This paper discusses both technical and project management aspects of drilling fluids services for deepwater and high pressure high temperature (HPHT) offshore drilling projects. The technical discussion part includes deepwater and HPHT specific fluids related concerns such as logistics, narrow drilling window, shallow hazards, gas hydrates, HPHT conditions and low temperature rheology; together with practical solutions for each of them. As some of these challenges cannot be met by only fluids itself, technologies such as managed pressure drilling (MPD), dual-gradient drilling (DGD) and use of special downhole tools are also included in the discussions. The project management aspect is covered for both the planning and execution phases. A newly developed Four Stage Planning Guideline (4SPG) with a recommended timetable is proposed for high-profile offshore drilling projects. Starting from fluids selection to preparation of the contingency plans is discussed in detail for the planning phase. Execution phase is discussed mainly for service company representatives on how to follow main or contingency plans effectively and ensure good communication is achieved with all parties involved. Work model presented in this paper can be used as a complete guideline by operating and service company representatives in order to increase the success rate of these high-risk offshore drilling projects and ensure learnings are captured in a structured way for continuous improvement.
{"title":"Drilling Fluids Project Engineering Guidance and Most Common Fluids Related Challenges for Deepwater and HPHT Offshore Wells","authors":"A. Ay, H. A. Dogan, A. Sonmez","doi":"10.4043/31179-ms","DOIUrl":"https://doi.org/10.4043/31179-ms","url":null,"abstract":"\u0000 This paper discusses both technical and project management aspects of drilling fluids services for deepwater and high pressure high temperature (HPHT) offshore drilling projects.\u0000 The technical discussion part includes deepwater and HPHT specific fluids related concerns such as logistics, narrow drilling window, shallow hazards, gas hydrates, HPHT conditions and low temperature rheology; together with practical solutions for each of them. As some of these challenges cannot be met by only fluids itself, technologies such as managed pressure drilling (MPD), dual-gradient drilling (DGD) and use of special downhole tools are also included in the discussions.\u0000 The project management aspect is covered for both the planning and execution phases. A newly developed Four Stage Planning Guideline (4SPG) with a recommended timetable is proposed for high-profile offshore drilling projects. Starting from fluids selection to preparation of the contingency plans is discussed in detail for the planning phase. Execution phase is discussed mainly for service company representatives on how to follow main or contingency plans effectively and ensure good communication is achieved with all parties involved.\u0000 Work model presented in this paper can be used as a complete guideline by operating and service company representatives in order to increase the success rate of these high-risk offshore drilling projects and ensure learnings are captured in a structured way for continuous improvement.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 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":"72560041","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}
Nikhil P. Joshi, Jonathan Lewis Brewer, Christopher J. Rose
During the annual In-Service Inspection of a spar hull, several regions of pitting corrosion on the upper portion of the north and south moon pool external wall plating were identified. The moon pool walls are constructed as typical stiffened panel structures. Visual, ultrasonic (UT), and pulsed eddy current (PEC) inspections indicated regions of corrosion with roughly 40% to 70% averaged localized wall loss. This paper discusses the analytical assessment of the structure to determine the effect of the corrosion on the structural integrity of the moon pool wall and any similar structural panel. To determine the impact of corrosion on the stiffened panel integrity, a finite element (FE) based analysis approach is used to perform a comparative assessment of the "as-built" and "corroded" configuration of the moon pool wall. The nominal plate and stiffener thicknesses are modeled in the "as-built" configuration; whereas, the measured plate thickness from the inspection is modeled in the "corroded" configuration. The structure is subjected to design loads based on the storm damaged design condition. The analysis is performed by uniformly increasing the applied loads until failure occurs, maintaining a constant ratio between the nominal loads. Two different analyses are performed as a part of the strength assessment: (1) a linear-elastic eigenvalue analysis to estimate the elastic buckling capacity and mode shapes of the structure and (2) an elastic-plastic post-buckling analysis to estimate the ultimate capacity of the structure. In addition, the results from the linear-elastic eigenvalue analysis are compared to the results from analytical buckling calculations. The analysis results indicate that the corrosion reduces the elastic plate buckling capacity significantly. However, the overall capacity of the stiffened panel is not significantly reduced. Therefore, from a global strength perspective, the stiffened panel remains acceptable in its corroded condition. The upper portion of the moon pool wall is typically fatigue insensitive in spars. Therefore, the effect of the corrosion wall loss on the fatigue performance was not assessed. Since there is limited guidance in design and assessment codes for assessing corroded stiffened panels, this approach can be used to address future stiffened panel corrosion wall loss. In addition, this method allows for inclusion of future corrosion allowance, if applicable. Determining the capacity of corroded panels using FEA-based numerical methods, like those described in this paper, allows the operators to manage their risks, repair costs, and inspection frequency by determining the actual capacity of the damaged components. This allows the operators to determine the appropriate mitigation measures based on a quantitative risk calculation.
