Scott Patrick Ellisor, R. A. Queiroz, Carlos Eduardo Martins Gaban, Guilherme Pedro Eppinghaus, B. N. Lucci
The oil and gas industry continues to face the need to reduce risk and the overall cost of operations as a means to compensate for lower oil prices. Conventional designs and methods are economically infeasible when drilling offshore in the current economic environment pushing the manufacturer to re-evaluate how to reduce risk and drive down costs. This paper describes a new and advanced way to drive down cost and reduce risk while drilling by reducing the number of trips into the well, adding significant value to the end user. The subsea wellhead system functions in a dynamic, complex environment; however, the qualification process of this system commonly employs relatively static test fixtures. These critical seal/casing hanger barriers within this wellhead system are presented, discussed and shown with exhaustive validation efforts necessary to evaluate relevant failure modes. Within the wellhead system, loads are typically resultant of a combined state including pressure and temperature. The validation of these components is aimed at defining the performance of the system in these states while detailing the limitations that one performance aspect may have on another. (Brown, 2017) This wellhead system offers reduced cost, simplified installation procedures and lower operational risk. Traditionally, a wellhead system would require a drilling lockdown sleeve during the drilling operations; however, prior to running the lockdown sleeve, many additional trips are made into the well to verify the position of the hanger in the wellhead. By eliminating the lockdown sleeve, the operator will save multiple trips into the well, therefore, reducing NPT and cost of operations. This is proven by performing well-defined subsea seal/casing hanger testing validation to accurately simulate the installed configuration. Because of this innovative seal assembly design, development of a single trip lock down sleeve was designed for wellhead systems requiring extremely high lock down requirements. The lock down sleeve does not require a trip with a Lead Impression Tool to clean the wellhead and measure the position of pre-installed equipment. This allows the user to save trips previously required by legacy designs, reducing time spent down hole and reducing overall cost. The antiquated claims of not being able to provide metal-to-metal sealing in dynamic applications are dispelled based on performed validation testing of a metal-to-metal seal (with no elastomeric/thermoplastic elements) which accurately represents field scenarios, in which combined pressure/temperature, load and hanger movement are applied. Therefore, the need for costly trips into the well is shown to be unnecessary with the installation of the single trip lockdown sleeve and/or high capacity casing hanger/seal assembly.
{"title":"Seal Qualification and Single-Trip Lockdown Sleeve Reduces Risk Through Innovative and Advanced Technology","authors":"Scott Patrick Ellisor, R. A. Queiroz, Carlos Eduardo Martins Gaban, Guilherme Pedro Eppinghaus, B. N. Lucci","doi":"10.4043/29943-ms","DOIUrl":"https://doi.org/10.4043/29943-ms","url":null,"abstract":"\u0000 The oil and gas industry continues to face the need to reduce risk and the overall cost of operations as a means to compensate for lower oil prices. Conventional designs and methods are economically infeasible when drilling offshore in the current economic environment pushing the manufacturer to re-evaluate how to reduce risk and drive down costs. This paper describes a new and advanced way to drive down cost and reduce risk while drilling by reducing the number of trips into the well, adding significant value to the end user.\u0000 The subsea wellhead system functions in a dynamic, complex environment; however, the qualification process of this system commonly employs relatively static test fixtures. These critical seal/casing hanger barriers within this wellhead system are presented, discussed and shown with exhaustive validation efforts necessary to evaluate relevant failure modes. Within the wellhead system, loads are typically resultant of a combined state including pressure and temperature. The validation of these components is aimed at defining the performance of the system in these states while detailing the limitations that one performance aspect may have on another. (Brown, 2017)\u0000 This wellhead system offers reduced cost, simplified installation procedures and lower operational risk. Traditionally, a wellhead system would require a drilling lockdown sleeve during the drilling operations; however, prior to running the lockdown sleeve, many additional trips are made into the well to verify the position of the hanger in the wellhead. By eliminating the lockdown sleeve, the operator will save multiple trips into the well, therefore, reducing NPT and cost of operations. This is proven by performing well-defined subsea seal/casing hanger testing validation to accurately simulate the installed configuration.\u0000 Because of this innovative seal assembly design, development of a single trip lock down sleeve was designed for wellhead systems requiring extremely high lock down requirements. The lock down sleeve does not require a trip with a Lead Impression Tool to clean the wellhead and measure the position of pre-installed equipment. This allows the user to save trips previously required by legacy designs, reducing time spent down hole and reducing overall cost.\u0000 The antiquated claims of not being able to provide metal-to-metal sealing in dynamic applications are dispelled based on performed validation testing of a metal-to-metal seal (with no elastomeric/thermoplastic elements) which accurately represents field scenarios, in which combined pressure/temperature, load and hanger movement are applied. Therefore, the need for costly trips into the well is shown to be unnecessary with the installation of the single trip lockdown sleeve and/or high capacity casing hanger/seal assembly.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134532309","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}
