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Norway and the U.K. look to be among the most active regions for subsea tiebacks in the short-term.
The area is rich in infrastructure in both deep and shallow waters as well as operators looking to produce reserves of oil and gas. The North and Norwegian seas are home to many of the projects scheduled to come online by the end of 2025.
Never wanting to be left behind, the U.S. also has developments set to come online by 2025, with a number of projects sanctioned or in the planning stages.
Tying back a smaller pool of reserves to an existing host facility lowers the carbon intensity of the development and leverages production capacity at existing facilities. Subsea tiebacks are also an economic way to produce smaller discoveries.
The following project-by-project summary looks at the latest developments of these subsea tiebacks. Information was gathered from public information and analysis. The first in a two-part series, this is a look at some of the subsea tieback projects scheduled to be online by 2025, as well as projects that have started production since last year’s reports published. Part two will cover tieback projects set to come onstream in 2026 and beyond.
In December, Energean farmed into the Anchois development offshore Morocco, acquiring interest and operatorship of the Lixus license.
Energean and Chariot plan to drill an appraisal well on the Anchois Field this year, targeting an additional 11 Bcm of gross un-risked prospective resource. Following the drilling of the appraisal well, Energean has the option to increase its working interest in the Lixus license by 10% to 55%.
The development sits in the Tanger-Larache exploration area of the Lixus license, 25 miles off Moroccan coast, in 2,700 ft of water. FEED on the development, which began in 2022, concluded in March. FEED was primarily conducted by SLB and Subsea 7’s Subsea Integration Alliance.
The consortium provided well completions, subsea production systems, subsea umbilicals, risers and flowlines and a central processing facility.
The field will be developed in two phases, with first gas expected in 2024. Phase 1 consists of three production wells, including the already drilled Anchois-1 and Anchois-2 wells. The third producer is planned to be brought onstream by 2027 along with an onshore processing facility. The wells will tie back to an onshore central processing facility that will have an initial capacity of 105 MMcf/d.
Initial production is expected to reach 40 MMcf/d and ramp up to 70 MMcf/d three years later. Phase 2 will include four to six additional production wells. Production is expected to plateau at 100 MMcf/d.
Energean operates the Lixus license with 45% interest on behalf of partners Chariot with 30% interest and Morocco’s National Office of Hydrocarbons and Mines (ONHYM) maintaining the final 25% of the stake.
The plan for development and operation (PDO) for the Equinor-operated Andvare Field was approved June 2023, and production is expected in 2024.
Previously known as the Gjøk Field, the development holds just under 2 Bcm of gas. The discovery lies in 1,243 ft of water in Block 6507/3P (PL159B) offshore Norway.
Andvare is being tied back to the nearby Norne Field in the Norwegian Sea. The Andvare well will be drilled as a sidetrack from one of 15 existing subsea templates. Andvare will use existing infrastructure and an available Norne well slot, allowing for a fast-track development of the gas discovery.
The Transocean Encourage harsh-environment semisubmersible rig will carry out drilling operations. Aibel will modify the Norne FPSO to accommodate production from Andvare.
Chevron’s deepwater Ballymore subsea tieback in the U.S. Gulf of Mexico (GoM) is expected to reach first oil in 2025.
Discovered in 2018 and sanctioned in 2022, Ballymore involves three production wells that will produce an estimated 75,000 bbl/d to Chevron’s nearby Blind Faith production semisubmersible in Mississippi Canyon Block 650. Ballymore, in 6,550 ft water depth in Mississippi Canyon Block 607, is targeting 150 MMboe.
In 2023, Expro secured a three-year $15 million contract for the first deployment of its single shear and seal high-debris 15,000 psi ball valve assembly. The mechanism will form part of Ballymore’s completion and intervention system.
Williams is providing offshore natural gas gathering and crude oil transportation services and onshore natural gas processing services. Subsea7 is installing the steel catenary riser, flowline and control system. Worley is handling engineering and design services for the integration and subsea tieback of the field and provided procurement services for the topsides.
Chevron operates the field with 60% interest, while partner TotalEnergies holds 40% interest.
BP delivered the first phase of its Cypre project offshore Trinidad in mid-October 2023.
The Cypre development is 48 miles off the southeast coast of Trinidad within the East Mayaro Block, in 260 ft of water. It ties back to the BP-operated Juniper platform via two new 9-mile flexible flowlines. The development includes seven wells and subsea trees. At peak production, the development is expected to produce between 250 MMcf/d and 300 MMcf/d.
Cypre will access power from Juniper, eliminating the need for additional power generation.
Sanctioned in 2022, drilling began in 2023, and the project was brought online later that year.
OneSubsea and Subsea Integration Alliance handled concept and design, engineering, procurement, construction and installation (EPCI) of a two-phase LNG tieback to the Juniper platform, in addition to topside upgrades. OneSubsea delivered subsea production systems.
BPTT is the sole owner and operator of Cypre.
