RTOC was able to maintain the resolution time for data aggregation issues and continue to produce drilling performance reports within time.\u0000 RTOC launched a mobile application for drilling real-time monitoring to support user mobility prior to the mandate of work-from-home policy. RTOC continued to support drilling operations during work-from-home period by providing real-time computations for drilling operations, doing real-time interactions for drilling events and introducing data analytics platform for users to analyze drilling performance.\u0000 In summary, systematic implementation of the workflows and following clear chain of command have proven to be effective in ensuring business continuity of RTOC. Building trust and respect helped boost the morale and productivity of the team while ensuring their safety and wellbeing.\u0000 The pandemic has been, indeed, a tough period for the world but the shift of working lifestyle was indeed a unique experience. It broadened the horizon for RTOC to develop advanced collaboration tools and upgrade the infrastructure to be future-ready for higher mobility. This novelty can also be adopted as standard procedure for Emergency Response Plan.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81595693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Noufal, G. Nasreldin, F. Al-Jenaibi, Joel W. Martin, J. Guerra, Hani Al Sahn, E. Muniz, Safdar Khan, Abdulla M. Shehab
A mature field located in a gently dipping structure onshore Abu Dhabi has multiple stacked oil and gas reservoirs experiencing different levels of depletion. The average reservoir pressure in some of these intervals had declined from the early production years to the present day by more than 2000 psi. Coupled geomechanical modelling is, therefore, of the greatest value to predict the stress paths in producing reservoir units, using the concept of effective stress. This paper examines the implications for long-term field management—focusing primarily on estimating the potential for reservoir compaction and predicting field subsidence. This paper takes the work reported in Noufal et al. (2020) one step further by integrating the results of a comprehensive geomechanical laboratory characterization study designed to assess the potential geomechanical changes in the stacked reservoirs from pre-production conditions to abandonment. This paper adopts a geomechanical modelling approach integrating a wide array of data—including prestack seismic inversion outputs and dynamic reservoir simulation results. This study comprised four phases. After the completion of rock mechanics testing, the first modelling phase examined geomechanics on a fine scale around individual wells. The goal of the second phase was to build 4D mechanical earth models (4D MEMs) by incorporating 14 reservoir models—resulting in one of the largest 4D MEMs ever built worldwide. The third phase involved determining the present-day stress state—matching calibrated post-production 1D MEMs and interpreted stress features. Lastly, the resulting model was used for field management and formation stimulation applications. The 4D geomechanical modelling results indicated stress changes in the order of several MPa in magnitude compared with the pre-production stress state, and some changes in stress orientations, especially in the vicinity of faults. This was validated using well images and direct stress measurements, indicating the ability of the 4D MEM to capture the changes in stress magnitudes and orientations caused by depletion. In the computed results, the 4D MEM captures the onset of pore collapse and its accelerating response as observed in the laboratory tests conducted on cores taken from different reservoir units. Pore collapse is predicted in later production years in areas with high porosity, and it is localized. The model highlights the influence of stress changes on porosity and permeability changes over time, thus providing insights into the planning of infill drilling and water injection. Qualitatively, the results provide invaluable insights into delineating potential sweet spots for stimulation by hydraulic fracturing.