{"title":"Rational Approach to Assess the Effect of Corrosion on Stiffened Panel Buckling and Ultimate Capacity","authors":"Nikhil P. Joshi, Jonathan Lewis Brewer, Christopher J. Rose","doi":"10.4043/31021-ms","DOIUrl":"https://doi.org/10.4043/31021-ms","url":null,"abstract":"\u0000 During the annual In-Service Inspection of a spar hull, several regions of pitting corrosion on the upper portion of the north and south moon pool external wall plating were identified. The moon pool walls are constructed as typical stiffened panel structures. Visual, ultrasonic (UT), and pulsed eddy current (PEC) inspections indicated regions of corrosion with roughly 40% to 70% averaged localized wall loss. This paper discusses the analytical assessment of the structure to determine the effect of the corrosion on the structural integrity of the moon pool wall and any similar structural panel.\u0000 To determine the impact of corrosion on the stiffened panel integrity, a finite element (FE) based analysis approach is used to perform a comparative assessment of the \"as-built\" and \"corroded\" configuration of the moon pool wall. The nominal plate and stiffener thicknesses are modeled in the \"as-built\" configuration; whereas, the measured plate thickness from the inspection is modeled in the \"corroded\" configuration. The structure is subjected to design loads based on the storm damaged design condition. The analysis is performed by uniformly increasing the applied loads until failure occurs, maintaining a constant ratio between the nominal loads. Two different analyses are performed as a part of the strength assessment: (1) a linear-elastic eigenvalue analysis to estimate the elastic buckling capacity and mode shapes of the structure and (2) an elastic-plastic post-buckling analysis to estimate the ultimate capacity of the structure. In addition, the results from the linear-elastic eigenvalue analysis are compared to the results from analytical buckling calculations.\u0000 The analysis results indicate that the corrosion reduces the elastic plate buckling capacity significantly. However, the overall capacity of the stiffened panel is not significantly reduced. Therefore, from a global strength perspective, the stiffened panel remains acceptable in its corroded condition. The upper portion of the moon pool wall is typically fatigue insensitive in spars. Therefore, the effect of the corrosion wall loss on the fatigue performance was not assessed.\u0000 Since there is limited guidance in design and assessment codes for assessing corroded stiffened panels, this approach can be used to address future stiffened panel corrosion wall loss. In addition, this method allows for inclusion of future corrosion allowance, if applicable. Determining the capacity of corroded panels using FEA-based numerical methods, like those described in this paper, allows the operators to manage their risks, repair costs, and inspection frequency by determining the actual capacity of the damaged components. This allows the operators to determine the appropriate mitigation measures based on a quantitative risk calculation.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81626783","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}
E. Stensrud, Are Torstensen, D. Lillestøl, Kristian Klausen
The Class Society DNV has performed production surveys in enclosed spaces using drones since 2016, demonstrating cost savings and increased personnel safety. The goal is to develop autonomous inspection drones to reduce the need to enter tanks and enable remote inspection. The vision is a drone that can fly by itself, track where it is, and spot rust and cracks, and measure steel thickness. We expect that drone-assisted remote inspection will reduce survey costs for the clients and be a major safety improvement for surveyors. Several drone capabilities are required to enable visual close-up inspection and non-destructive testing in enclosed, GPS-denied, and poorly lit environments. In this study, we report the most recent status from an ongoing research project, including several industry partners. We highlight technical challenges and preliminary results on drone navigation functionalities, computer vision for detection of cracks, and the use of hyperspectral imaging to detect and classify the chemical composition of coatings, rust, and other use cases.