Brazil is entering the age of decommissioning, with aging offshore fields that have been in operation for more than 25 years. Brazil has migrated from an operator’s monopolistic environment (with the state owned oil company, Petrobras) to a new reality in which many companies, national and international operate in Brazilian waters. As part of this new reality, Brazil has established government organizations whose aim is to coordinate the exploitation of Brazil’s natural resources with the intent of optimizing activities while protecting the environment in an ever increasingly complex eco-system management. Traditionally, offshore projects follow basic phases such as conceptual, front end engineering and design (FEED), detail design, construction and commissioning. Cost allocation and schedules for these phases are all associated with production estimates and return on investment estimates. In many instances, internationally, planning for decommissioning has been deferred to an unforeseen future. Finally that far off horizon has become a reality, and domestic and foreign operators in Brazil are going through a new decommissioning awareness phase. It is the author’s opinion that operators wish to comply with a well-defined frame of Brazilian and international regulations. In general, this paper aims at examining the existing regulatory environment and make recommendations on a path forward for:Clear-cut requirements so that the permitting process flows with a minimized review cycle;A clear set of rules, defining what abandonment options exist (e.g. complete removal vs. partial removal, on-site abandonment rules for topsides and subsea infrastructure);A clear set of rules defining fines and sanctions for environmental violations The objectives of this paper are to 1) Gather basic information on the current status of the Brazilian Rules and Regulations, 2) Help non-government entities work together to accomplish the goals set forth by Brazilian lawmakers and officials, and 3) Develop a roadmap for convergence of the environmental agency and project stakeholders. Laws, rules and regulations, and international treaties of which Brazil is signatory are part of this environment.
{"title":"Decommissioning of Subsea Facilities in Brazil","authors":"Armando Rebello","doi":"10.4043/29712-ms","DOIUrl":"https://doi.org/10.4043/29712-ms","url":null,"abstract":"\u0000 Brazil is entering the age of decommissioning, with aging offshore fields that have been in operation for more than 25 years.\u0000 Brazil has migrated from an operator’s monopolistic environment (with the state owned oil company, Petrobras) to a new reality in which many companies, national and international operate in Brazilian waters. As part of this new reality, Brazil has established government organizations whose aim is to coordinate the exploitation of Brazil’s natural resources with the intent of optimizing activities while protecting the environment in an ever increasingly complex eco-system management.\u0000 Traditionally, offshore projects follow basic phases such as conceptual, front end engineering and design (FEED), detail design, construction and commissioning. Cost allocation and schedules for these phases are all associated with production estimates and return on investment estimates.\u0000 In many instances, internationally, planning for decommissioning has been deferred to an unforeseen future. Finally that far off horizon has become a reality, and domestic and foreign operators in Brazil are going through a new decommissioning awareness phase.\u0000 It is the author’s opinion that operators wish to comply with a well-defined frame of Brazilian and international regulations. In general, this paper aims at examining the existing regulatory environment and make recommendations on a path forward for:Clear-cut requirements so that the permitting process flows with a minimized review cycle;A clear set of rules, defining what abandonment options exist (e.g. complete removal vs. partial removal, on-site abandonment rules for topsides and subsea infrastructure);A clear set of rules defining fines and sanctions for environmental violations\u0000 The objectives of this paper are to 1) Gather basic information on the current status of the Brazilian Rules and Regulations, 2) Help non-government entities work together to accomplish the goals set forth by Brazilian lawmakers and officials, and 3) Develop a roadmap for convergence of the environmental agency and project stakeholders. Laws, rules and regulations, and international treaties of which Brazil is signatory are part of this environment.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115122788","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. F. Oliveira, Silvia Schaffel, Joaquim Domingues do Amaral Netto
A new method developed to evaluate the performance measure of some sub-criteria of the environmental criterion in a Comparative Assessment of various options of the decommissioning of subsea installations in Brazil is presented. The method is based on an adaptation of that proposed by IBAMA in Technical Note N°. 10/2012 (TN 10) used for assessment of environmental impacts required for the licensing of offshore activities in Brazil. By requirement of the Comparative Assessment methodology, there is a need for a numerical evaluation that allows comparing the performance of one alternative over the others. An analytical method was developed based on the combination of environmental attributes that contribute for the magnitude of the impacts (frequency, intensity, extension and duration) and sensitivity of the environmental factors affected (relevance, resilience and reversibility). The importance of the impacts is given by the combination of the environmental sensitivity with the magnitude of the impacts, in the called "Environmental Impact Importance Score Matrix". The proposed method provides a performance measure that allows comparing and prioritizing each decommissioning option according to the proposed criteria. It reduces the subjectivity in assessing the importance of the environmental impacts and provides greater transparency and traceability in the assessment of the impacts. As an example, the proposed method is applied for the decommissioning of a rigid pipeline between two platforms in Campos Basin, where the considered decommissioning options are: (a) complete removal by cut and lift and (b) leave in situ. For this particular case, the assessment of the proposed environmental sub-criteria revealed that Option (b) was the preferred option with respect to the impacts on marine and onshore environment.
