K. Goodheart, P. Mas, Maged Ismail, Umberto Badiali, Wim Hendicx
Through the introduction of programmable logic controller (PLCs), Dynamic Process & Controls modeling, integrating with Multiphysics Mechatronics & 3D equipment simulation modeling, companies can work in the online real-time environment. This modeling of equipment or processes builds the foundation for digital transformation of subsea, topside, onshore and plant environments. In the design and operation of field equipment, the physics based Digital Twin is getting more and more traction to develop virtually the equipment because of recent prediction accuracy improvement and faster calculation times. Such digital twins allow to find the optimal operating conditions and predictive maintenance schedules for operation. In this timeslot we will explain, based on few industrial examples, a new set of capabilities that allow companies to get the maximum out of digital twins to be able to use them on their equipment. By applying a structured process using Digital Twins to be able to convert the existing knowledge & data at Companies into solution to be more predictive on their equipment. This will deliver substantial return on investment (ROI) for the Oil and Gas Industry. An AI based methodology to perform Model Order Reduction on the digital twin to be able to get real time response in connection to online unit information An AI based methodology to convert the reduced model into a virtual sensor for online quality predictions or predictive maintenance scheduling as well as to use it for creating an optimal controller of the unit based on the product requirements Fast edge computing hardware that can collect data from sensors and, in real time, run the Executable Digital Twin (xDT) and suggest corrective action to the operator or run in closed loop control
{"title":"Predictive Maintenance Using the Executable Digital Twin xDT","authors":"K. Goodheart, P. Mas, Maged Ismail, Umberto Badiali, Wim Hendicx","doi":"10.4043/30980-ms","DOIUrl":"https://doi.org/10.4043/30980-ms","url":null,"abstract":"\u0000 Through the introduction of programmable logic controller (PLCs), Dynamic Process & Controls modeling, integrating with Multiphysics Mechatronics & 3D equipment simulation modeling, companies can work in the online real-time environment. This modeling of equipment or processes builds the foundation for digital transformation of subsea, topside, onshore and plant environments.\u0000 In the design and operation of field equipment, the physics based Digital Twin is getting more and more traction to develop virtually the equipment because of recent prediction accuracy improvement and faster calculation times. Such digital twins allow to find the optimal operating conditions and predictive maintenance schedules for operation.\u0000 In this timeslot we will explain, based on few industrial examples, a new set of capabilities that allow companies to get the maximum out of digital twins to be able to use them on their equipment. By applying a structured process using Digital Twins to be able to convert the existing knowledge & data at Companies into solution to be more predictive on their equipment. This will deliver substantial return on investment (ROI) for the Oil and Gas Industry.\u0000 An AI based methodology to perform Model Order Reduction on the digital twin to be able to get real time response in connection to online unit information An AI based methodology to convert the reduced model into a virtual sensor for online quality predictions or predictive maintenance scheduling as well as to use it for creating an optimal controller of the unit based on the product requirements Fast edge computing hardware that can collect data from sensors and, in real time, run the Executable Digital Twin (xDT) and suggest corrective action to the operator or run in closed loop control","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77534307","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}
W. Sánchez, Iván Coronel, Edgar Mora, C. Giosa, M. Satizabal, J. Leal, P. Solórzano, L. Castañeda, Gabriel Mantilla, P. Nazarenko, Oscar Avella, Paul Joseph
Traditional waterflooding methods in heavy oil fields can lead to several problems including reductions of swapping efficiency, channeling of injected water, and low values of recovery factor. These problems are often made worse by other critical factors such as lack of real-time data, operational incidents during injection profile calibration, and complexity of interventions in the existing wells. An innovative solution was implemented in a four-zone injector well in a heavy oil field in Colombia consisting of four intelligent electric valves controlled remotely and distributed fiber optic monitoring to calculate injected flow per zone in real-time. This system allowed the operator to increase oil production in the associated producer wells and eliminate rig-less interventions. The first installation of an All-Electric intelligent completion with distributed fiber optic monitoring was successfully deployed in a complex existing injector well without HSE incidents nor deviations in time and cost. After one year of operation, the system increased production in corresponding producer wells by 62% and saved 30% of operational costs. Additionally, the completion design has improved the injection performance which means that the system requires less injected water to produce the same amount of oil. All these results were possible thanks to the use of a more efficient injection completion and the use of real-time data to make on-time decisions. The importance of this implementation is that it demonstrated that this type of technology not only solves different challenges of the Enhanced Oil Recovery (EOR) strategies of mature fields but also brings additional value in terms of oil production, injection performance, and reduction in operational costs. In this way, this application showed that an intelligent completion - usually expensive in terms of initial investment - is financially viable to implement in mature existing wells with limited CAPEX availability. This paper will present the implementation of an intelligent well completion system that uses permanent distributed fiber optics to monitor water injection in 4 independent zones. The document will also include details regarding the reasons to install this technology in a mature field, well and technology selection, intelligent completion design, and installation. Results will be compared to conventional completion for injector wells that depends on rig-less intervention to measure and regulate injected flow per zone.