{"title":"Towards Remote Inspections of FPSO's Using Drones Instrumented with Computer Vision and Hyperspectral Imaging","authors":"E. Stensrud, Are Torstensen, D. Lillestøl, Kristian Klausen","doi":"10.4043/30939-ms","DOIUrl":"https://doi.org/10.4043/30939-ms","url":null,"abstract":"\u0000 The Class Society DNV has performed production surveys in enclosed spaces using drones since 2016, demonstrating cost savings and increased personnel safety. The goal is to develop autonomous inspection drones to reduce the need to enter tanks and enable remote inspection. The vision is a drone that can fly by itself, track where it is, and spot rust and cracks, and measure steel thickness. We expect that drone-assisted remote inspection will reduce survey costs for the clients and be a major safety improvement for surveyors. Several drone capabilities are required to enable visual close-up inspection and non-destructive testing in enclosed, GPS-denied, and poorly lit environments. In this study, we report the most recent status from an ongoing research project, including several industry partners. We highlight technical challenges and preliminary results on drone navigation functionalities, computer vision for detection of cracks, and the use of hyperspectral imaging to detect and classify the chemical composition of coatings, rust, and other use cases.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73292588","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. Cutrim, C. O. Souza, Bruno Sergio Pimentel De Souza
As a general practice in the oil and gas industry, the well foundation, composed by the conductor and the surface casing, is designed with a strict tolerance regarding cement shortfall on the surface casing. However, in a pre-salt scenario, in order to reduce the costs of well construction, the surface casing shoe generally reaches the top of salt. In this case, it is quite hard to make the cement job reach the mudline due to problems like salt dissolution (generating high calipers) and presence of many geological faults in the post-salt zone (which can work as a lost circulation area). Besides that, an evaluation of the wellhead movement is necessary so that the structural restrictions of subsea equipment connected to the wellhead are not violated. This work had the goal of presenting a coupled structural model to analyze the foundation of a subsea well with a partially cemented surface casing, where the safety factors of surface casing are evaluated in the whole well life cycle along with the wellhead movement due to the loads related to each step of this cycle. A sensitivity analysis on the top of cement (measured from the casing shoe) is made, varying it from 300 m to 800 m. The results showed wellhead movement consistent with what is observed in the field, once no axial movement has been reported. Additionally, it was highlighted that the foundation design depends on the operations during the well construction and its future purpose, production or injection, because the thermal loads associated with operations have different impacts.
{"title":"Wellhead Movement Analysis and Surface Casing Integrity in Pre-Salt Wells","authors":"F. Cutrim, C. O. Souza, Bruno Sergio Pimentel De Souza","doi":"10.4043/30957-ms","DOIUrl":"https://doi.org/10.4043/30957-ms","url":null,"abstract":"\u0000 As a general practice in the oil and gas industry, the well foundation, composed by the conductor and the surface casing, is designed with a strict tolerance regarding cement shortfall on the surface casing. However, in a pre-salt scenario, in order to reduce the costs of well construction, the surface casing shoe generally reaches the top of salt. In this case, it is quite hard to make the cement job reach the mudline due to problems like salt dissolution (generating high calipers) and presence of many geological faults in the post-salt zone (which can work as a lost circulation area). Besides that, an evaluation of the wellhead movement is necessary so that the structural restrictions of subsea equipment connected to the wellhead are not violated.\u0000 This work had the goal of presenting a coupled structural model to analyze the foundation of a subsea well with a partially cemented surface casing, where the safety factors of surface casing are evaluated in the whole well life cycle along with the wellhead movement due to the loads related to each step of this cycle. A sensitivity analysis on the top of cement (measured from the casing shoe) is made, varying it from 300 m to 800 m.\u0000 The results showed wellhead movement consistent with what is observed in the field, once no axial movement has been reported. Additionally, it was highlighted that the foundation design depends on the operations during the well construction and its future purpose, production or injection, because the thermal loads associated with operations have different impacts.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88881179","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}
Riser base gas lift is conventionally used in deep water fields to minimize backpressure on wells, smooth start-up transients, and mitigate slugging in the flowline-riser system which can cause disruption in the topside facilities. The effectiveness of riser base gas lift depends on several factors, such as the reservoir performance, the fluid properties, the field architecture, and the topography. There are several technical solutions available to deliver the lift gas to the riser base. Such technical solutions differ in terms of lift-gas supply method (distributed vs point-to-point), riser specifications, and overall system complexity. The selection of technical solution has the potential for minimizing infrastructure. Available solutions include bundled risers and concentric riser configurations that allow gas lift functions to be integrated with the main production conduit. The evaluation of riser base gas lift effectiveness and the selection of the most appropriate technical solution is typically performed early in the field development cycle. This paper presents a review of the available subsea gas lift technical solutions and discusses an evaluation process, including criteria for the selection of the most appropriate solution. The presented case study assumes a deep water Gulf of Mexico field, in which the main subsea system consists of two wet insulated piggable flowline loops. Key decision drivers were flow assurance requirements, complexity, operability, impact on field layout, interfaces, installation, and schedule are discussed. This holistic approach aids the selection of the most appropriate riser base gas lift system in the early field development cycle.