{"title":"An Analytical Method to Combine Environmental Attributes to Generate the Matrix of Importance of Environmental Impacts for the Decommissioning of Subsea Installations in Brazil","authors":"L. F. Oliveira, Silvia Schaffel, Joaquim Domingues do Amaral Netto","doi":"10.4043/29704-ms","DOIUrl":"https://doi.org/10.4043/29704-ms","url":null,"abstract":"\u0000 A new method developed to evaluate the performance measure of some sub-criteria of the environmental criterion in a Comparative Assessment of various options of the decommissioning of subsea installations in Brazil is presented. The method is based on an adaptation of that proposed by IBAMA in Technical Note N°. 10/2012 (TN 10) used for assessment of environmental impacts required for the licensing of offshore activities in Brazil. By requirement of the Comparative Assessment methodology, there is a need for a numerical evaluation that allows comparing the performance of one alternative over the others. An analytical method was developed based on the combination of environmental attributes that contribute for the magnitude of the impacts (frequency, intensity, extension and duration) and sensitivity of the environmental factors affected (relevance, resilience and reversibility). The importance of the impacts is given by the combination of the environmental sensitivity with the magnitude of the impacts, in the called \"Environmental Impact Importance Score Matrix\". The proposed method provides a performance measure that allows comparing and prioritizing each decommissioning option according to the proposed criteria. It reduces the subjectivity in assessing the importance of the environmental impacts and provides greater transparency and traceability in the assessment of the impacts. As an example, the proposed method is applied for the decommissioning of a rigid pipeline between two platforms in Campos Basin, where the considered decommissioning options are: (a) complete removal by cut and lift and (b) leave in situ. For this particular case, the assessment of the proposed environmental sub-criteria revealed that Option (b) was the preferred option with respect to the impacts on marine and onshore environment.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115130361","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}
P. Rocha, Roberto de Oliveira Goulart, S. Kawathekar, Raul Dotta
Heavy oil represents a significant portion of the remaining oil reserves and there are strong economic incentives within industry to develop technologies to profitably produce these oil reserves. The success of Early Production System phase (EPS) and Definitive System (DS) solutions for Atlanta Field development certainly presents a promising way forward to achieve a safe production of extra-heavy oil in deep waters. As the Operator, Enauta made the farm-in of Atlanta Field in 2011. Atlanta is a heavy oil field with 14°API grade with viscosity equivalent of an oil with 12°API, a shallow reservoir around 800 meters below sea bed with low temperature of 40°C and water deep around 1,550 m. Heavy oils are often characterized by their high viscosities, stable emulsion formation tendency and low reservoir energy. These combined characteristics makes production, transportation and processing operations very challenging. Likewise, the Atlanta crude imposes enormous challenges for the characterization of the reservoir, drilling and completion, flow assurance from the wells to FPSO, topsides process ing (phase separation, heat and power generation methods) and cargo storage as well as offloading from the FPSO to tankers. This paper describes EPS implementation and DS development to overcome these project challenges with the use of the best available technical solutions and approaches to keep production safe and profitable, focused on the specifics strategies to overcome flow assurance challenges, techniques employed for the fluid viscosity management and emulsion breaking, techniques to enhance phase separation, heat and power generation methods and fuel alternatives to optimize OPEX and various design features to reduce atmospheric emissions. Production aspects will also be described from the solution adopted for the oil processing and offloading for the EPS FPSO as well as the DS "flex-FPSO" concept to enable oil production using alternative fuels, bearing in mind CAPEX/OPEX optimization, operational flexibility, robustness and ever tightening environmental regulations. To ensure safe operations, different contingency plans have been implemented, like this innovative solution: a software developed and tested offshore to reliably predict the drift (SW-Drift) of the drilling ship for both forecast and real-time metocean data, to accurately determine the conditions under which a support vessel shall be aware in advance to avoid collision of the drilling ship caused by a possible blackout event. The Atlanta Field development presents a successful real case to the Oil Industry to be considered in similar difficult oil and project conditions.