{"title":"World First All-Electric Intelligent Completion System with Permanent Monitoring to Evaluate Injection Performance in a Mature Injector Well","authors":"W. Sánchez, Iván Coronel, Edgar Mora, C. Giosa, M. Satizabal, J. Leal, P. Solórzano, L. Castañeda, Gabriel Mantilla, P. Nazarenko, Oscar Avella, Paul Joseph","doi":"10.4043/31323-ms","DOIUrl":"https://doi.org/10.4043/31323-ms","url":null,"abstract":"\u0000 Traditional waterflooding methods in heavy oil fields can lead to several problems including reductions of swapping efficiency, channeling of injected water, and low values of recovery factor. These problems are often made worse by other critical factors such as lack of real-time data, operational incidents during injection profile calibration, and complexity of interventions in the existing wells. An innovative solution was implemented in a four-zone injector well in a heavy oil field in Colombia consisting of four intelligent electric valves controlled remotely and distributed fiber optic monitoring to calculate injected flow per zone in real-time. This system allowed the operator to increase oil production in the associated producer wells and eliminate rig-less interventions.\u0000 The first installation of an All-Electric intelligent completion with distributed fiber optic monitoring was successfully deployed in a complex existing injector well without HSE incidents nor deviations in time and cost. After one year of operation, the system increased production in corresponding producer wells by 62% and saved 30% of operational costs. Additionally, the completion design has improved the injection performance which means that the system requires less injected water to produce the same amount of oil. All these results were possible thanks to the use of a more efficient injection completion and the use of real-time data to make on-time decisions.\u0000 The importance of this implementation is that it demonstrated that this type of technology not only solves different challenges of the Enhanced Oil Recovery (EOR) strategies of mature fields but also brings additional value in terms of oil production, injection performance, and reduction in operational costs. In this way, this application showed that an intelligent completion - usually expensive in terms of initial investment - is financially viable to implement in mature existing wells with limited CAPEX availability.\u0000 This paper will present the implementation of an intelligent well completion system that uses permanent distributed fiber optics to monitor water injection in 4 independent zones. The document will also include details regarding the reasons to install this technology in a mature field, well and technology selection, intelligent completion design, and installation. Results will be compared to conventional completion for injector wells that depends on rig-less intervention to measure and regulate injected flow per zone.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84585116","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Brandão, F. Pires, Ingrid Poloponsky, F. Santos, D. Lopes
Flexible Pipes were widely used in Brazil offshore developments and the challenge on overcoming increasing water depths, high pressures and fluids with high contaminants was always present. In 2017 a new failure mode, called SCC CO2 was disclosed bringing such disruption in the use of this equipment since, at that time, the conditions observed in Brazilian Pre salt were like the "perfect storm" for the failure mode to happen. It had high concentrations of CO2, therefore high permeation in the anulus, high stresses and the possibility to have anulus flooded as result of an outer sheath breach or even due to permeated water. These were the triple conditions needed to have the failure, considering that all metallic material used in the pipe were subjected to this phenomenon. Since the discovery was made, several test campaigns to better understand and replicate the phenomena started. They covered pipe retrieved from field dissection, several small-scale materials testing, and fracture mechanics to create reliable crack propagation calculations. There were 3 mains focus areas; to understand how to deal with the installed fleet, to define the conditions in which a crack would appear and define, using fracture mechanics, how long a crack would take to break the wire. In other words, it was intended to define what is the remaining service life. As a result of this investigation some initial beliefs like that all materials were subjected to the phenomena and that a solution was far away were somehow reduced and reshaped. There was also the initiative to embark on technology for detection of the anulus condition, mainly to define if it is flooded or not. Some ROV inspection means were added to the endfitting and some sensors were added to the interconnected pipe sections that allow conditioning monitoring or inspection from the floating unit, not using a ROV. This paper will cover the improvements done since the disclosure of the phenomena in 2017, reviewing what is known about it so far, what is still to be discovered and how the results achieved to date can contribute for a more reliable and longer service life for the flexible pipes to be applied in a rich CO2 environment.