{"title":"Design Perspectives for Selection of Subsea Gas Lift Technology for Deep Water Fields","authors":"Ligia Tornisiello, S. Taxy, Rick Curto","doi":"10.4043/31108-ms","DOIUrl":"https://doi.org/10.4043/31108-ms","url":null,"abstract":"\u0000 Riser base gas lift is conventionally used in deep water fields to minimize backpressure on wells, smooth start-up transients, and mitigate slugging in the flowline-riser system which can cause disruption in the topside facilities. The effectiveness of riser base gas lift depends on several factors, such as the reservoir performance, the fluid properties, the field architecture, and the topography. There are several technical solutions available to deliver the lift gas to the riser base. Such technical solutions differ in terms of lift-gas supply method (distributed vs point-to-point), riser specifications, and overall system complexity. The selection of technical solution has the potential for minimizing infrastructure. Available solutions include bundled risers and concentric riser configurations that allow gas lift functions to be integrated with the main production conduit. The evaluation of riser base gas lift effectiveness and the selection of the most appropriate technical solution is typically performed early in the field development cycle. This paper presents a review of the available subsea gas lift technical solutions and discusses an evaluation process, including criteria for the selection of the most appropriate solution. The presented case study assumes a deep water Gulf of Mexico field, in which the main subsea system consists of two wet insulated piggable flowline loops. Key decision drivers were flow assurance requirements, complexity, operability, impact on field layout, interfaces, installation, and schedule are discussed. This holistic approach aids the selection of the most appropriate riser base gas lift system in the early field development cycle.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90568055","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}
Olatunji Adeola, Kolby Burmaster, M. Phi, S. Arnold, Alexander Robinson, Jackson Klein
The ExxonMobil Wells organization, along with Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, executed a successful multi-rig campaign to achieve First Oil on the Liza Phase 1 project ahead of schedule, utilizing advanced deepwater completion technologies to deliver highly productive wells. Considering the sizable resource offshore Guyana, strategic partnerships have been established with drilling contractors and other service providers to build economies-of-scale. ExxonMobil's prior global experience is actively being leveraged in rig selection and well design. Standardization, both above and below the rotary, has allowed for increased flexibility on current and future well execution, maintaining optionality to rapidly adjust project pace. A deliberate contracting strategy with established rig providers has also opened access to top tier rigs with reduced procurement timelines, providing flexibility with total rig count and capability. With an integrated team approach focused on simulataneous operations (SIMOPS) mitigation, rig movements have been optimized within the field to prioritize the highest value work and streamline project delivery. Effective schedule integration with multiple drilling rigs and installation vessels has reduced SIMOPS downtime during Phase 1 project execution. Additionally, batch rig operations have allowed the team to capitalize on operational efficiencies. A combination of these factors led to on-time well delivery and helped the project achieve aggressive First Oil milestones. The team has implemented innovative technologies to maximize value and well reliability, including the following: integrated geosteering workflows, with Azimuthal Ultra-Deep Resistivity (AUDR), enabling maximum reservoir penetrations; a suite of low equivalent circulating density (ECD) drilling fluids that enable the drilling of narrow-margin, highly deviated wells; ExxonMobil's patented NAFPac™ openhole gravel pack technology and autonomous inflow control devices (AICDs) on stand-alone-screen completions to increase well life and reliability; and remotely operated vehicle (ROV) based tree intervention control systems and ROV actuated suspension valves allowing for offline installation of subsea trees. Additionally, the team implemented the first floating application of the NOVOS™ automated slip-to-slip drilling system. NOVOS™ has been coupled with an automated drilling advisory system (AutoDAS) and data analytics environments for continuous performance improvement. The production wells that were delivered for Liza Phase 1 have highly productive, low-skin completions averaging over 900 m in length and production rates in excess of 30 kbd/well. Advancements in completion technology and efficiency proven on Liza Phase 1 are being extended into Phase 2 development and beyond, providing additional reservoir management capability. Lastly, ExxonMobil's commitment to Guyana extends to its people. Guyanese personnel have benef
