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Delivery of the umbilicals is expected in Q4 2021. The King’s Quay FPS achieved FID in Q2 2019, and is expected to process up to 80,000 B/D of crude oil with first production in 2022. Subsea 7’s installation services contract is the latest Chevron award for its Anchor field project. First oil from the project is expected in 2024. The company announced both contract awards simultaneously.
Sandvik and Van Oord’s announcements come a week after oil major BP said it’s slashing 10,000 jobs. Phase 1 of the North Sea megaproject—Norway’s largest offshore development since the 1980s—has come on stream. Johan Sverdrup is expected to produce 660,000 BOPD at its peak. Aker BP expects the unmanned facility, a further development of the Valhall field in the Norwegian North Sea, to recover 60 million BOE. Startup is expected sometime this fall.
Phase 1 of the North Sea megaproject—Norway’s largest offshore development since the 1980s—has come on stream. Johan Sverdrup is expected to produce 660,000 BOPD at its peak. Aker BP expects the unmanned facility, a further development of the Valhall field in the Norwegian North Sea, to recover 60 million BOE. Startup is expected sometime this fall. After seeing a significant increase in the price level for subsea equipment, Equinor says it is realizing the ways in which standardized subsea templates help build financial competitiveness.
Subsea 7’s installation services contract is the latest Chevron award for its Anchor field project. First oil from the project is expected in 2024. The company announced both contract awards simultaneously. The new contract awards could be worth up to $800 million. Described as Brazil’s first-ever integrated SPS and SURF project, the development will include 19 wells, approximately 130 km of rigid risers and flowlines, and 35 km of umbilicals.
Rajaratnam, Sabesan (Subsea 7) | Bedrossian, Arek (Subsea 7) | Roy, Alan (Subsea 7) | Lacerda, Narciso (Subsea 7) | Cherkaoui, Saad (Subsea 7) | Giraudbit, Sonia (Subsea 7) | Gitahy, Leonardo (Subsea 7)
The Electrically Heat Traced Flowline (EHTF) is characterised by a combination of high performance dry annular thermal insulation of Pipe-in-Pipe (PiP) with a restricted electrical heating capability provided by helically wound copper wires laid between the inner pipe and the insulation in the annulus. The main advantage of EHTF are: future tie-back integration, unlock marginal reserves, access to HPHT pipeline, extend field life and maximise economic recovery and reduction in chemical and energy usage operational flexibility in controlling the flowline temperature and preventing the formation of wax and hydrates in shutdown conditions. Fibre optic cables are deployed in the EHTF system to measure the temperature of the flowline.
This paper presents the development of a detailed finite element model to predict the mechanical behaviour of the helically wound cabling during reeling operations. The wires and cables were represented explicitly in the model as initially straight and then wound helically around the inner pipe with specified pre-tension. The EHTF PiP system was then cyclically deformed against a former to simulate the reeling process. A fibre optic cable (FOC) containing a local imperfection due to denting was included in the model to assess the impact of reeling process on the continued acceptability of accidentally dented FOC.
The effects of friction between the cabling and the inner pipe and insulation surfaces, the pre-tensioned helical winding process and helix pitch, and the restraint provided by the thermal insulation layer and centralizers, were all investigated. Physical tests were conducted to establish the cyclic material properties of the electrical wires and results from these tests were used to calibrate the FE model.
This paper details Subsea 7's technical expertise in modelling the highly complex behaviour of the EHTF cabling system as it experiences multiple bending cycles due to reeling. The paper highlights some important key results describing the behaviour of the wires and consequent predictions of integrity which have since been verified through full scale physical tests. The FE modelling also contributed to the insight gained regarding the overall behaviour of the system.