{"title":"Flexible Pipes Subjected to SCC CO2: Review and Means to Increase Reliability on Service Life Applied to Brazilian Pre-Salt Fields","authors":"M. Brandão, F. Pires, Ingrid Poloponsky, F. Santos, D. Lopes","doi":"10.4043/31135-ms","DOIUrl":"https://doi.org/10.4043/31135-ms","url":null,"abstract":"\u0000 Flexible Pipes were widely used in Brazil offshore developments and the challenge on overcoming increasing water depths, high pressures and fluids with high contaminants was always present. In 2017 a new failure mode, called SCC CO2 was disclosed bringing such disruption in the use of this equipment since, at that time, the conditions observed in Brazilian Pre salt were like the \"perfect storm\" for the failure mode to happen. It had high concentrations of CO2, therefore high permeation in the anulus, high stresses and the possibility to have anulus flooded as result of an outer sheath breach or even due to permeated water. These were the triple conditions needed to have the failure, considering that all metallic material used in the pipe were subjected to this phenomenon.\u0000 Since the discovery was made, several test campaigns to better understand and replicate the phenomena started. They covered pipe retrieved from field dissection, several small-scale materials testing, and fracture mechanics to create reliable crack propagation calculations. There were 3 mains focus areas; to understand how to deal with the installed fleet, to define the conditions in which a crack would appear and define, using fracture mechanics, how long a crack would take to break the wire. In other words, it was intended to define what is the remaining service life.\u0000 As a result of this investigation some initial beliefs like that all materials were subjected to the phenomena and that a solution was far away were somehow reduced and reshaped. There was also the initiative to embark on technology for detection of the anulus condition, mainly to define if it is flooded or not. Some ROV inspection means were added to the endfitting and some sensors were added to the interconnected pipe sections that allow conditioning monitoring or inspection from the floating unit, not using a ROV.\u0000 This paper will cover the improvements done since the disclosure of the phenomena in 2017, reviewing what is known about it so far, what is still to be discovered and how the results achieved to date can contribute for a more reliable and longer service life for the flexible pipes to be applied in a rich CO2 environment.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81441156","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}
T. Sadigov, C. Cerrahoglu, James Ramsay, Laurence Burchell, S. Cavalero, T. Watson, P. Thiruvenkatanathan, Martin Sundin
This paper introduces a novel technique that allows real-time injection monitoring with distributed fiber optics using physics-informed machine learning methods and presents results from Clair Ridge asset where a cloud-based, real-time application is deployed. Clair Ridge is a structural high comprising of naturally fractured Devonian to Carboniferous continental sandstones, with a significantly naturally fractured ridge area. The fractured nature of the reservoir lends itself to permanent deployment of Distributed Fiber Optic Sensing (DFOS) to enable real-time injection monitoring to maximise recovery from the field. In addition to their default limitations, such as providing a snapshot measurement and disturbing the natural well flow with up and down flowing passes, wireline-conveyed production logs (PL) are also unable to provide a high-resolution profile of the water injection along the reservoir due to the completion type. DFOS offers unique surveillance capability when permanently installed along the reservoir interface and continuously providing injection profiles with full visibility along the reservoir section without the need for an intervention. The real-time injection monitoring application uses both distributed acoustic and temperature sensing (DAS & DTS) and is based on physics-informed machine learning models. It is now running and available to all asset users on the cloud. So far, the application has generated high-resolution injection profiles over a dozen multi-rate injection periods automatically and the results are cross-checked against the profiles from the warmback analyses that were also generated automatically as part of the same application. The real-time monitoring insights have been effectively applied to provide significant business value using the capability for start-up optimization to manage and improve injection conformance, monitor fractured formations and caprock monitoring.
{"title":"Real-Time Water Injection Monitoring with Distributed Fiber Optics Using Physics-Informed Machine Learning","authors":"T. Sadigov, C. Cerrahoglu, James Ramsay, Laurence Burchell, S. Cavalero, T. Watson, P. Thiruvenkatanathan, Martin Sundin","doi":"10.4043/30982-ms","DOIUrl":"https://doi.org/10.4043/30982-ms","url":null,"abstract":"\u0000 This paper introduces a novel technique that allows real-time injection monitoring with distributed fiber optics using physics-informed machine learning methods and presents results from Clair Ridge asset where a cloud-based, real-time application is deployed. Clair Ridge is a structural high comprising of naturally fractured Devonian to Carboniferous continental sandstones, with a significantly naturally fractured ridge area. The fractured nature of the reservoir lends itself to permanent deployment of Distributed Fiber Optic Sensing (DFOS) to enable real-time injection monitoring to maximise recovery from the field. In addition to their default limitations, such as providing a snapshot measurement and disturbing the natural well flow with up and down flowing passes, wireline-conveyed production logs (PL) are also unable to provide a high-resolution profile of the water injection along the reservoir due to the completion type. DFOS offers unique surveillance capability when permanently installed along the reservoir interface and continuously providing injection profiles with full visibility along the reservoir section without the need for an intervention.\u0000 The real-time injection monitoring application uses both distributed acoustic and temperature sensing (DAS & DTS) and is based on physics-informed machine learning models. It is now running and available to all asset users on the cloud. So far, the application has generated high-resolution injection profiles over a dozen multi-rate injection periods automatically and the results are cross-checked against the profiles from the warmback analyses that were also generated automatically as part of the same application. The real-time monitoring insights have been effectively applied to provide significant business value using the capability for start-up optimization to manage and improve injection conformance, monitor fractured formations and caprock monitoring.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82411945","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}