{"title":"Drilling Execution and Completion Advancements Continue to Deliver for Guyana","authors":"Olatunji Adeola, Kolby Burmaster, M. Phi, S. Arnold, Alexander Robinson, Jackson Klein","doi":"10.4043/31230-ms","DOIUrl":"https://doi.org/10.4043/31230-ms","url":null,"abstract":"\u0000 The ExxonMobil Wells organization, along with Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, executed a successful multi-rig campaign to achieve First Oil on the Liza Phase 1 project ahead of schedule, utilizing advanced deepwater completion technologies to deliver highly productive wells. Considering the sizable resource offshore Guyana, strategic partnerships have been established with drilling contractors and other service providers to build economies-of-scale.\u0000 ExxonMobil's prior global experience is actively being leveraged in rig selection and well design. Standardization, both above and below the rotary, has allowed for increased flexibility on current and future well execution, maintaining optionality to rapidly adjust project pace. A deliberate contracting strategy with established rig providers has also opened access to top tier rigs with reduced procurement timelines, providing flexibility with total rig count and capability. With an integrated team approach focused on simulataneous operations (SIMOPS) mitigation, rig movements have been optimized within the field to prioritize the highest value work and streamline project delivery. Effective schedule integration with multiple drilling rigs and installation vessels has reduced SIMOPS downtime during Phase 1 project execution. Additionally, batch rig operations have allowed the team to capitalize on operational efficiencies. A combination of these factors led to on-time well delivery and helped the project achieve aggressive First Oil milestones.\u0000 The team has implemented innovative technologies to maximize value and well reliability, including the following: integrated geosteering workflows, with Azimuthal Ultra-Deep Resistivity (AUDR), enabling maximum reservoir penetrations; a suite of low equivalent circulating density (ECD) drilling fluids that enable the drilling of narrow-margin, highly deviated wells; ExxonMobil's patented NAFPac™ openhole gravel pack technology and autonomous inflow control devices (AICDs) on stand-alone-screen completions to increase well life and reliability; and remotely operated vehicle (ROV) based tree intervention control systems and ROV actuated suspension valves allowing for offline installation of subsea trees. Additionally, the team implemented the first floating application of the NOVOS™ automated slip-to-slip drilling system. NOVOS™ has been coupled with an automated drilling advisory system (AutoDAS) and data analytics environments for continuous performance improvement.\u0000 The production wells that were delivered for Liza Phase 1 have highly productive, low-skin completions averaging over 900 m in length and production rates in excess of 30 kbd/well. Advancements in completion technology and efficiency proven on Liza Phase 1 are being extended into Phase 2 development and beyond, providing additional reservoir management capability.\u0000 Lastly, ExxonMobil's commitment to Guyana extends to its people. Guyanese personnel have benef","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91295362","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}
Machine Learning is an artificial intelligence subprocess applied to automatically and quickly perform mathematical calculations to data in order to build models used to make predictions. Technical papers related to machine learning algorithms applications have being increasingly published in many oil and gas disciplines over the last five years, revolutionizing the way engineers approach to their works, and sharing innovating solutions that contributes to an increase in efficiency. In this paper, Machine Learning models are built to predict inverse rate of penetration (ROPI) and surface torque for a well located at Gulf of Mexico shallow waters. Three type of analysis were performed. Pre-drill analysis, predicting the parameters without any data of the target well in the database. Drilling analysis, running the model every sixty meters, updating the database with information of the target well and predicting the parameters ahead the bit. Sensitivity parameter optimization analysis was performed iterating weight on bit and rotary speed values as model inputs in order identify the optimum combination to deliver the best drilling performance under the given conditions. The Extreme Gradient Boosting (XGBoost) library in Python programming language environment, was used to build the models. Model performance was satisfactory, overcoming the challenge of using drilling parameters input manually by drilling bit engineers. The database was built with data from different fields and wells. Two databases were created to build the models, one of the models did not consider logging while drilling (LWD) data in order to determine its importance on the predictions. Pre-drill surface torque prediction showed better performance than ROPI. Predictions ahead the bit performance was good both for torque and ROPI. Sensitivity parameter optimization showed better resolution with the database that includes LWD data.
