bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design and Analysis of Electrically Heat-Traced Flowline EHTF Pipeline End Manifold PLEM Using Seven Vega
Authors: Gautam Arun , Du David , Hurault De Ligny Florent 
Published: April 2022

Abstract
This paper presents the successful design and installation of the EHTF (Electrically Heat Traced Flowline) PLEM (Pipeline End Manifold) using the newly built, highly capable pipelay vessel, Seven Vega. This was achieved by taking advantage of Seven Vega's reel lay firing line capabilities.
The EHTF PLEM is an essential component of the EHTF system which combines the Thermal performance of PiP (Pipe in Pipe) flowline with Electrical heating capability. The EHTF PLEM is a complex structure which is designed to flow production fluid from well jumpers and from an extension flowline through a flowline jumper, as well as extends electrical heating functionality to the extension flowline. It has 3 hubs, 6 gate valves, and 8 electric flying leads, the piping header, and the termination of the electrical system all in one structure. The final design resulted in major reduction of overall length and weight.
The creative design went through multiple iterations to achieve the desired results while the vessel was still being built. Seven Vega is designed to install rigid flowlines including pipe in pipe systems and electrical trace heating, in water depths up to 3000m. Most reel-lay vessels have small PMA (PLET Manipulator Assembly) systems in the firing line. However, Seven Vega's bigger envelope and weight accommodates both 1st and 2nd end. Avoiding the need for cross-haul reduces cost and adds flexibility in the schedule. The result was the overall reduction in weight of the PLEM, flexibility of schedule, and successful design of the recoverable EHTF PLEM within PMA capacity of Seven Vega.
This paper showcases the advanced capabilities of the newly built Seven Vega and focuses on optimization and installation of the essential PLEM structure of EHTF technology.
How Subsea Produced Water Management Can Reduce Overall Carbon Footprint of Subsea-to-Shore Oil Developments
Authors: Anres Stephane , Shaiek Sadia , Bacati Fabrice , Giolo Riccardo , Zid Walid , La Sorda Enrico , Rondon Marianna , Pedenaud Pierre , Skivington Graeme , Lynch Kevin , Larbey Richard 
Published: April 2022

Abstract
A new subsea-to-shore oil field architecture is presented where produced water is separated, treated and re-injected locally. This solution reduces the overall power consumption and the global CO2e footprint of the development compared to an architecture where the whole production is sent to shore.
The paper will present the results of a study for the development of a 200 000 bpd oil field requiring 300 000 bpd water injection located 150 km from shore in 1500 m water depth and with a field life of 15 years.
Preliminary design work performed covers flow assurance, subsea process, subsea equipment, subsea layout as well as CO2e footprint comparison with a scenario where all the production is sent to shore.
The system incorporates a gravity-based liquid-liquid separator for bulk oil-water separation, produced water is then treated, mixed with desulfated seawater and re-injected. Oil, gas and residual produced water are sent to shore via a single wet insulated line with continuous injection of low-dosage hydrate inhibitors.
This scenario has two main advantages compared to a subsea-to-shore without subsea processing. The first is that the power required to boost production is significantly reduced. The second is that the volume of produced water to be treated onshore is also significantly reduced, which is advantageous, not only in terms of cost, but also in terms of reducing the shore operations’ footprint.
Particular focus will be made on the produced water treatment design which is a two-stage design using two different technologies for increased robustness in order to reach a specification of 30 ppm oil-in-water for injection water.
Mooring Integrity Issues and Lessons Learned Database - DeepStar® Project 20401
Authors: Spong Robert , Garrity Robert , Thompson Clay , Yan Xiaoyan , Gabrielsen Øystein , L’Hostis Didier , Heyl Caspar , Minnebo Joerik , Naciri Mamoun , Roberts Craig , Byatt David 
Published: April 2022

ABSTRACT
Mooring failures have been a recurring issue in the offshore industry, and failures continue to occur across the offshore Floating Production System (FPS) fleet. Many of these recurring failures appear to be from similar degradation mechanisms as past events. To better understand these trends and learn from these events, DeepStar® Project 20401 - Database of Mooring Integrity Issues and Lessons Learned was initiated.
The project primarily consisted of the collection and assessment of mooring integrity data on failures, pre-emptive replacements and repairs observed on FPS permanent mooring systems. Additionally, chain corrosion/wear data was collected and summarized as part of the project. When available the data was collected from published sources. However, most of the integrity data came from the eight operator and mooring consultancies companies participating in the project.
This paper describes the project data collection, the deliverables and key observations from the mooring integrity database developed as part of the project. The observations presented within the paper provide unique insight into predominate degradation mechanisms, observed consequences and estimated failure rates of mooring lines.
Challenges and Lessons Learned on the First Use of Tethered Bop in a Major Operator in Brazil, Including the Replacement of the Tension System Using the Rig Drilling String
Authors: Cardoso Cristiano Bernabé , Silva Magno Almeida da , Baptista João Marcelo Mussi , Santos Janaína Barreto , Kupski Sérgio Carlos , Caniçali Otávio , Resende Matheus Rodrigues , Costa Daniel , Rocha Danielle , Santiago Marcos Vinícius Sampaio 
Published: April 2022