{"title":"Atlanta Field Development - Present and Future","authors":"P. Rocha, Roberto de Oliveira Goulart, S. Kawathekar, Raul Dotta","doi":"10.4043/29846-ms","DOIUrl":"https://doi.org/10.4043/29846-ms","url":null,"abstract":"\u0000 Heavy oil represents a significant portion of the remaining oil reserves and there are strong economic incentives within industry to develop technologies to profitably produce these oil reserves. The success of Early Production System phase (EPS) and Definitive System (DS) solutions for Atlanta Field development certainly presents a promising way forward to achieve a safe production of extra-heavy oil in deep waters.\u0000 As the Operator, Enauta made the farm-in of Atlanta Field in 2011. Atlanta is a heavy oil field with 14°API grade with viscosity equivalent of an oil with 12°API, a shallow reservoir around 800 meters below sea bed with low temperature of 40°C and water deep around 1,550 m. Heavy oils are often characterized by their high viscosities, stable emulsion formation tendency and low reservoir energy. These combined characteristics makes production, transportation and processing operations very challenging. Likewise, the Atlanta crude imposes enormous challenges for the characterization of the reservoir, drilling and completion, flow assurance from the wells to FPSO, topsides process ing (phase separation, heat and power generation methods) and cargo storage as well as offloading from the FPSO to tankers.\u0000 This paper describes EPS implementation and DS development to overcome these project challenges with the use of the best available technical solutions and approaches to keep production safe and profitable, focused on the specifics strategies to overcome flow assurance challenges, techniques employed for the fluid viscosity management and emulsion breaking, techniques to enhance phase separation, heat and power generation methods and fuel alternatives to optimize OPEX and various design features to reduce atmospheric emissions.\u0000 Production aspects will also be described from the solution adopted for the oil processing and offloading for the EPS FPSO as well as the DS \"flex-FPSO\" concept to enable oil production using alternative fuels, bearing in mind CAPEX/OPEX optimization, operational flexibility, robustness and ever tightening environmental regulations.\u0000 To ensure safe operations, different contingency plans have been implemented, like this innovative solution: a software developed and tested offshore to reliably predict the drift (SW-Drift) of the drilling ship for both forecast and real-time metocean data, to accurately determine the conditions under which a support vessel shall be aware in advance to avoid collision of the drilling ship caused by a possible blackout event.\u0000 The Atlanta Field development presents a successful real case to the Oil Industry to be considered in similar difficult oil and project conditions.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115157640","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}
R. Satti, J. Gilliat, D. Bale, P. Hillis, B. Myers, Jason M. Harper
Well completion operations in perforating, sand-control, stimulation, and flow management are often transient in nature, thereby making it a challenge to understand the complex physical processes that affect a safe deployment or a robust optimization of completion hardware. Historically, steady-state methods have been used to predict dynamic completion events. These methods can lead to inaccurate analysis and add risk to the decision-making process. An integrated, transient simulation approach is therefore required to model, predict, optimize and most importantly ensure a safe completion operation. In this work, we present the application of fully transient, multi-phase flow simulation software that simulates dynamic downhole completion scenarios. The computational framework of the software incorporates a coupled wellbore-perforation-reservoir model, with differentiating algorithms for shock-capturing hydrodynamic solvers, robust thermodynamic closure, advanced fluid dynamics and more importantly, significantly faster turnaround simulation times to enable quick pre-job modeling iterations. The software has been extensively used for designing and optimizing perforating jobs, but recently, the applicability of the software has been demonstrated for transient completion scenarios beyond perforating. Several application examples are presented in this study, whereby the computational software has been successfully used to predict and drive critical decisions relating to either novel completion technologies or safe deployment of completion systems. Case histories pertaining to dropped tools, downhole valves (effects of water hammer/shut-in), next-generation completion systems (fully conformable sand management systems), and safety investigation of post-perforating, completion practices, and propellant-assisted stimulation systems are comprehensively discussed in this paper. Results and data analysis including modeled pressure surge, loading on downhole equipment, transient fluid physics, history-matching and most importantly, the insight into dynamic interaction between the wellbore and formation are presented in this study. This study clearly demonstrates the importance of a transient, fully coupled simulator to predict dynamic completion scenarios as well as ensure flawless execution of next-generation completion systems. This robust simulation platform, when integrated with production calculations, also provides the scope to better predict and maximize productivity.
{"title":"Application of a Transient Near-Wellbore / Reservoir Simulator for Complex Completions Design","authors":"R. Satti, J. Gilliat, D. Bale, P. Hillis, B. Myers, Jason M. Harper","doi":"10.4043/29948-ms","DOIUrl":"https://doi.org/10.4043/29948-ms","url":null,"abstract":"\u0000 Well completion operations in perforating, sand-control, stimulation, and flow management are often transient in nature, thereby making it a challenge to understand the complex physical processes that affect a safe deployment or a robust optimization of completion hardware. Historically, steady-state methods have been used to predict dynamic completion events. These methods can lead to inaccurate analysis and add risk to the decision-making process. An integrated, transient simulation approach is therefore required to model, predict, optimize and most importantly ensure a safe completion operation.\u0000 In this work, we present the application of fully transient, multi-phase flow simulation software that simulates dynamic downhole completion scenarios. The computational framework of the software incorporates a coupled wellbore-perforation-reservoir model, with differentiating algorithms for shock-capturing hydrodynamic solvers, robust thermodynamic closure, advanced fluid dynamics and more importantly, significantly faster turnaround simulation times to enable quick pre-job modeling iterations. The software has been extensively used for designing and optimizing perforating jobs, but recently, the applicability of the software has been demonstrated for transient completion scenarios beyond perforating.