{"title":"Drilling Optimization Applying Machine Learning Regression Algorithms","authors":"Freddy J. Marquez","doi":"10.4043/30934-ms","DOIUrl":"https://doi.org/10.4043/30934-ms","url":null,"abstract":"\u0000 Machine Learning is an artificial intelligence subprocess applied to automatically and quickly perform mathematical calculations to data in order to build models used to make predictions. Technical papers related to machine learning algorithms applications have being increasingly published in many oil and gas disciplines over the last five years, revolutionizing the way engineers approach to their works, and sharing innovating solutions that contributes to an increase in efficiency.\u0000 In this paper, Machine Learning models are built to predict inverse rate of penetration (ROPI) and surface torque for a well located at Gulf of Mexico shallow waters. Three type of analysis were performed. Pre-drill analysis, predicting the parameters without any data of the target well in the database. Drilling analysis, running the model every sixty meters, updating the database with information of the target well and predicting the parameters ahead the bit. Sensitivity parameter optimization analysis was performed iterating weight on bit and rotary speed values as model inputs in order identify the optimum combination to deliver the best drilling performance under the given conditions.\u0000 The Extreme Gradient Boosting (XGBoost) library in Python programming language environment, was used to build the models. Model performance was satisfactory, overcoming the challenge of using drilling parameters input manually by drilling bit engineers. The database was built with data from different fields and wells. Two databases were created to build the models, one of the models did not consider logging while drilling (LWD) data in order to determine its importance on the predictions.\u0000 Pre-drill surface torque prediction showed better performance than ROPI. Predictions ahead the bit performance was good both for torque and ROPI. Sensitivity parameter optimization showed better resolution with the database that includes LWD data.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90845626","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}
C. Webb, A. Sarabi, D. Constantinis, Travis Harley Anthony
The Bijupira and Salema oil fields in the Campos Basin, Brazil, are tied-back to the FPSO Fluminense. The design life of FPSO Fluminense was 15 years, first oil was in 2003. In 2017, Shell as operator and partner Petrobras decided to execute a 5 year life extension project to extend production until 2023. Although the life extension project encompassed many vessel, moorings, and production facility renovation projects, this paper will focus on the repairs of cracks in the wetted surfaces of the hull. Crack repairs were executed during production operations using a novel methodology designed to eliminate the risks of diving operations, while significantly reducing the costs of the offshore hull repairs. Earlier attempts using traditional methods with divers to deploy cofferdams were unsuccessful due to the high safety risk of diving in the persistent 2-plus knot Brazil current. In early 2019, the operator and a team of engineering consultants concluded that a novel repair approach that eliminates diving operations was feasible. The concept methodology was developed, one element of which included positioning and securing a cofferdam over a cracked area of the FPSO side shell. The cofferdam was lowered from the FPSO deck while being guided into position and secured in place by guide wires passed through holes in the side shell. Water ingress into the void spaces was eliminated via a hot tap and winching system that penetrates the side shell from inside the tank. Following the concept development, a step-by-step procedure was written, vetted with the classification society and subsequently used in the tendering process to select an execution contractor. The selected execution contractor constructed a test tank that replicated the actual hull structure. The prototype was used to test the method at full scale, including procedures, communication protocols, and equipment. The learnings were incorporated into both the procedures and equipment. This process was repeated as a training exercise for the offshore personnel and HSSE leaders prior to offshore execution. The execution contractor was mobilized offshore in the first quarter of 2020 and successfully performed the hull repairs. The job was completed as planned, including removal and replacement of several independent sections of stiffened hull plating, which included both flat and curved surfaces. Based upon successful execution, this method has been proven to be a technology that can be used to eliminate the risks of diving and to significantly reduce the costs of future offshore hull repairs. This paper will address the methodical approach taken to develop and integrate the various elements of this novel technology developed jointly by the operator and consultants, as well as the phases testing, pre-mobilization surveys, project execution, and other activities that drive success.