Abstract
The use of the tethered BOP at Petrobras intends to enable the operation of Dynamically Positioned Rigs in shallow waters, allowing drilling or workover in wells in congested areas or subject to environmental restrictions due to corals or marine fauna. The BOP tethering technology also allows the use of newer generation rigs, whose BOPs are larger and heavier, in old wells not designed for such loads. ROV and surface images of the critical moments for the BOP tethering show the lessons learned in this operation, such as schematics and drawings of improvements implemented or suggested for future opportunities. During the operations, many opportunities for improvement were identified, such as: the ideal drilling schedule to launch the anchors with the Anchor Handling Tug Supply Vessel (AHTS); the imprisonment of the cables by the cement of the surface casing in the mud line; the knots that occurred in the cable after replacing the tensioner system; the feasibility to use the rig drill string instead of an RSV to replace the tensioner; and the need of unlatching the BOP to replace the tensioner system, with suggestions to avoid this in the future. The challenges overcome in this operation allowed the development of new solutions and procedures for tethering the BOP, dispensing with the use of a RSV, and improving the contractor's initial procedure. The success of this system enables rig operations in several locations that are currently unfeasible, whether for plug & abandonment of old wells or for drilling new locations in shallow water. The first use of tethered BOP in association with real-time Riser Analysis in Brazil resulted in the reduction of the risk associated with an emergency disconnection, providing a larger operational window and a more accurate analysis of well structure fatigue.
The Campos Basin Case: Unlocking Value from Mature Offshore Brazilian Assets – Petrobras
Authors: Lameira Otavio Diniz , Dinelli Denis Krambeck , Bordieri Eduardo , Carvalho Daniela Martinelli , Batista Marcio Rodrigues , Lage Daniel Henriques Mesquita , Lira Filipe Silva , Bezerra Leonardo Campos do Amaral 
Published: April 2022

Abstract
The oil shock of the 1970s challenged O&G operators for a step change in R&D with direct impact on investments in new production frontiers, such as the Brazilian offshore. More than 40 years after the first oil, around 14 billion barrels of oil and gas (boe) have already been produced in the Campos Basin and two OTC awards have been granted with the Campos Basin achievements in Marlim and Roncador fields. Today, Campos Basin production accounts for around 30% of all Brazilian O&G output. Moreover, there is still a lot of potential value to be extracted from those assets in association with the extension of the term of the contracts of the main Concessions for another 27 years.
In the continued strategy of Active Portfolio Management, any Campos Basin assets that do not fit into the company's portfolio focus are either divested or decommissioned, but still Campos Basin is a core area with substantial reserves to be booked, low reservoir risk and the potential to further reduce lifting costs. We can name Marlim, Roncador and Jubarte fields as examples of assets prioritized due to their value generating potential. These "world class" assets have been further developed with a specific approach: the Integrated Development Plans, with investments in complementary wells in existing fields to manage risks, enhance the recovery factor, as well as a governance to support decision making process between new Production Units or Lifetime Extension of those currently operating. All this governance is managed under a formal "Campos Basin Renovation Plan", a program that challenges the teams to identify opportunities to increase reserves and add value to the company.
In this context, considering the relevance of this world class oil & gas province, this paper intends to describe how the team is facing the challenge of generating extra value through investments in mature fields in the Campos Basin, considering its decision-making process, the increase in the recovery factor, reduction of costs, strategic alliances, and articulation with Regulatory Agencies.
World's First Offshore Use of Adhesively Bonded Mechanically Lined Pipe
Authors: Toguyeni Grégory , Lee Choon Hua , Omundsen Inge Andre , Jones Richard , Girvan John , Hondebrink Luke , Banse Joachim 
Published: April 2022