\u0000 Several application examples are presented in this study, whereby the computational software has been successfully used to predict and drive critical decisions relating to either novel completion technologies or safe deployment of completion systems. Case histories pertaining to dropped tools, downhole valves (effects of water hammer/shut-in), next-generation completion systems (fully conformable sand management systems), and safety investigation of post-perforating, completion practices, and propellant-assisted stimulation systems are comprehensively discussed in this paper. Results and data analysis including modeled pressure surge, loading on downhole equipment, transient fluid physics, history-matching and most importantly, the insight into dynamic interaction between the wellbore and formation are presented in this study. This study clearly demonstrates the importance of a transient, fully coupled simulator to predict dynamic completion scenarios as well as ensure flawless execution of next-generation completion systems. This robust simulation platform, when integrated with production calculations, also provides the scope to better predict and maximize productivity.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116163466","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}
Achoyamen Ogbeifun Michael, S. Oterkus, J. Race, Harit Naik, Eduardo Decnop, D. Moorthy, S. Bhowmik
A novel riser concept is being investigated. This is the branched riser system (BRS) with different configuration types including the branched steel catenary riser (BSCR), the branched steel lazy wave riser (BSLWR) and the branched lazy wave hybrid riser (BLWHR). As part of the design and operational requirement for riser systems, riser interference or clash checks is important especially in cases when risers are positioned closely from each other and the external excitations including hydrodynamic interactions are significant. This paper presents findings from the investigation of the interference response of the branches of the BSCR. The BSCR, with different half branch angles(β = 0.1deg, 0.5deg and 1deg), are hosted by a floating production system in a water depth of 1500m and subjected to different loading conditions including current loads, vessel offsets, variation in branches’ weight, dynamic loads from ocean wave excitations and drag amplification due to VIV. Under these conditions, the minimum clearance between the BSCR branches were calculated and checked against the minimum clearance requirements. Results from this study showed that the global displacement responses of the BSCR branches are in tandem with each other for non-VIV scenarios and that the minimum clearances between them satisfy the no-clash criteria. This is due to the close drag-to-apparent-weight (DAW) ratio of the branches. Wave load excitations on the BSCR were observed to cause little changes on the branches’ clearance, even when imposed on a combination of worst static conditions. For ‘lockin’ conditions during VIV, it is found that the transverse vibrational amplitude-to-diameter (A/D) ratio of the branches, which impact amplification on the inline drag force can be different for the two branches. This can result in differential deflection of the branches and higher clash possibilities. Under VIV conditions with the current profile typical of Gulf of Mexico (GoM), the BSCR configuration with half branch angle, β = 0.1deg, was found not to satisfy the interference criteria while the BSCR (β=1deg) survived. This indicates that high half branch angle will be required for the BSCR design under high intensity and shearing current profiles acting on the branches. However, all BSCR configurations with half branch angles (β =0.1deg, 0.5deg and 1deg) were found to satisfy the interference requirement when subjected to constant current profiles (slab currents) and current profile typical of West of Africa (WoA), though slab current profile resulted in very high A/D ratio. These results provide positive indications for continuing investigation of other aspects of the BSCR.
{"title":"The Branched Steel Catenary Riser Interference Study","authors":"Achoyamen Ogbeifun Michael, S. Oterkus, J. Race, Harit Naik, Eduardo Decnop, D. Moorthy, S. Bhowmik","doi":"10.4043/29716-ms","DOIUrl":"https://doi.org/10.4043/29716-ms","url":null,"abstract":"\u0000 A novel riser concept is being investigated. This is the branched riser system (BRS) with different configuration types including the branched steel catenary riser (BSCR), the branched steel lazy wave riser (BSLWR) and the branched lazy wave hybrid riser (BLWHR). As part of the design and operational requirement for riser systems, riser interference or clash checks is important especially in cases when risers are positioned closely from each other and the external excitations including hydrodynamic interactions are significant. This paper presents findings from the investigation of the interference response of the branches of the BSCR.\u0000 The BSCR, with different half branch angles(β = 0.1deg, 0.5deg and 1deg), are hosted by a floating production system in a water depth of 1500m and subjected to different loading conditions including current loads, vessel offsets, variation in branches’ weight, dynamic loads from ocean wave excitations and drag amplification due to VIV. Under these conditions, the minimum clearance between the BSCR branches were calculated and checked against the minimum clearance requirements.\u0000 Results from this study showed that the global displacement responses of the BSCR branches are in tandem with each other for non-VIV scenarios and that the minimum clearances between them satisfy the no-clash criteria. This is due to the close drag-to-apparent-weight (DAW) ratio of the branches. Wave load excitations on the BSCR were observed to cause little changes on the branches’ clearance, even when imposed on a combination of worst static conditions. For ‘lockin’ conditions during VIV, it is found that the transverse vibrational amplitude-to-diameter (A/D) ratio of the branches, which impact amplification on the inline drag force can be different for the two branches. This can result in differential deflection of the branches and higher clash possibilities. Under VIV conditions with the current profile typical of Gulf of Mexico (GoM), the BSCR configuration with half branch angle, β = 0.1deg, was found not to satisfy the interference criteria while the BSCR (β=1deg) survived. This indicates that high half branch angle will be required for the BSCR design under high intensity and shearing current profiles acting on the branches. However, all BSCR configurations with half branch angles (β =0.1deg, 0.5deg and 1deg) were found to satisfy the interference requirement when subjected to constant current profiles (slab currents) and current profile typical of West of Africa (WoA), though slab current profile resulted in very high A/D ratio. These results provide positive indications for continuing investigation of other aspects of the BSCR.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123704059","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}
Cristiano Eduardo Agostini, L. F. M. Almeida, N. M. Júnior, Mateus Dias Magalhães, Roger Savoldi Roman, E. Schnitzler, Alan Pinheiro Silva