Alexandre Rabello, Dorival Natal Neto, E. Coelho, Estevan P. Seraco, Wagner Destro, A. Labes, Gustavo Rodriguez, N. Cuellar, E. Lacher, Daniel Marcos, Vitor Cremoso Coelho, Nestor Noriega
In projects to develop offshore production in Brazilian pre-salt fields, an innovative model of subsea manifolds is being used, based on shared-actuation control (SAC) for the remote operation of valves. The control solution, which comprises the first full-electric robotic tool designed to operate in ultra-deep waters, has achieved an important mark in 2020, with the commissioning and start-of-operation of the first fabricated unit. In this article, we present lessons learned and discuss relevant specifications and programs of the technological development that contributed for the results obtained so far. Considering aspects on conception, technology, and environment of application, the pre-salt SAC required the adoption of new solutions on several disciplines of subsea engineering. As a typical case of technological development, the design process comprised decisions on engineering requirements and the establishment of a comprehensive qualification program. Now, after the first robot completing critical stages at field, such as subsea deployment, functional testing, and integration with the subsea system, we obtain a set of performance results that serve us to evaluate e.g. how effective were the selected technical specifications and testing routines, used throughout the engineering program. This discussion also provides possible adjustments in the overall development plan, considering its application as new generations of SAC arise. The commissioning in 2020 of the first robot resulted in its full integration with the subsea manifold and the correspondent production system, contributing to water-alternating-gas injection in the pre-salt field Tupi Extremo Sul. A second subsea system featuring the same model of robotic tool, for manifold control, is in advanced schedule in 2021 for integration in Búzios II, another pre-salt field in Brazil. Confirming the advantages that we could expect with the adoption of SAC in subsea equipment, the pre-salt SAC allowed a series of optimizations on design of the robot-controlled manifold. The robot tool replaced all the hydraulic actuators that traditional control systems, based on electric-hydraulic multiplexing, would require to implement remote controlling of the manifold valves. This led to a significant reduction on sizes and weight of the manifold structure.
{"title":"First Full-Electric Shared-Actuation Control for Subsea Manifolds in Brazilian Ultra-Deep Waters: A Discussion of the Technological Development up to Field Commissioning","authors":"Alexandre Rabello, Dorival Natal Neto, E. Coelho, Estevan P. Seraco, Wagner Destro, A. Labes, Gustavo Rodriguez, N. Cuellar, E. Lacher, Daniel Marcos, Vitor Cremoso Coelho, Nestor Noriega","doi":"10.4043/31003-ms","DOIUrl":"https://doi.org/10.4043/31003-ms","url":null,"abstract":"\u0000 In projects to develop offshore production in Brazilian pre-salt fields, an innovative model of subsea manifolds is being used, based on shared-actuation control (SAC) for the remote operation of valves. The control solution, which comprises the first full-electric robotic tool designed to operate in ultra-deep waters, has achieved an important mark in 2020, with the commissioning and start-of-operation of the first fabricated unit. In this article, we present lessons learned and discuss relevant specifications and programs of the technological development that contributed for the results obtained so far.\u0000 Considering aspects on conception, technology, and environment of application, the pre-salt SAC required the adoption of new solutions on several disciplines of subsea engineering. As a typical case of technological development, the design process comprised decisions on engineering requirements and the establishment of a comprehensive qualification program. Now, after the first robot completing critical stages at field, such as subsea deployment, functional testing, and integration with the subsea system, we obtain a set of performance results that serve us to evaluate e.g. how effective were the selected technical specifications and testing routines, used throughout the engineering program. This discussion also provides possible adjustments in the overall development plan, considering its application as new generations of SAC arise.\u0000 The commissioning in 2020 of the first robot resulted in its full integration with the subsea manifold and the correspondent production system, contributing to water-alternating-gas injection in the pre-salt field Tupi Extremo Sul. A second subsea system featuring the same model of robotic tool, for manifold control, is in advanced schedule in 2021 for integration in Búzios II, another pre-salt field in Brazil.\u0000 Confirming the advantages that we could expect with the adoption of SAC in subsea equipment, the pre-salt SAC allowed a series of optimizations on design of the robot-controlled manifold. The robot tool replaced all the hydraulic actuators that traditional control systems, based on electric-hydraulic multiplexing, would require to implement remote controlling of the manifold valves. This led to a significant reduction on sizes and weight of the manifold structure.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78834711","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. Karim, Hairulirwan Abu Hassan, Sayyid M Izdihar Muslimin, Roberto Fuenmayor, Ammar Kamarulzaman, Mohamad Mustaqim Mokhlis
The Digital Field initiative is transforming the daily operations on the oilfield and it is now part of PETRONAS corporate wide digital strategy. This transformation is done by onboarding multiple disciplines such as subsurface team, facilities, and operations, HSSE and Business Planning and is designed to replicates the performance of an oilfield in the computer, combining business process management and technical workflows. Digital Field has enabled the customer to execute their work collaboratively, by providing decision support system (technical workflows and business process management tools) subsequently improving their process efficiencies and optimizing their production. It is believed that by conducting a systematic review of the improvement and tracking the values that has been achieved, it will help to promote and accelerate digital adoption faster. The main objectives of the Automated Value Tracking are: To promote opportunity generation through collaborative environment. To track stages of every opportunity of the following categories of Production Optimization, Unplanned Deferment and Process Cycle Efficiencies. To