{"title":"A Safe and Cost Effective Diverless Method for Hull Wetted Surface Side Shell Repairs Executed On FPSO Fluminense","authors":"C. Webb, A. Sarabi, D. Constantinis, Travis Harley Anthony","doi":"10.4043/31055-ms","DOIUrl":"https://doi.org/10.4043/31055-ms","url":null,"abstract":"\u0000 The Bijupira and Salema oil fields in the Campos Basin, Brazil, are tied-back to the FPSO Fluminense. The design life of FPSO Fluminense was 15 years, first oil was in 2003. In 2017, Shell as operator and partner Petrobras decided to execute a 5 year life extension project to extend production until 2023. Although the life extension project encompassed many vessel, moorings, and production facility renovation projects, this paper will focus on the repairs of cracks in the wetted surfaces of the hull.\u0000 Crack repairs were executed during production operations using a novel methodology designed to eliminate the risks of diving operations, while significantly reducing the costs of the offshore hull repairs.\u0000 Earlier attempts using traditional methods with divers to deploy cofferdams were unsuccessful due to the high safety risk of diving in the persistent 2-plus knot Brazil current. In early 2019, the operator and a team of engineering consultants concluded that a novel repair approach that eliminates diving operations was feasible.\u0000 The concept methodology was developed, one element of which included positioning and securing a cofferdam over a cracked area of the FPSO side shell. The cofferdam was lowered from the FPSO deck while being guided into position and secured in place by guide wires passed through holes in the side shell. Water ingress into the void spaces was eliminated via a hot tap and winching system that penetrates the side shell from inside the tank.\u0000 Following the concept development, a step-by-step procedure was written, vetted with the classification society and subsequently used in the tendering process to select an execution contractor.\u0000 The selected execution contractor constructed a test tank that replicated the actual hull structure. The prototype was used to test the method at full scale, including procedures, communication protocols, and equipment. The learnings were incorporated into both the procedures and equipment. This process was repeated as a training exercise for the offshore personnel and HSSE leaders prior to offshore execution.\u0000 The execution contractor was mobilized offshore in the first quarter of 2020 and successfully performed the hull repairs. The job was completed as planned, including removal and replacement of several independent sections of stiffened hull plating, which included both flat and curved surfaces.\u0000 Based upon successful execution, this method has been proven to be a technology that can be used to eliminate the risks of diving and to significantly reduce the costs of future offshore hull repairs.\u0000 This paper will address the methodical approach taken to develop and integrate the various elements of this novel technology developed jointly by the operator and consultants, as well as the phases testing, pre-mobilization surveys, project execution, and other activities that drive success.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90451442","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}
S. Bhat, Varadarajan Nadathur, D. Knezevic, P. Aalberts, H. Kolsters, Daniel Amuda, Orobome Atebe, D. Pasala, Tuyen Hoang, T. Luong, Phuong Huynh, Riccardo Righetti, R. Hageman, Jim Yu
A high-fidelity FPSO Structural Digital Twin (SDT) based on Reduced Basis Finite Element Analysis (RB-FEA) coupled with inspection data and physical sensor measurements (advisory hull monitoring system) is presented to demonstrate a complete FPSO "digital thread" that combines operational data feeds, detailed structural analysis based on as-is asset condition, and automated structural integrity reporting. This lays the groundwork for a philosophical shift for asset lifecycle management by enabling the use of "as-measured" conditions in lieu of assumed "design-conditions" for a more accurate, and robust understanding of asset health. We demonstrate the deployment of this methodology for the Bonga FPSO and discuss the value that it brings during day-to-day operations.