This paper presents the finite element analysis of salt-creep behavior on deepwater wells with trapped annulus, considering cooling effects caused by injection operations. In addition, this effect was considered coupled with salt-creep behavior and its influence on casing collapse design under transient and steady state well operation. The scenarios of injection flow rate and temperature profile were analyzed using the coupled approach, for salt creeping and thermal trapped annulus. The wellbore profile is a typical Pre Salt Brazilian Offshore, where rock salt layer is confined under two casing shoes. The injection wells operation results in a pressure decrease in a confined annulus due to thermal cooling between casing and salt formation. Due to this pressure drop on the trapped annulus, the salt creeping behavior tends to increase, and proper casing stress verification must be done. The finite elements analysis for salt creeping was modeled using commercial finite elements software package, and thermal profile for transient and steady state injection was obtained using thermal casing design software. The coupled effects were evaluated using commercial casing design software. Preliminary studies have shown that there is a great influence on the salt creeping response on confined annulus when subjected to a pressure decrease due to thermal cooling on trapped annulus, caused by water injection operation. It is observed that there is a growth of the confined annular pressure due to salt creeping effects and that there is an acceleration in this phenomenon. The analysis also shows that casing collapse safety margin is time dependent considering a given operation. After well shutdown, the natural heating of the confined annulus occurs due to geothermal effects, and this pressure is added to the trapped annulus, increasing the pressure of trapped annulus. The final pressure is the sum of the salt pressure build up accelerated by the cooling steady state regime and geothermal pressure build up, during shutdown. The worst case scenario could be during restart the well injection, in that way, this kind of situation must be analyzed, so that it does not lead to critical situations on the casing design. Historically, according to literature review, only the annular pressure build up with production heating is analyzed. This work is a novel approach where annular pressure drop off, caused by cooling operations, was investigated including coupled salt-creeping and thermal phenomenon.
{"title":"Salt Creeping Analysis on Deepwater Wells Submitted to Cooling Operations on Trapped Annular","authors":"Cristiano Eduardo Agostini, L. F. M. Almeida, N. M. Júnior, Mateus Dias Magalhães, Roger Savoldi Roman, E. Schnitzler, Alan Pinheiro Silva","doi":"10.4043/29764-ms","DOIUrl":"https://doi.org/10.4043/29764-ms","url":null,"abstract":"\u0000 This paper presents the finite element analysis of salt-creep behavior on deepwater wells with trapped annulus, considering cooling effects caused by injection operations. In addition, this effect was considered coupled with salt-creep behavior and its influence on casing collapse design under transient and steady state well operation. The scenarios of injection flow rate and temperature profile were analyzed using the coupled approach, for salt creeping and thermal trapped annulus. The wellbore profile is a typical Pre Salt Brazilian Offshore, where rock salt layer is confined under two casing shoes. The injection wells operation results in a pressure decrease in a confined annulus due to thermal cooling between casing and salt formation. Due to this pressure drop on the trapped annulus, the salt creeping behavior tends to increase, and proper casing stress verification must be done. The finite elements analysis for salt creeping was modeled using commercial finite elements software package, and thermal profile for transient and steady state injection was obtained using thermal casing design software. The coupled effects were evaluated using commercial casing design software. Preliminary studies have shown that there is a great influence on the salt creeping response on confined annulus when subjected to a pressure decrease due to thermal cooling on trapped annulus, caused by water injection operation. It is observed that there is a growth of the confined annular pressure due to salt creeping effects and that there is an acceleration in this phenomenon. The analysis also shows that casing collapse safety margin is time dependent considering a given operation. After well shutdown, the natural heating of the confined annulus occurs due to geothermal effects, and this pressure is added to the trapped annulus, increasing the pressure of trapped annulus. The final pressure is the sum of the salt pressure build up accelerated by the cooling steady state regime and geothermal pressure build up, during shutdown. The worst case scenario could be during restart the well injection, in that way, this kind of situation must be analyzed, so that it does not lead to critical situations on the casing design. Historically, according to literature review, only the annular pressure build up with production heating is analyzed. This work is a novel approach where annular pressure drop off, caused by cooling operations, was investigated including coupled salt-creeping and thermal phenomenon.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"75 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127412546","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}
It is commonly known that the drilling sector of the oil and gas industry has lagged other batch and process industries such as the automotive and aerospace industries in terms of adopting new technologies. Historically, the oil and gas industry has been risk-adverse to deploying new technologies typically using the mindset "If isn’t broken, do not fix it". Technologies that have made it through commercialization have typically centered around solving a problem or accomplishing something that has not been done before, such as the ability to install heavier tubular strings or the ability to complete a well in an environment not previously accomplishable. However, lower commodity pricing is forcing the industry to become more cost-effective at drilling all types wells such that the industry can remain profitable in the current environment. This has created a technology trend to drill wells at a lower cost, which has put a focus on process improvement and process optimization, something not heavily focused on previously. Borrowing off other industries, an accelerated rate of adopting new technologies is being realized, especially digital and robotic technologies that can remove personnel from the rig floor and automate processes that are repetitive in nature. The drill floor is naturally seen as an area where the repetitious nature of pipe handling, installation, and removal can be automated for safety and efficiency. Although technologies do currently exist to mechanize the process, further automation of the process without compromising the functions required at well center has been difficult to be viewed as value added and profitable. Based on experience and research on these operations, proof of value can be demonstrated to show what makes sense in terms of automating the drill floor.