{"title":"Integrating Laboratory Testing and Numerical Modelling for a Giant Maturing Carbonate Field in UAE — II. Coupled Geomechanical Modelling of Stacked Reservoir Intervals","authors":"A. Noufal, G. Nasreldin, F. Al-Jenaibi, Joel W. Martin, J. Guerra, Hani Al Sahn, E. Muniz, Safdar Khan, Abdulla M. Shehab","doi":"10.2118/207729-ms","DOIUrl":"https://doi.org/10.2118/207729-ms","url":null,"abstract":"\u0000 A mature field located in a gently dipping structure onshore Abu Dhabi has multiple stacked oil and gas reservoirs experiencing different levels of depletion. The average reservoir pressure in some of these intervals had declined from the early production years to the present day by more than 2000 psi. Coupled geomechanical modelling is, therefore, of the greatest value to predict the stress paths in producing reservoir units, using the concept of effective stress. This paper examines the implications for long-term field management—focusing primarily on estimating the potential for reservoir compaction and predicting field subsidence.\u0000 This paper takes the work reported in Noufal et al. (2020) one step further by integrating the results of a comprehensive geomechanical laboratory characterization study designed to assess the potential geomechanical changes in the stacked reservoirs from pre-production conditions to abandonment. This paper adopts a geomechanical modelling approach integrating a wide array of data—including prestack seismic inversion outputs and dynamic reservoir simulation results. This study comprised four phases. After the completion of rock mechanics testing, the first modelling phase examined geomechanics on a fine scale around individual wells. The goal of the second phase was to build 4D mechanical earth models (4D MEMs) by incorporating 14 reservoir models—resulting in one of the largest 4D MEMs ever built worldwide. The third phase involved determining the present-day stress state—matching calibrated post-production 1D MEMs and interpreted stress features. Lastly, the resulting model was used for field management and formation stimulation applications.\u0000 The 4D geomechanical modelling results indicated stress changes in the order of several MPa in magnitude compared with the pre-production stress state, and some changes in stress orientations, especially in the vicinity of faults. This was validated using well images and direct stress measurements, indicating the ability of the 4D MEM to capture the changes in stress magnitudes and orientations caused by depletion. In the computed results, the 4D MEM captures the onset of pore collapse and its accelerating response as observed in the laboratory tests conducted on cores taken from different reservoir units. Pore collapse is predicted in later production years in areas with high porosity, and it is localized. The model highlights the influence of stress changes on porosity and permeability changes over time, thus providing insights into the planning of infill drilling and water injection. Qualitatively, the results provide invaluable insights into delineating potential sweet spots for stimulation by hydraulic fracturing.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85761556","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 reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.
{"title":"A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer","authors":"Jitong Liu, Wanjun Li, Haiqiu Zhou, Y. Gu, Fuhua Jiang, Guobin Zhang, Shiying Zhou, Hai-Xiang Liu, Chao Liao, Shengqiang Wang, Zhifeng Zhou","doi":"10.2118/208099-ms","DOIUrl":"https://doi.org/10.2118/208099-ms","url":null,"abstract":"\u0000 The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability.\u0000 The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers.\u0000 The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers.\u0000 This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77153086","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}
This paper discusses "Halaqa", which aims to create a culture of learning by sharing experiences in sessions where people interact with one another and encouraging the free flow of ideas among the teams. This inspires young professionals to enhance the learning curve, seek new ideas and develop a culture of creative problem-solving pathways. As a definition, "Halaqa" is a platform for sharing ideas and experiences. The session is planned bi-weekly targeting young professionals in the Petroleum Engineering function. The topic of the session can be presented by (i) a senior or an experienced professional as a part of coaching or (ii) a young professional as a knowledge sharing methodology. The sessions are interactive allowing open discussions for the deeply inquisitive minds. The sessions also provide support with unpacking complex and sticky issues, helping young professionals to replicate the best practices for the efficient and effective delivery of the project. Each session usually takes about an hour including discussions and the points are documented properly for the retention of knowledge. "Halaqa" is a new concept in the asset and has the potential to be replicated in the entire organization. The uniqueness comes from the fact that it provides a platform to interact and collaborate to pursue common objectives. The relationships that are created through these interactions are crucial as far as the learning of young professionals is concerned.