Nilsen-Nygaard, Viktor (Equinor ASA) | Hanssen, Ståle (Equinor ASA) | Groenewegen, Matthijs (Allseas Engineering B.V.) | Vlaanderen, Stef (Allseas Engineering B.V.) | Apeland, Kjell Edvard (Equinor ASA) | Berge, Jan Olav (Equinor ASA) | Instanes, Frode (Equinor ASA) | Armstrong, Michael A. P. (Isotek Oil&Gas Ltd)
In order to deliver on the ambitious schedule for the Johan Sverdrup development, the operator and the Johan Sverdrup-partners also needed to make some innovative bets on new technology. This paper explores two areas - innovations in installation and pipeline technology - that played a key role in the development of the mega-project. In particular the decision to qualify and become the world s first user of the single-lift installation technology developed for the vessel Pioneering Spirit ended up changing the very concept for construction, installation and completion of three of the four topsides that make up the Johan Sverdrup field center in the first phase of the development. The technology - developed by the installation contractor and qualified for first use worldwide by the operator - saved an estimated 2.5 million offshore manhours from the offshore completion phase, which significantly reduced safety risks and helped shave months off the development schedule. The first-ever use of the technology to install topsides took place in June 2018 with the singlelift installation of the drilling platform topsides on the Johan Sverdrup field. And in March 2019, the two remaining topsides weighing a total of 44,000 tonnes were lifted in place in the span of only 3 days, including the heaviest offshore lift ever executed with the installation of the 26,500 tonnes processing platform. The paper also intends to explore how the same innovative mindset and focus also played a role in introducing new pipeline technology - in particular, the world s first use of remote-controlled and diverless hyperbaric welding of the ''36 oil export pipeline to the Johan Sverdrup riser platform. The paper also discusses how the project benefited from further industrialization of the hot-tapping technology used for the first time by the operator in 2012 on the Åsgard subsea project, when connecting the Johan Sverdrup gas export pipeline to the'live' Statpipe gas pipeline.
The main objective of this paper is to demonstrate a cost-effective, user-friendly and highly reliable subsea pipeline and subsea structure design automation method developed on a cloud-based digital field twin platform. The FEED and detail design phase of the subsea pipeline and subsea structures are normally quite long and need to run several analyses sequentially to achieve the desired results. In this cloud-based design automation method, a significant number of calculation hours are saved due to systematic and sequential approach with minimum remediation work by reducing human error.
In this proposed design automation framework, all the standard pipeline and subsea structure design calculations including code checks based on design standards are performed through a web-based graphical user interface (GUI) designed in cloud-based digital field twin. In the design phase of the subsea pipeline, some more advanced level pipeline finite element analyses are performed for buckling and walking assessment. The design phase of the subsea pipeline consists of different analytical as well as finite element (FE) calculations which are performed systematically and sequentially in cloud-based digital field twin. Various pipeline engineering calculations are performed sequentially and systematically in the cloud using the metadata information available from the digital field data. Some of the standard engineering calculations implemented in the digital field twin are wall thickness calculation (based on design standards), on-bottom stability analysis, span analysis, pipe end expansion analysis, pipeline global buckling analysis etc. All the standard pipeline and subsea structure design calculations are developed in python, which is connected to the cloud-based digital twin through API. For advanced FE analyses for lateral buckling and pipeline walking, the preliminary susceptibilities are assessed through analytical calculations developed through python-based API. For the pipeline FE analysis for lateral buckling and walking assessment, pre-processor and post-processor are developed in python based on various metadata (pipe data, soil, environment) information available in the subsea digital field.
The pipeline design calculation outputs are stored in a standardised report format in the cloud platform. The proposed GUI developed for the pipeline and structural design automation is user friendly and the whole process is automated through the python API. This design automation approach significantly reduces the total project cost. Digital Field Twin integrate all the subsea pipeline and structural design calculations and automate the report generation. The proposed digital field twin is very much beneficial for the early stages in the projects where some changes are expected.
This subsea pipeline and structural design automation system built on the cloud-based digital field twin through API so that it works as an integrated system giving 3D digital field diagram to perform all the design calculations in one digital platform.
With the increasing development of high temperature/high pressure wells, particularly in deep water, riser designs using conventional strength material are utilising increasingly heavier wall thickness pipe, up to 50mm wall thickness in 8" and 10" OD X65 linepipe. Such riser designs are challenging existing seamless linepipe manufacturing and girth welding capabilities. Consequently, Subsea 7 undertook a linepipe material and welding qualification programme in order to provide confidence in the use of heavy wall pipeline and riser designs and installed by R-lay.