quantify values associated with opportunities generated from automated workflows and current business process. To promote ownership of the actions associated with the assigned opportunity and to help to quantify on individual level contribution to the corporate goal in terms of production volume and time savings. To measures optimized number of opportunities generated against production volume associated with Production Optimization activity according to Field category and Quality of Opportunity Generated from Optimization Advisor. The process is summarized as follow: Opportunity generation: Automated opportunity generation generated through current Production Optimization Advisory framework. Integration with existing Petronas business process tools i.e. Daily Operational Tracking System, Alpha projects, Opportunity Management system, etc. Manual opportunity generation. Opportunity evaluation and analysis: Provide quantitatively confidence level of production incremental volume from automated Optimization Advisory through machine learning. Establish relationship between numbers of opportunity completed and categories versus production volume gain. Opportunity tracking and approval: Tracking the opportunity generation according to the process level. Escalating Opportunity and value recognition through business process approval. This workflow helps to improve to understand the current update of the different levels such as well, field, region and upstream with the help of integrating the value realization and allows "cards" to show information that can trigger opportunities to increase production, reduce time of decision and fast action.
{"title":"Value Tracking Thru Digital Fields Countrywide Solution Big Data Analytics Project","authors":"A. Karim, Hairulirwan Abu Hassan, Sayyid M Izdihar Muslimin, Roberto Fuenmayor, Ammar Kamarulzaman, Mohamad Mustaqim Mokhlis","doi":"10.4043/31046-ms","DOIUrl":"https://doi.org/10.4043/31046-ms","url":null,"abstract":"\u0000 The Digital Field initiative is transforming the daily operations on the oilfield and it is now part of PETRONAS corporate wide digital strategy.\u0000 This transformation is done by onboarding multiple disciplines such as subsurface team, facilities, and operations, HSSE and Business Planning and is designed to replicates the performance of an oilfield in the computer, combining business process management and technical workflows. Digital Field has enabled the customer to execute their work collaboratively, by providing decision support system (technical workflows and business process management tools) subsequently improving their process efficiencies and optimizing their production. It is believed that by conducting a systematic review of the improvement and tracking the values that has been achieved, it will help to promote and accelerate digital adoption faster.\u0000 The main objectives of the Automated Value Tracking are:\u0000 To promote opportunity generation through collaborative environment. To track stages of every opportunity of the following categories of Production Optimization, Unplanned Deferment and Process Cycle Efficiencies. To quantify values associated with opportunities generated from automated workflows and current business process. To promote ownership of the actions associated with the assigned opportunity and to help to quantify on individual level contribution to the corporate goal in terms of production volume and time savings. To measures optimized number of opportunities generated against production volume associated with Production Optimization activity according to Field category and Quality of Opportunity Generated from Optimization Advisor.\u0000 The process is summarized as follow:\u0000 Opportunity generation: Automated opportunity generation generated through current Production Optimization Advisory framework. Integration with existing Petronas business process tools i.e. Daily Operational Tracking System, Alpha projects, Opportunity Management system, etc. Manual opportunity generation. Opportunity evaluation and analysis: Provide quantitatively confidence level of production incremental volume from automated Optimization Advisory through machine learning. Establish relationship between numbers of opportunity completed and categories versus production volume gain. Opportunity tracking and approval: Tracking the opportunity generation according to the process level. Escalating Opportunity and value recognition through business process approval.\u0000 This workflow helps to improve to understand the current update of the different levels such as well, field, region and upstream with the help of integrating the value realization and allows \"cards\" to show information that can trigger opportunities to increase production, reduce time of decision and fast action.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86898787","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}
Knut Olav Sønåsen, P. T. Moe, Morten Hansen, Dag André Fjeldstad, Halvor S. Gustad, A. Sadeghi, A. Hilley, A. Bjo̸rset
Operators working on shallow and mid-water depths in rough seas are focusing on reducing fatigue in the upper part of well systems during drilling operations. Fatigue is caused by cyclic bending moments due to wave induced riser and vessel motions. The combined use of a Reactive Flex-Joint (RFJ) and the Well Access Management System (WAMS) has demonstrated significantly reduced fatigue exposure through a reduction in loads, reporting of real-time status and rig positioning advice. The RFJ is a mechanism mounted on a standard flex joint for easy installation on drilling rigs. It uses a nitrogen gas spring to reverse the flex joint bending moment. The generated opposing moment increases with an increasing angle of the lower flex joint. This significantly reduces the cyclic bending moments in the lower part of the Blow Out Preventer (BOP) and wellhead (WH) system. WAMS is an advanced monitoring system that may be operated as a fully integrated part of the RFJ design. Sensors provide real-time data for flex joint angle, BOP inclination, wellhead- and riser bending moments. The data is used to assess incurring fatigue damage in real-time and for reporting fatigue status after operations. Two RFJ systems have been in continuous use on two separate rigs during 2020. The RFJ system and WAMS are field-proven and have demonstrated their efficiency in challenging operations in the Barents Sea and the North Sea. The RFJ has been well received in the market due to one-time installation, safe use, significant reduction in wellhead loads, and low operating expenses (OPEX). Data obtained from the operations have been carefully analyzed and show that the RFJ reduces cyclic loads from 50 to 80% resulting in 30 to as much as 1000 times extended fatigue life of the wellhead. The RFJ efficiency depends on the settings of the system and operational conditions.