{"title":"Halaqa: preparing a culture of success for young professionals","authors":"Hanin Rashid Al Kiyumi","doi":"10.2118/207378-ms","DOIUrl":"https://doi.org/10.2118/207378-ms","url":null,"abstract":"\u0000 This paper discusses \"Halaqa\", which aims to create a culture of learning by sharing experiences in sessions where people interact with one another and encouraging the free flow of ideas among the teams. This inspires young professionals to enhance the learning curve, seek new ideas and develop a culture of creative problem-solving pathways.\u0000 As a definition, \"Halaqa\" is a platform for sharing ideas and experiences. The session is planned bi-weekly targeting young professionals in the Petroleum Engineering function. The topic of the session can be presented by (i) a senior or an experienced professional as a part of coaching or (ii) a young professional as a knowledge sharing methodology. The sessions are interactive allowing open discussions for the deeply inquisitive minds. The sessions also provide support with unpacking complex and sticky issues, helping young professionals to replicate the best practices for the efficient and effective delivery of the project. Each session usually takes about an hour including discussions and the points are documented properly for the retention of knowledge.\u0000 \"Halaqa\" is a new concept in the asset and has the potential to be replicated in the entire organization. The uniqueness comes from the fact that it provides a platform to interact and collaborate to pursue common objectives. The relationships that are created through these interactions are crucial as far as the learning of young professionals is concerned.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80984997","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}
Maintenance costs and machine availability are two of the most important concerns to gas turbine equipment owner. Therefore, a well thought out maintenance program that reduces costs while increasing equipment availability should be instituted. The correct implementation of planned maintenance relying on preventive maintenance optimization through perfect inspection frequency and scope provides direct benefits in the avoidance of forced outages, unscheduled repairs, and downtime. Major overhaul is carried out for each gas turbine every 48,000 firing hours which costs around 1 M USD for each engine and with more than 8 months unavailability for the unit. To increase equipment availability and enhance cost and time efficiency, alternatives approaches were evaluated including Service Exchange of gas turbines. It is found that service exchange is the best option for optimizing time and cost of overhaul of such engines. This paper is written to improve Major Overhaul practice for existing Gas Turbines from ongoing practice of routine major overhaul including engine strip down, inspection and repair to Service Exchange of Gas Generator and Power Turbine every 48,000 firing hours.
{"title":"Service Exchange or Major Overhaul. Which Philosophy to Implement for Gas Turbine","authors":"K. M. Youssef","doi":"10.2118/208221-ms","DOIUrl":"https://doi.org/10.2118/208221-ms","url":null,"abstract":"\u0000 Maintenance costs and machine availability are two of the most important concerns to gas turbine equipment owner. Therefore, a well thought out maintenance program that reduces costs while increasing equipment availability should be instituted.\u0000 The correct implementation of planned maintenance relying on preventive maintenance optimization through perfect inspection frequency and scope provides direct benefits in the avoidance of forced outages, unscheduled repairs, and downtime.\u0000 Major overhaul is carried out for each gas turbine every 48,000 firing hours which costs around 1 M USD for each engine and with more than 8 months unavailability for the unit.\u0000 To increase equipment availability and enhance cost and time efficiency, alternatives approaches were evaluated including Service Exchange of gas turbines. It is found that service exchange is the best option for optimizing time and cost of overhaul of such engines.\u0000 This paper is written to improve Major Overhaul practice for existing Gas Turbines from ongoing practice of routine major overhaul including engine strip down, inspection and repair to Service Exchange of Gas Generator and Power Turbine every 48,000 firing hours.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79868138","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}
Managing climate change is a growing global concern. The Paris Agreement, the first ever legally binding global climate change agreement, enforced longer term actions for energy firms in terms of implementing newer means and technologies to reduce reliance on fossil fuel-based energy. In this regard, much attention is drawn to commercialized Power-To-Gas (PTG) - Hydrogen generated from renewable energy-based electrolysis can be introduced into natural gas utilities, thereby ensuring "Greener" natural gas mix. The integration of PTG plants and natural gas-fired power plants presents an attractive model to implement this. This paper analyzes the associated project management challenges, ranging from complexity issues to technology management and with a view on better integration and risk reduction. Power-to-Gas (PTG) is the process of converting surplus renewable energy into hydrogen gas through electrolysis. PTG plants and natural gas-fired power plants can form a closed loop between an electric power system and an interconnected multi-energy system, and this is believed to be a sustainable solution towards environment friendly energy systems. Power-to-Gas (PTG) technology is yet to mature in terms of its commercial viability. As such, traditional project management processes and methodologies also need to be reviewed and adapted to suit the economic and execution models needed for project success. The dimensions that will be analyzed in this paper include project integration management, project complexity management, technology management and risk management strategies. A model for Joint Venture management will also be proposed. PTG projects, as an effective means of transitioning to a ‘greener’ natural gas mix and the associated project life cycle process will be defined based on an integrated FEL (iFEL) model. Project risk management perspectives, its stakeholder influences and methods to mitigate risks towards better decision-making process shall be explored. This work proposes establishment of a dedicated, technically competent and scalable Global PMO to oversee the PTG projects’ prioritization, concept/technology selection, JV management, contracting strategies, formulation of a proactive management response system and overall value assurance.