Riser designs with heavy wall thickness may impose excessive top tension requirements making them difficult to install cost effectively using R-lay technology. Additionally, such risers may pose excessive payloads on the floating production vessel. Fatigue requirements at the hang off and touch down zones pose further limitations on the use of heavy wall risers. These limitations may impede cost effective development of HP/HT fields.
The application of high strength steel for HT/HP applications as riser material is an attractive alternative. High strength steel reduces the wall thickness and thereby reduces payloads on floating hostfacility and top tension requirements for R-lay installation. Application of high strength steel improves the top end interface design also, due to reduced tension. The qualification status of reelable X80, including CRA lined pipe will be presented.
Another challenge for HP/HT riser application is the top end connection to the floater. Traditional flex-joint solutions may not be feasible, requiring a Stress Joint at the top. For ultra-deep water conditions, special stress joints with titanium may be necessary. The limitation and application of such top end solutions for HP/HT application will be presented in this paper.
Following the drop of oil prices during 2015 we have seen an increased attention from operators on using new technology, in particular active heating technologies. This paper presents an update to experience from early implementation with lessons learned to recent technology development of what today is the only field proven electric heating technology for rigid flowlines per today - Direct Electric Heating (DEH). It also discusses Electric Heat Tracing as promising technology undergoing qualification - but the main focus is on DEH. DEH had its technology qualification carried out in the 90-ties and early 2000's while the more recent years has focused on achieving long distance tie backs, qualification for deep water projects but also design alteration opening for cost reduction. Increased number of operators: During the first 10 years, all projects were in operation in the North Sea whereas during the last 8 years other operators has started using the technology, as well as applications in harsher environment and deeper waters. Deep water: Following internal testing to gain more information on material data of steel and copper, combined with an update in analysis technique - previous over-conservatism in design process can be reduced such that a more accurate analysis can be carried out. Consequently, cable designs which previously only were applicable for depths down to less than 800m WD can now be used at 1500m WD. Long distance step-outs: Wet design XLPE insulation to higher electrical gradients has been now successfully qualified, allowing DEH to be applied on longer distance tiebacks than before Technology improvements A 3-year R&D on high frequency DEH gives both technical advantages for interference with other subsea equipment, reduced AC corrosion as smaller conductors which leads to a significant cost reduction. With the above technical improvements alone or combined, and a better DEH system than that was qualified in year 2000 is now available to the market.
The design of an electrically heated flowline is based on several thermal requirements, which significantly affect the design and the CAPEX of such a solution. In particular, the heat-up criteria which define the minimum duration - usually 48 hrs - required to heat-up a flowline from ambient temperature to the ready-for-restart temperature is often the most demanding one and drives the electrical system requirements in a very conservative way compared to the other heating criteria. The objective of this paper is to demonstrate how the industry could remove this heat-up requirement and adopt a "temperature maintenance operating philosophy" to optimise the design of electrically heated flowlines. Heat-ups from ambient temperature would still be achievable, in less than seven days.
This approach is particularly well suited to heat traced pipe-in-pipe, where the heat lost to the environment is extremely low. For these highly insulated flowlines, the temperature maintenance duty power is significantly reduced, compared to the required power for heat-up phases.
This paper investigates the potential benefits and the feasibility of this change in the design requirements. Initially, impacts on the overall heated flowline design and particularly on the electrical architecture have been assessed as well as the associated CAPEX reduction. Secondly, analyses of the corresponding operating procedures have been conducted to assess feasibility. Finally, OPEX aspects have been taken into account to conclude on the overall interest of the solution.
Case studies show that applying a temperature maintenance philosophy to heat traced pipe-in-pipe would lead to significant CAPEX savings thanks to optimised electrical system design. Regarding shutdown costs, although the results depend on the assumptions considered, the temperature maintenance philosophy appears preferable as it results in lower power consumption and shorter shutdowns, the majority of the time. Furthermore, fewer heat-up phases result in safer procedures with regard to hydrate melting risks while reducing the power applied reduces the electrical stress on the heating system.
All the assessments have been conducted based on Electrically Heat Traced Flowline (EHTF) technology however the same exercise could be performed for other electrically heated flowline technologies and could demonstrate similar benefits.