{"title":"Significant Reduction of Well System Fatigue by Use of Reactive Flex Joint with Integrated Monitoring System","authors":"Knut Olav Sønåsen, P. T. Moe, Morten Hansen, Dag André Fjeldstad, Halvor S. Gustad, A. Sadeghi, A. Hilley, A. Bjo̸rset","doi":"10.4043/31265-ms","DOIUrl":"https://doi.org/10.4043/31265-ms","url":null,"abstract":"\u0000 Operators working on shallow and mid-water depths in rough seas are focusing on reducing fatigue in the upper part of well systems during drilling operations. Fatigue is caused by cyclic bending moments due to wave induced riser and vessel motions. The combined use of a Reactive Flex-Joint (RFJ) and the Well Access Management System (WAMS) has demonstrated significantly reduced fatigue exposure through a reduction in loads, reporting of real-time status and rig positioning advice.\u0000 The RFJ is a mechanism mounted on a standard flex joint for easy installation on drilling rigs. It uses a nitrogen gas spring to reverse the flex joint bending moment. The generated opposing moment increases with an increasing angle of the lower flex joint. This significantly reduces the cyclic bending moments in the lower part of the Blow Out Preventer (BOP) and wellhead (WH) system. WAMS is an advanced monitoring system that may be operated as a fully integrated part of the RFJ design. Sensors provide real-time data for flex joint angle, BOP inclination, wellhead- and riser bending moments. The data is used to assess incurring fatigue damage in real-time and for reporting fatigue status after operations.\u0000 Two RFJ systems have been in continuous use on two separate rigs during 2020. The RFJ system and WAMS are field-proven and have demonstrated their efficiency in challenging operations in the Barents Sea and the North Sea. The RFJ has been well received in the market due to one-time installation, safe use, significant reduction in wellhead loads, and low operating expenses (OPEX).\u0000 Data obtained from the operations have been carefully analyzed and show that the RFJ reduces cyclic loads from 50 to 80% resulting in 30 to as much as 1000 times extended fatigue life of the wellhead. The RFJ efficiency depends on the settings of the system and operational conditions.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86456351","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}
Enrique Barrios, Rafael Santos, Robin P. Hartmann, Vinícius Pessanha, R. Neves, Rodrigo Alves Pereira, Rodrigo Rodrigues Ribeiro, Thiago Schimmelpfennig
The Brazilian Pre-Salt has gained importance as an essential world-class province given its prolific production and thanks to its many challenges, it has incentivized the market to look for better ways to faces these technical challenges safely. This article aims to describe the main challenges faced by Shell and Constellation as well as the approach adopted to improve the operations’ safety and reduce drilling time, significantly reducing the drilling costs in an exploratory campaign in the Brazilian Pre-Salt. The campaign was based on the buildup of a partnership between the drilling contractor, operator and the main services provider, Halliburton, creating a transparent and collaborative environment, which improved all parties’ ownership and accountability. The application of many processes and techniques such as Step Seven, Stop Work Authority and Design of Work improved safety and efficiency. A precise equipment selection, detailed planning and careful execution with disciplined application of a learning mindset were also paramount to drilling performance. Four pre-salt wells were drilled in the campaign at Sul de Gato de Mato (2 wells), Alto de Cabo Frio and Saturno prospects with all of them qualifying in terms of drilling time as best in class (BIC), i.e., within the top 5% percentile. In 2019, the GdM3 well was the fastest delivery of a pre-salt well out of the 250+ wells in the region. The well GdM4 drilled in 2020 as part of the same campaign broke the previous record by seven days, being the fastest pre-salt well ever drilled with its 18 dry hole days mark. The main reason associated with the campaign´s success was the utilization of the DID-PDCA methodology, which promoted the integration of all the workforce in a cycle towards continuous improvement by: (i) carefully selecting the equipment and experienced service providers, (ii) generating detailed plans of the drilling activity and engaging all those involved in the delivery, (iii) establishing and applying a HSE strategy for safety culture enhanced and (iv) constantly monitoring of performance and discussing the next steps. Along this article a summary of well layout, the drilling phase duration, some of the key performance improvement initiatives as well as how they were generated will be shared.