{"title":"Managing Energy Transition - Adapting Power to Gas Technology PTG - Project Management Review of Complexity, Technology and Integration Aspects","authors":"Prasannakumar K. Purayil, Sujith Pratap Chandran","doi":"10.2118/207806-ms","DOIUrl":"https://doi.org/10.2118/207806-ms","url":null,"abstract":"\u0000 Managing climate change is a growing global concern. The Paris Agreement, the first ever legally binding global climate change agreement, enforced longer term actions for energy firms in terms of implementing newer means and technologies to reduce reliance on fossil fuel-based energy. In this regard, much attention is drawn to commercialized Power-To-Gas (PTG) - Hydrogen generated from renewable energy-based electrolysis can be introduced into natural gas utilities, thereby ensuring \"Greener\" natural gas mix. The integration of PTG plants and natural gas-fired power plants presents an attractive model to implement this. This paper analyzes the associated project management challenges, ranging from complexity issues to technology management and with a view on better integration and risk reduction.\u0000 Power-to-Gas (PTG) is the process of converting surplus renewable energy into hydrogen gas through electrolysis. PTG plants and natural gas-fired power plants can form a closed loop between an electric power system and an interconnected multi-energy system, and this is believed to be a sustainable solution towards environment friendly energy systems. Power-to-Gas (PTG) technology is yet to mature in terms of its commercial viability. As such, traditional project management processes and methodologies also need to be reviewed and adapted to suit the economic and execution models needed for project success. The dimensions that will be analyzed in this paper include project integration management, project complexity management, technology management and risk management strategies. A model for Joint Venture management will also be proposed.\u0000 PTG projects, as an effective means of transitioning to a ‘greener’ natural gas mix and the associated project life cycle process will be defined based on an integrated FEL (iFEL) model. Project risk management perspectives, its stakeholder influences and methods to mitigate risks towards better decision-making process shall be explored.\u0000 This work proposes establishment of a dedicated, technically competent and scalable Global PMO to oversee the PTG projects’ prioritization, concept/technology selection, JV management, contracting strategies, formulation of a proactive management response system and overall value assurance.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"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":"87653301","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}
Acid fracturing treatments are conducted to increase the productivity of naturally fractured reservoirs. The treatment performance depends on several parameters such as reservoir properties and treatment conditions. Different approaches are available to estimate the efficacy of acid fracturing stimulations. However, a limited number of models were developed considering the presence of natural fractures (NFs) in the hydrocarbon reservoirs. This work aims to develop an efficient model to estimate the effectiveness of acid fracturing treatment in naturally fractured reservoirs utilizing an artificial neural network (ANN) technique. In this study, the improvement in hydrocarbon productivity due to applying acid fracturing treatment is estimated, and the interactions between the natural fractures and the induced ones are considered. More than 3000 scenarios of reservoir properties and treatment parameters were used to build and validate the ANN model. The developed model considers reservoir and treatment parameters such as formation permeability, injection rate, natural fracture spacing, and treatment volume. Furthermore, percentage error and correlation coefficient were determined to assess the model prediction performance. The proposed model shows very effective performance in predicting the performance of acid fracturing treatments. A percentage error of 6.3 % and a correlation coefficient of 0.94 were obtained for the testing datasets. Furthermore, a new correlation was developed based on the optimized AI model. The developed correlation provides an accurate and quick prediction for productivity improvement. Validation data were used to evaluate the reliability of the new equation, where a 6.8% average absolute error and 0.93 correlation coefficient were achieved, indicating the high reliability of the proposed correlation. The novelty of this work is developing a robust and reliable model for predicting the productivity improvement for acid fracturing treatment in naturally fractured reservoirs. The new correlation can be utilized in improving the treatment design for naturally fractured reservoirs by providing quick and reliable estimations.