{"title":"Proof of Value in Automating the Drill Floor","authors":"J. Angelle","doi":"10.4043/29681-ms","DOIUrl":"https://doi.org/10.4043/29681-ms","url":null,"abstract":"\u0000 It is commonly known that the drilling sector of the oil and gas industry has lagged other batch and process industries such as the automotive and aerospace industries in terms of adopting new technologies. Historically, the oil and gas industry has been risk-adverse to deploying new technologies typically using the mindset \"If isn’t broken, do not fix it\". Technologies that have made it through commercialization have typically centered around solving a problem or accomplishing something that has not been done before, such as the ability to install heavier tubular strings or the ability to complete a well in an environment not previously accomplishable. However, lower commodity pricing is forcing the industry to become more cost-effective at drilling all types wells such that the industry can remain profitable in the current environment. This has created a technology trend to drill wells at a lower cost, which has put a focus on process improvement and process optimization, something not heavily focused on previously. Borrowing off other industries, an accelerated rate of adopting new technologies is being realized, especially digital and robotic technologies that can remove personnel from the rig floor and automate processes that are repetitive in nature. The drill floor is naturally seen as an area where the repetitious nature of pipe handling, installation, and removal can be automated for safety and efficiency. Although technologies do currently exist to mechanize the process, further automation of the process without compromising the functions required at well center has been difficult to be viewed as value added and profitable. Based on experience and research on these operations, proof of value can be demonstrated to show what makes sense in terms of automating the drill floor.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126771691","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. Diniz, Breno N. Espíndola, Italo Dourado Affonso, Jackson Luan Queiroz, Leojaime Queiroz Oliveira, Gerson Barboza, Carlos Augusto Pereira
This work aims at describing some initiatives (within the context of new ultra deep-water oil platforms designs using computer aided engineering tools) in order to reach a higher level of information organization, transform the engineering design environment so that it is possible to get more productive processes in order to meet all required deadlines. These initiatives were developed focusing on data structuring, information standardization, redundancy reduction, auditing mechanisms implementation and workflow standardization and automation, allowing Petrobras engineerign design team to get benefits from Industry 4.0.
{"title":"Data-Centrism: A Path to Digital Transformation in Engineering Design Environment","authors":"F. Diniz, Breno N. Espíndola, Italo Dourado Affonso, Jackson Luan Queiroz, Leojaime Queiroz Oliveira, Gerson Barboza, Carlos Augusto Pereira","doi":"10.4043/29860-ms","DOIUrl":"https://doi.org/10.4043/29860-ms","url":null,"abstract":"\u0000 This work aims at describing some initiatives (within the context of new ultra deep-water oil platforms designs using computer aided engineering tools) in order to reach a higher level of information organization, transform the engineering design environment so that it is possible to get more productive processes in order to meet all required deadlines. These initiatives were developed focusing on data structuring, information standardization, redundancy reduction, auditing mechanisms implementation and workflow standardization and automation, allowing Petrobras engineerign design team to get benefits from Industry 4.0.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"33 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129592670","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. S. Kraus, S. Melo, M. Reynier, Leonardo de Souza Marinho, Leticia Falcao Veiga, Bruno C. Pereira, Leandro Franco Macena Araújo, Dalton S. Ximenes