由于巴西盐下油藏产量丰富，其作为世界级油田的重要性日益凸显，同时也面临着诸多挑战，这促使市场寻找更好的方法来安全地应对这些技术挑战。本文旨在描述壳牌和Constellation公司面临的主要挑战，以及在巴西盐下勘探活动中为提高作业安全性、缩短钻井时间、显著降低钻井成本所采取的方法。该活动建立在钻井承包商、运营商和主要服务提供商哈里伯顿之间的合作伙伴关系的基础上，创造了一个透明和协作的环境，提高了各方的所有权和问责制。许多流程和技术的应用，如第七步、停止工作权限和工作设计，提高了安全性和效率。精确的设备选择、详细的规划、仔细的执行以及严谨的学习心态对钻井性能也是至关重要的。在Sul de Gato de Mato(2口井)、Alto de Cabo Frio和Saturno区块，共钻了4口盐下井，所有井的钻井时间都达到了同类最佳(BIC)水平，即在前5%的范围内。2019年，GdM3井是该地区250多口井中交付速度最快的一口盐下井。作为同一活动的一部分，2020年钻探的GdM4井将之前的记录提前了7天，成为有史以来钻探速度最快的盐下井，达到了18个干井日。活动成功的主要原因是使用了DID-PDCA方法，该方法通过以下方式促进了所有劳动力在持续改进周期中的整合:(1)仔细选择设备和经验丰富的服务提供商，(2)制定钻井活动的详细计划，并让所有参与交付的人员参与进来，(3)建立和应用HSE战略，以加强安全文化，(4)不断监测性能并讨论下一步。在这篇文章中，我们将总结井的布局、钻井阶段的持续时间、一些关键的性能改进措施以及它们是如何产生的。
{"title":"Driving Superior Performance in Brazilian Pre-Salt - The Challenges, Solutions and Achievements of Shell and Providers in Exploratory Pre-Salt Wells in Brazil","authors":"Enrique Barrios, Rafael Santos, Robin P. Hartmann, Vinícius Pessanha, R. Neves, Rodrigo Alves Pereira, Rodrigo Rodrigues Ribeiro, Thiago Schimmelpfennig","doi":"10.4043/31004-ms","DOIUrl":"https://doi.org/10.4043/31004-ms","url":null,"abstract":"\u0000 The Brazilian Pre-Salt has gained importance as an essential world-class province given its prolific production and thanks to its many challenges, it has incentivized the market to look for better ways to faces these technical challenges safely. This article aims to describe the main challenges faced by Shell and Constellation as well as the approach adopted to improve the operations’ safety and reduce drilling time, significantly reducing the drilling costs in an exploratory campaign in the Brazilian Pre-Salt.\u0000 The campaign was based on the buildup of a partnership between the drilling contractor, operator and the main services provider, Halliburton, creating a transparent and collaborative environment, which improved all parties’ ownership and accountability. The application of many processes and techniques such as Step Seven, Stop Work Authority and Design of Work improved safety and efficiency. A precise equipment selection, detailed planning and careful execution with disciplined application of a learning mindset were also paramount to drilling performance.\u0000 Four pre-salt wells were drilled in the campaign at Sul de Gato de Mato (2 wells), Alto de Cabo Frio and Saturno prospects with all of them qualifying in terms of drilling time as best in class (BIC), i.e., within the top 5% percentile. In 2019, the GdM3 well was the fastest delivery of a pre-salt well out of the 250+ wells in the region. The well GdM4 drilled in 2020 as part of the same campaign broke the previous record by seven days, being the fastest pre-salt well ever drilled with its 18 dry hole days mark.\u0000 The main reason associated with the campaign´s success was the utilization of the DID-PDCA methodology, which promoted the integration of all the workforce in a cycle towards continuous improvement by: (i) carefully selecting the equipment and experienced service providers, (ii) generating detailed plans of the drilling activity and engaging all those involved in the delivery, (iii) establishing and applying a HSE strategy for safety culture enhanced and (iv) constantly monitoring of performance and discussing the next steps.\u0000 Along this article a summary of well layout, the drilling phase duration, some of the key performance improvement initiatives as well as how they were generated will be shared.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89765693","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}
Slug flow in multiphase flowlines can cause operational instabilities which, when severe, lead to mechanical damage or even shutdown of processing facilities. While a number of control schemes to handle slugging have been published, many of them require subsea instrumentation or make use of calculated "pseudo-variables" for control, values which have no real physical meaning. Hydrodynamic slugging was anticipated during design of a new facility in Angola, and a simulation study demonstrated that a control scheme from the published literature could be applied effectively to control the slugging. However, that solution was rejected because of the use of a pseudo-variable as the principal control point. Therefore, a novel control scheme was developed and tested on simulation for both hydrodynamic slugging and severe riser-induced slugging and later patented.(1,2) The project implemented the novel active slugging control using a topsides control valve and topsides instrumentation. While a pseudo-variable, a pseudo-flow controller, was employed, it was part of a cascade scheme such that the principal control variable was a real topside pressure measurement. Upon commissioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug control scheme was effective in controlling incoming slugs.