{"title":"Predicting the Productivity Enhancement After Applying Acid Fracturing Treatments in Naturally Fractured Reservoirs Utilizing Artificial Neural Network","authors":"Amjed Hassan, M. Aljawad, M. Mahmoud","doi":"10.2118/208172-ms","DOIUrl":"https://doi.org/10.2118/208172-ms","url":null,"abstract":"\u0000 Acid fracturing treatments are conducted to increase the productivity of naturally fractured reservoirs. The treatment performance depends on several parameters such as reservoir properties and treatment conditions. Different approaches are available to estimate the efficacy of acid fracturing stimulations. However, a limited number of models were developed considering the presence of natural fractures (NFs) in the hydrocarbon reservoirs. This work aims to develop an efficient model to estimate the effectiveness of acid fracturing treatment in naturally fractured reservoirs utilizing an artificial neural network (ANN) technique.\u0000 In this study, the improvement in hydrocarbon productivity due to applying acid fracturing treatment is estimated, and the interactions between the natural fractures and the induced ones are considered. More than 3000 scenarios of reservoir properties and treatment parameters were used to build and validate the ANN model. The developed model considers reservoir and treatment parameters such as formation permeability, injection rate, natural fracture spacing, and treatment volume. Furthermore, percentage error and correlation coefficient were determined to assess the model prediction performance. The proposed model shows very effective performance in predicting the performance of acid fracturing treatments. A percentage error of 6.3 % and a correlation coefficient of 0.94 were obtained for the testing datasets. Furthermore, a new correlation was developed based on the optimized AI model. The developed correlation provides an accurate and quick prediction for productivity improvement. Validation data were used to evaluate the reliability of the new equation, where a 6.8% average absolute error and 0.93 correlation coefficient were achieved, indicating the high reliability of the proposed correlation.\u0000 The novelty of this work is developing a robust and reliable model for predicting the productivity improvement for acid fracturing treatment in naturally fractured reservoirs. The new correlation can be utilized in improving the treatment design for naturally fractured reservoirs by providing quick and reliable estimations.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83801212","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}
See how application of a fully trained Artificial Intelligence (AI) / Machine Learning (ML) technology applied to 3D seismic data volumes delivers an unbiased data driven assessment of entire volumes or corporate seismic data libraries quickly. Whether the analysis is undertaken using onsite hardware or a cloud based mega cluster, this automated approach provides unparalleled insights for the interpretation and prospectivity analysis of any dataset. The Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms to create families of waveforms, called GeoPopulations, that are used to derive Amplitude, Structure (time or depth depending on the input 3D seismic volume) and the new seismic Fitness attribute. We will show how Fitness is used to interpret paleo geomorphology and facies maps for every peak, trough and zero crossing of the 3D seismic volume. Using the Structure, Amplitude and Fitness attribute maps created for every peak, trough and zero crossing the Exploration and Production (E&P) team can evaluate and mitigate Geological and Geophysical (G&G) risks and uncertainty associated with their petroleum systems quickly using the entire 3D seismic data volume.
{"title":"Using AI/ML to Explore & Develop Quickly and Efficiently","authors":"A. Aming","doi":"10.2118/207377-ms","DOIUrl":"https://doi.org/10.2118/207377-ms","url":null,"abstract":"\u0000 See how application of a fully trained Artificial Intelligence (AI) / Machine Learning (ML) technology applied to 3D seismic data volumes delivers an unbiased data driven assessment of entire volumes or corporate seismic data libraries quickly. Whether the analysis is undertaken using onsite hardware or a cloud based mega cluster, this automated approach provides unparalleled insights for the interpretation and prospectivity analysis of any dataset.\u0000 The Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms to create families of waveforms, called GeoPopulations, that are used to derive Amplitude, Structure (time or depth depending on the input 3D seismic volume) and the new seismic Fitness attribute. We will show how Fitness is used to interpret paleo geomorphology and facies maps for every peak, trough and zero crossing of the 3D seismic volume. Using the Structure, Amplitude and Fitness attribute maps created for every peak, trough and zero crossing the Exploration and Production (E&P) team can evaluate and mitigate Geological and Geophysical (G&G) risks and uncertainty associated with their petroleum systems quickly using the entire 3D seismic data volume.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 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":"89949317","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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