Brazilian Environmental Authority (IBAMA) adopted EPA rules for discharging drill cuttings from O&G operations. EPA method describes procedures to evaluate toxicity using Leptocheirus plumulosus. Despite being an exotic species, Brazilian laboratories keep L. plumulosus cultures. Otherwise, Grandidierella bonnieroides is widely distributed in Brazilian estuaries is successfully cultured and sensitive to many toxicants. The present study was carried out to evaluate the effects of three non-aqueous drilling fluids (NAF) and two synthetic based drilling muds (SBM) spiked to natural sediment on the amphipods. Reference toxicant experiments were also performed using C16C18 internal olefin or a C16C18 internal olefin SBM of similar density. Sediment was collected in Jabaquara beach, RJ and transferred to the laboratory in chilly bins. After sieving, it was kept at 4 ± 2 °C until spiking for no longer than 60 days. Spiking procedures and whole-sediment tests were set up following the methods described in EPA method 1644 and Brazilian Standards. Amphipods were exposed to 5 concentrations of SBM and NAF spiked sediment plus controls for 4 and 10 days, respectively, in static system. In NAF tests using G. bonnieroides the average LC50 obtained were 3.53 g.kg-1dw (n= 7; SD=1.63; CV= 46.07%), 1.33 g.kg-1dw (n= 6; SD=0.69; CV= 52.15%) and 0.56 g.kg-1dw (n= 7; SD=0.24; CV= 42.69%) for olefin, ester and paraffin, respectively, while L. plumulosus showed an average LC50 of 1.66 g.kg-1dw (n= 6; SD=1.30; CV= 78.10%), 0.60 g.kg-1dw (n= 5; SD=0.22; CV=35.81%) and 0.26 g.kg-1dw (n= 6; SD=0.13; CV= 50.50%), respectively. The average LC50 obtained in SBM 1 (11.6 ppg) tests using G. bonnieroides was 139.78 mL.kg-1dw (n= 3; SD= 69.47; CV= 49.70%) and for SBM 2 (9.9 ppg) the LC50 was 132.97 mL.kg-1dw, while L. plumulosus showed an average LC50 of 94.79 mL.kg-1dw (n= 2; SD= 92.33; CV= 97.41%) LC50 of 34.82 mL.kg-1dw, respectively, for SBM1 and SBM2. In olefin tests using L. plumulosus, SBM 2 test using G. bonnieroides and SBM 1 tests using both species, STR ≤ 1 were obtained, meeting the EPA criteria for drilling cuttings discharge. Although G. bonnieroides has shown to be less sensitive than L. plumulosus to the NAF and SBM, the method using G. bonnieroides as test species demonstrated to be suitable for this purpose and presented similar variability than the same method using L. plumulosus.
{"title":"Ecotoxicological Evaluation of Non Aqueous Drilling Fluids Using a Brazilian Native Versus an Exotic Amphipod","authors":"L. S. Kraus, S. Melo, M. Reynier, Leonardo de Souza Marinho, Leticia Falcao Veiga, Bruno C. Pereira, Leandro Franco Macena Araújo, Dalton S. Ximenes","doi":"10.4043/29746-ms","DOIUrl":"https://doi.org/10.4043/29746-ms","url":null,"abstract":"\u0000 Brazilian Environmental Authority (IBAMA) adopted EPA rules for discharging drill cuttings from O&G operations. EPA method describes procedures to evaluate toxicity using Leptocheirus plumulosus. Despite being an exotic species, Brazilian laboratories keep L. plumulosus cultures. Otherwise, Grandidierella bonnieroides is widely distributed in Brazilian estuaries is successfully cultured and sensitive to many toxicants.\u0000 The present study was carried out to evaluate the effects of three non-aqueous drilling fluids (NAF) and two synthetic based drilling muds (SBM) spiked to natural sediment on the amphipods. Reference toxicant experiments were also performed using C16C18 internal olefin or a C16C18 internal olefin SBM of similar density.\u0000 Sediment was collected in Jabaquara beach, RJ and transferred to the laboratory in chilly bins. After sieving, it was kept at 4 ± 2 °C until spiking for no longer than 60 days. Spiking procedures and whole-sediment tests were set up following the methods described in EPA method 1644 and Brazilian Standards. Amphipods were exposed to 5 concentrations of SBM and NAF spiked sediment plus controls for 4 and 10 days, respectively, in static system.\u0000 In NAF tests using G. bonnieroides the average LC50 obtained were 3.53 g.kg-1dw (n= 7; SD=1.63; CV= 46.07%), 1.33 g.kg-1dw (n= 6; SD=0.69; CV= 52.15%) and 0.56 g.kg-1dw (n= 7; SD=0.24; CV= 42.69%) for olefin, ester and paraffin, respectively, while L. plumulosus showed an average LC50 of 1.66 g.kg-1dw (n= 6; SD=1.30; CV= 78.10%), 0.60 g.kg-1dw (n= 5; SD=0.22; CV=35.81%) and 0.26 g.kg-1dw (n= 6; SD=0.13; CV= 50.50%), respectively. The average LC50 obtained in SBM 1 (11.6 ppg) tests using G. bonnieroides was 139.78 mL.kg-1dw (n= 3; SD= 69.47; CV= 49.70%) and for SBM 2 (9.9 ppg) the LC50 was 132.97 mL.kg-1dw, while L. plumulosus showed an average LC50 of 94.79 mL.kg-1dw (n= 2; SD= 92.33; CV= 97.41%) LC50 of 34.82 mL.kg-1dw, respectively, for SBM1 and SBM2. In olefin tests using L. plumulosus, SBM 2 test using G. bonnieroides and SBM 1 tests using both species, STR ≤ 1 were obtained, meeting the EPA criteria for drilling cuttings discharge. Although G. bonnieroides has shown to be less sensitive than L. plumulosus to the NAF and SBM, the method using G. bonnieroides as test species demonstrated to be suitable for this purpose and presented similar variability than the same method using L. plumulosus.","PeriodicalId":415055,"journal":{"name":"Day 1 Tue, October 29, 2019","volume":"59 16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124562982","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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