{"title":"Novel Active Slug Control in Angola - Development & Field Results","authors":"L. A. Brenskelle, Martin Morles, L. Flores","doi":"10.4043/31298-ms","DOIUrl":"https://doi.org/10.4043/31298-ms","url":null,"abstract":"\u0000 Slug flow in multiphase flowlines can cause operational instabilities which, when severe, lead to mechanical damage or even shutdown of processing facilities. While a number of control schemes to handle slugging have been published, many of them require subsea instrumentation or make use of calculated \"pseudo-variables\" for control, values which have no real physical meaning. Hydrodynamic slugging was anticipated during design of a new facility in Angola, and a simulation study demonstrated that a control scheme from the published literature could be applied effectively to control the slugging. However, that solution was rejected because of the use of a pseudo-variable as the principal control point. Therefore, a novel control scheme was developed and tested on simulation for both hydrodynamic slugging and severe riser-induced slugging and later patented.(1,2) The project implemented the novel active slugging control using a topsides control valve and topsides instrumentation. While a pseudo-variable, a pseudo-flow controller, was employed, it was part of a cascade scheme such that the principal control variable was a real topside pressure measurement. Upon commissioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug control scheme was effective in controlling incoming slugs.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75040627","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}
I. Pettigrew, Ashley Barker, Anthony O'Brien, Alex Cesan
Using Computed Tomography (CT) for 3D spatial analysis is a well-established technique primarily used in the fields of medical imaging and precision defect analysis of materials such as aircraft CT technology is gradually evolving for asset integrity within the Oil and Gas sector for two main applications: in-line inspection (ILI) verification and non-intrusive inspection (NII) of coated subsea pipelines. The CT scanning philosophy for both types of inspection challenges varies significantly and in this paper is considered in terms of alignment of inspection deliverables with scan definition. This paper explores the redesign of the traditional CT approach to optimize scanning for high-density target volumes by implementing a ground-up approach to all hardware and mathematics. The advanced algorithms used in the InspeCTTM technology enables a novel technique for image reconstruction; allowing for cleaner images than are possible using traditional CT whilst using less data and hence smaller radioactive sources. In addition, this paper demonstrates a selection of important findings from the InspeCTTM system qualification to API Standard 1163. To maximize the effectiveness of the subsea campaign, use of automated analysis is demonstrated to provide consistency in interpretation and reduce the considerable time demands of high-volume data analysis enabling any remediation decisions or change to inspection strategy to be actioned at the time of inspection rather on a future campaign.
{"title":"InspectTM Computed Tomography for NDT of Subsea Pipelines","authors":"I. Pettigrew, Ashley Barker, Anthony O'Brien, Alex Cesan","doi":"10.4043/30949-ms","DOIUrl":"https://doi.org/10.4043/30949-ms","url":null,"abstract":"\u0000 Using Computed Tomography (CT) for 3D spatial analysis is a well-established technique primarily used in the fields of medical imaging and precision defect analysis of materials such as aircraft CT technology is gradually evolving for asset integrity within the Oil and Gas sector for two main applications: in-line inspection (ILI) verification and non-intrusive inspection (NII) of coated subsea pipelines. The CT scanning philosophy for both types of inspection challenges varies significantly and in this paper is considered in terms of alignment of inspection deliverables with scan definition.\u0000 This paper explores the redesign of the traditional CT approach to optimize scanning for high-density target volumes by implementing a ground-up approach to all hardware and mathematics. The advanced algorithms used in the InspeCTTM technology enables a novel technique for image reconstruction; allowing for cleaner images than are possible using traditional CT whilst using less data and hence smaller radioactive sources. In addition, this paper demonstrates a selection of important findings from the InspeCTTM system qualification to API Standard 1163.\u0000 To maximize the effectiveness of the subsea campaign, use of automated analysis is demonstrated to provide consistency in interpretation and reduce the considerable time demands of high-volume data analysis enabling any remediation decisions or change to inspection strategy to be actioned at the time of inspection rather on a future campaign.","PeriodicalId":11084,"journal":{"name":"Day 4 Thu, August 19, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74413977","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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