Abstract
The use of Mechanically Lined Pipe (MLP) installed by the reel-lay method is a field proven solution which presents key advantages over other more expensive rigid linepipe and installation methods. Implementing the most commonly used corrosion resistant alloys (CRA) as a thin liner inside a standard carbon steel (CS) pipe has been a differentiator for many projects due to the advantageous procurement lead times and reduced costs over clad pipe made from plates. To prevent the formation of wrinkles on the CRA liner during the reeling process the most reliable method to date was to internally pressurise the pipe with water. This solution, however, can increase the offshore installation time. A solution to prevent liner wrinkling with a standard 3.0mm or even 2.5mm thick liner during reeling without the use of pressurisation has been developed by Butting in the form of the GluBi® lined pipe. Through the liner being adhesively bonded to the outer pipe, its integrity is maintained despite the global plastic strain applied by the installation method. This new linepipe product has been qualified, fabricated and will be installed as a world's first on the AkerBP HOD project in the North Sea in 2022.
Following a thorough product technology qualification via DNV, the GluBi® pipe was approved for use on the AkerBP HOD project as the inner pipe of the 12"/16" Pipe-in-Pipe (PiP) production line to be installed by the reel-lay method. As part of the project specific qualification tests, the wrinkling resistance of the liner was demonstrated via full scale reeling simulation testing as well as the full set of Manufacturing Procedure Qualification Tests in line with the project specification. Important areas of the GluBi® pipe design are the pipe ends, particularly the transition between the liner and the weld overlay region. A detailed Finite Element model of the pipe system was created including the PiP centralisers; this allowed a verification of the global and local stresses at the most critical locations including the 3.0mm 316L liner close to the transition liner/overlay.
Successful pipe production was run by Butting and the pipes delivered to Subsea7's pipeline fabrication spoolbase in Vigra, Norway, for PiP stalks fabrication using a state-of-the-art mechanised welding solution combining the CMT and PGMAW welding processes. Offshore reel-lay installation with Seven Vega, Subsea 7's most advanced reel-lay vessel, is planned in 2022.
This paper will present the project specific product qualification including the mechanical testing of the outer and inner pipes as well as the adhesive material, the detailed finite element analysis (FEA) performed, the production welding activities and offshore installation by reel-lay.
LLOG Praline Tieback Execution: Fast-Paced Project Execution Delivered by Collaborative Project Management Techniques
Authors: Herbertson Barry Michael , Williams Julian 
Published: April 2022

Abstract

Objectives/Scope
The Praline project was awarded and executed during the COVID-19 pandemic and demonstrated how the right project management principles created transparency and trust between Contractor and Company so that both parties worked openly during project execution to successfully execute the scope in the required timeframe.

Methods, Procedures, Process
This project showcases how creating the right project environment fostered creative engineering, operational flexibility and collaborative decision making. A gate system was developed which enabled several solutions to run in parallel and focused on key dates for specific decisions which allowed for the final offshore scenario to be vetted. In addition, daily task orientated meetings were held with a small team to communicate updates and plans on specific topics between key stakeholders. All attendees were empowered to make decisions and progress tasks in the meeting. A lean and agile approach was deployed.

Results, Observations, Conclusions
The project was able to overcome numerous challenges during a pandemic in a short timeframe by implementing a fast-paced decision-making process which was underpinned by high-level trust between LLOG and Subsea 7. The project shifted from a plan to install the entire pipeline, In-Line Sled (ILS) and Pipeline End Termination (PLET) in a single trip to using multiple assets and mobilisations. The asset changes were required to maintain LLOG's first oil requirements and meant that the design, installation engineering, and procurement activities needed to be condensed and yet still meet high quality and safety standards. The changes in installation assets impacted the structures designs due to the installation equipment and this had a knock-on impact to the procurement and fabrication activities. One example was that the ILS needed to be redesigned to change the mudmat foundation and use an existing foundation from another project. This scope was completed in less than four weeks from the implementation of the vessel change and could only have been done through the transparent and collaborative approach established on the project.

Novel/Additive Information
This paper showcases how collaboration and transparency between all stakeholders enabled fast-paced decision making and selection of the optimal offshore solution in a condensed time frame.
Private Cluster and Revitalization Mature Fields in Brazil
Authors: Teixeira Cotta Diego Resende , Calvi Jean Carlos , Simões Carvalho Iuri Rossi 
Published: April 2022

Abstract
All shallow water fields being divested, as well as some of the deepwater assets. Independents specialized in mature fields jumping into these opportunities. New operators are working on reducing OPEX and decommissioning costs, revitalizing production facilities implementing IOR opportunities, and looking for tieback opportunities to leverage existing underutilised facilities.
This challenge was tackled with PetroRio making it the first independent company to create a private cluster of mature fields in the Campos Basin region, Brazil.
PetroRio are a Brazilian largest independent oil and natural production company with focus on investments and recovering production assets, specialized in efficiently managing reserves and redeveloping mature fields.
The company business model is totally focused on the efficient production of oil fields already in the production phase and on the cost optimization, positioning the Company to capture gains even in adverse external scenarios.
Challenges and Opportunities for Subsea Electrical Power Systems for High Power Subsea Processing and Boosting: HISEP Study Case
Authors: De Oliveira Ana Margarida , Gonçalves André Athayde , Da Silva William Albuquerque , Costa Lilson Terra , Passarelli Fabio Menezes 
Published: April 2022