{"title":"Structural Digital Twin of FPSO for Monitoring the Hull and Topsides Based on Inspection Data and Load Measurement","authors":"S. Bhat, Varadarajan Nadathur, D. Knezevic, P. Aalberts, H. Kolsters, Daniel Amuda, Orobome Atebe, D. Pasala, Tuyen Hoang, T. Luong, Phuong Huynh, Riccardo Righetti, R. Hageman, Jim Yu","doi":"10.4043/31328-ms","DOIUrl":"https://doi.org/10.4043/31328-ms","url":null,"abstract":"\u0000 A high-fidelity FPSO Structural Digital Twin (SDT) based on Reduced Basis Finite Element Analysis (RB-FEA) coupled with inspection data and physical sensor measurements (advisory hull monitoring system) is presented to demonstrate a complete FPSO \"digital thread\" that combines operational data feeds, detailed structural analysis based on as-is asset condition, and automated structural integrity reporting. This lays the groundwork for a philosophical shift for asset lifecycle management by enabling the use of \"as-measured\" conditions in lieu of assumed \"design-conditions\" for a more accurate, and robust understanding of asset health. We demonstrate the deployment of this methodology for the Bonga FPSO and discuss the value that it brings during day-to-day operations.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 2021","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-08-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72787615","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}
Subsea flexible pipelines removal is subject to order restrictions, mostly caused by crossings. It is proposed to create a computational algorithm to design an optimal order of vessel intervention over a field. A real field was studied, and, from it, the mathematical base model was created upon graph theory, with great correlation with the minimum feedback arc set problem. Vessel movements were discretized and reduced to removal, reposition, and cut, leading to a state search. A-star algorithm was implemented to guide the search for the solution. Then, the complete algorithm was built, tested in a minimal environment, and finally applied to the real instance. To improve performance, a beam search filtering was envisioned, using seven ranking functions. Constructed model is suspected to be NP-hard, by correlation to minimum feedback arc set problem, leading to a large space search. Instances containing under 100 crossings were solved optimally, without needing any assistance. After implementing the heuristics and beam search, solution time was lowered by about 20 times, demonstrating the effectiveness of the technique. Also, ranking functions for pipe repositioning based on crossing count led to better results than crossing density. For cutting, an approximation based on feedback arc set was used. GreedyFAS was employed and gave satisfactory results. Bigger instances containing around 3000 crossings could not be solved optimally in a reasonable time, even with the heuristics. Improvements in A-star estimation function and bound the solution branches might lead to an optimal solution for these larger instances. Model proposed simplifies the operational order decisions and helps build the scheduling of operations. As it is based on state search, other aspects in logistics, vessel capacities and steps in decommissioning processes may be added, adjusting the neighboring weights and branching, keeping the same core.
{"title":"Task Scheduling for Subsea Flexible Pipes Decommissioning","authors":"R. Bressan, Danilo Artigas","doi":"10.4043/31066-ms","DOIUrl":"https://doi.org/10.4043/31066-ms","url":null,"abstract":"\u0000 Subsea flexible pipelines removal is subject to order restrictions, mostly caused by crossings. It is proposed to create a computational algorithm to design an optimal order of vessel intervention over a field. A real field was studied, and, from it, the mathematical base model was created upon graph theory, with great correlation with the minimum feedback arc set problem. Vessel movements were discretized and reduced to removal, reposition, and cut, leading to a state search. A-star algorithm was implemented to guide the search for the solution. Then, the complete algorithm was built, tested in a minimal environment, and finally applied to the real instance. To improve performance, a beam search filtering was envisioned, using seven ranking functions. Constructed model is suspected to be NP-hard, by correlation to minimum feedback arc set problem, leading to a large space search. Instances containing under 100 crossings were solved optimally, without needing any assistance. After implementing the heuristics and beam search, solution time was lowered by about 20 times, demonstrating the effectiveness of the technique. Also, ranking functions for pipe repositioning based on crossing count led to better results than crossing density. For cutting, an approximation based on feedback arc set was used. GreedyFAS was employed and gave satisfactory results. Bigger instances containing around 3000 crossings could not be solved optimally in a reasonable time, even with the heuristics. Improvements in A-star estimation function and bound the solution branches might lead to an optimal solution for these larger instances. Model proposed simplifies the operational order decisions and helps build the scheduling of operations. As it is based on state search, other aspects in logistics, vessel capacities and steps in decommissioning processes may be added, adjusting the neighboring weights and branching, keeping the same core.","PeriodicalId":11072,"journal":{"name":"Day 1 Mon, August 16, 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":"81901291","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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