Abstract
In 2017, Operator developed five feasibility studies with different suppliers to propose system configuration, select equipment and identify technology gaps to conceive a HISEP™ technology system to produce Brazilian pre-salt reservoirs, notoriously in the Mero field. A subsequent de-risking phase of the main technological gaps and critical engineering activities were structured to support a robust solution to be installed and validated in a HISEP™ full-scale application. All feasibility studies have indicated the need of two 6 MW shaft power centrifugal pumps operating in series to reinject HISEP™ dense gas phase (CO2 rich gas) into the reservoir.
This paper presents the subsea electrical power system (SEPS) topologies and technical solutions studied during HISEP™ de-risking phase to drive those high-power subsea pumps.
Underwater Cold bending - A Novel Solution for Offshore Pipelines Crossing Sharp Slope Transitions
Authors: Pigliapoco Mauro , Lucchese Francesco , Fatica Giulio 
Published: April 2022

Abstract
The exploitation of subsea hydrocarbons fields as well as large subsea gas to market infrastructures often requires pipelines to route across sharp slope transitions. Site conditions are sometime so critical to represent a severe design concern and to require costly seabed preparation works, extremely challenging and environmentally impacting. This paper presents an innovative solution that allows avoiding any preparation work as well as a novel installation method for its effective and safe implementation.
Specifically, the paper presents a design case study for a gas export pipeline crossing a severe escarpment at the intersection between the Continental Shelf and the Continental Slope (Shelf Break). The rigid pipeline installed by normal continuous pipelay across such sharp slope transition would be subject to excessive bending due to localized imposed curvature that requires mitigation. Two alternative design solutions have been developed and compared: one based on excavation (trenching) to shape the escarpment edge and one introducing vertical bends on the pipeline string.
The design solution based on trenching results in large excavation volume with associated environmental impact in term seawater turbidity and damaged seabed surface (biocenosis). The analysis results also show that the solution is very sensitive to trenching profile accuracy and profile long term stability. Constructability is discussed in terms of availability of technology vs water depth, soil uncertainties, excavation volume, excavation tolerances. The alternative design based on bends allows avoiding any seabed preparation works and all the associated issues. The analysis results demonstrate much higher performances in terms of pipeline integrity and safety throughout the pipeline life. However, its implementation requires special installation solutions as bends are not installable with the normal continuous pipelay method. The paper presents a new installation method (Saipem patented) that allows realizing vertical cold bends safely and effectively on the pipeline profile with no interruption of the continuous pipelay process. The novel idea is to realize the bends underwater, when the pipe is landing or close to landing on the seabed, by means of a remotely operated Underwater Bending Machine purposedly designed.
The paper describes the new Underwater Cold Bending technology, presenting the engineering work done to support the demonstration of its robustness and reliability. The paper also presents a case study for escarpment crossing design developed according to two alternative design concepts, the standard and the novel one. The two solutions are compared, listing pros and cons of each one, highlighting relevant design issues as well as construction criticalities and risks.
Repurposing Gulf of Mexico Oil and Gas Facilities for the Blue Economy
Authors: Robinson Roy , Englemann Georg , Saterlee Kent 
Published: April 2022

Abstract
This paper presents a summary of the results of a study of the potential for repurposing legacy oil and gas facilities in the Gulf of Mexico for Blue Economy uses. It was a limited study designed to summarize practical options for repurposing. The conclusions list those areas where further modeling or studies are warranted and required with the objective being to build an integrated modeling tool to assist companies, government agencies, and NGO's in assessing the benefits and risks for repurposing specific facilities.
30CFR 585J can be used to expedite permitting the deployment of renewable energy in the Gulf of Mexico. This regulation specifically is written to allow addition of renewable energy and other marine activities on to existing oil and gas leases and is written broadly enough it can be applied to other Blue Economy activities.
For the transition to occur the current policy of removing non-producing assets must be stopped. These facilities, providing they are still in good repair, can be a tremendous asset that can accelerate the decarbonization of the Gulf Coast Region, and become the basis for an industrial transition that will create more employment and value than even the peak of offshore oil and gas.
The Gulf of Mexico has an excellent offshore renewable energy potential. NREL places the total Gross Resource available at 2000GW and the Technical (recoverable) resource at 500GW. Neither value includes geothermal, and because of the conservative way the NREL calculates the resources the actual potential is at least twice as large.
The DOE study, summarized in this paper, provides detailed answer to the following questions:
What is the potential value of legacy platforms, wells, and pipelines to renewable energy and Blue Economy activities? What renewable energy systems are economically viable in the Gulf of Mexico and can be deployed safely on existing leases? What Blue Economy industries can be facilitated by using legacy assets in the Gulf of Mexico? Who can apply for and what is the process for repurposing existing assets or adding new assets to existing leases? What are the benefits to the current owners, the Gulf Coast Region, and environment?
Finally, the paper provides the outline of a process that stakeholders can use to evaluate individual existing facilities for potential use in building a Blue Industrial base in the Gulf of Mexico.