After reaching FID in March 2023, Shell’s Dover project is expected to add 21,000 boe/d to the Appomattox production semisubmersible in the U.S. GoM by 2025.
Discovered in 2018, Dover is Shell’s sixth discovery in the Norphlet geologic play. Dover sits in 7,500 ft of water in Mississippi Canyon Block 612 and will tie back to the nearby Appomattox platform.
The subsea development concept calls for two production wells to be produced through a 17.5-mile flowline and riser to Appomattox.
Shell holds 100% interest in the Dover discovery and 79% interest in its operated Appomattox production hub.
Equinor submitted the PDO for its Eirin gas field development in September 2023. The project, expected onstream in 2025, will be a subsea facility tied to the Gina Krog platform in the North Sea and cost NOK 4 billion (US$370 million).
Proven in 1978 as part of the Gina Krog development, development of the Eirin Field was put on hold until recently. Development plans involve Eirin being tied back to Gina Krog through a production flowline and umbilical. The development is planned to extend Gina Krog’s productive life from 2029 to 2036.
Ocean Installer AS was awarded an EPCI installation and commissioning contract in October 2023.
Equinor operates the field with a 78.2% interest. KUFPEC Norway holds the remaining 21.8% interest.
Norway’s Havtil in November 2023 approved the ConocoPhillips Skandinavia AS plan for Eldfisk North. First production is expected in 2024.
Eldfisk North is in PL018 offshore Norway in 230 ft of water in the North Sea. The field, in Block 2/7, has an estimated resource potential between 50 MMboe and 90 MMboe.
The PDO for the $1.2 billion Eldfisk North project calls for three, six-well subsea templates tied back to ConocoPhillips’ existing Eldfisk complex 4 miles away.
The plan includes drilling up to 14 wells, with nine of the wells being producers and the other five for water injection. The West Elara jackup is carrying out the drilling program.
Final deliveries of the project’s subsea infrastructure are scheduled for 2024. Aker Solutions is providing vertical subsea trees, wellheads, control systems, three six-slot templates with integrated manifolds and associated services.
ConocoPhillips Skandinavia AS operates the Eldfisk Field with 35.112% interest, on behalf of partners TotalEnergies EP Norge AS with 39.896%, Vår Energi AS with 12.388%, Equinor AS with 7.604% and Petoro AS with 5%.
The Frosk Field, tied back to the Alvheim FPSO about 15 miles away via existing subsurface structures on Bøyla and Alvheim, started production 18 months after the operator submitted the PDO to the Norwegian Petroleum Directorate (now known as Norwegian Offshore Directorate).
Discovered in 2018, Frosk, located in PL340 and PL869, holds 10 MMboe of recoverable reserves in 393 ft of water.
The Frosk project engaged an alliance of Aker BP, Odfjell Drilling and Halliburton for drilling and completion of new wells, and an alliance of Aker BP, Subsea 7 and Aker Solutions for the subsea development.
Aker BP operates the field with an 80% interest. Vår Energi holds the remaining 20% interest.
The project will deliver production from three Great White wells back to the Shell-operated Perdido spar. The wells are expected to produce up to 22,000 boe/d, with production expected to begin in April 2025.
The Perdido spar, which lies in 8,000 ft water depth in Alaminos Canyon Block 857, has been onstream since 2010, and has a peak production capacity of 125,000 boe/d.
Shell operates the Perdido spar with 35% interest on behalf of partners, Chevron with 37.5%, 3C Perdido Holdings LLC holding with 26.5% and BP with 1%.
Equinor and its partners are developing a cluster of gas and condensate discoveries in the Norwegian Sea that were once considered stranded assets, with first production expected in 2025. Equinor and its partners in 2022 submitted the Haltenbanken East plan to develop these discoveries in nearly 1,000 ft of water.
Haltenbanken East will be developed as a unit covering multiple licenses and comprising six discoveries and three additional prospects tied back to the Equinor-operated Åsgard B platform. The discoveries hold 100 MMboe of recoverable reserves.
The discoveries are Gamma, Harepus/Mikkel South, Flyndretind, Nona, Sigrid and Natalia, and the prospects are Flyndretind Ile, Tussen and Rita. They are located in PL263, PL312, PL473, PL074 and PL471. Equinor is the operator of these licenses.
Equinor and its partners are bringing the assets online in two phases. The first phase, which will take place in 2024 and 2025, includes drilling six wells at five of the discoveries. Production from the first two wells is expected to begin in 2025, with the others going onstream as they are completed.
Phase two targets the last discovery and three prospects, which are planned to be drilled as sidetracks from existing wells.
In January, Aker BP was cleared by Havtil, the Norwegian Ocean Industry Authority, to begin using the newly installed subsea templates, control cables and pipelines at the Hanz Field development in the central Norwegian North Sea.
Hanz will be tied back to the Ivar Aasen platform 7 miles north of the field, with expected start up in the first half of 2024. The project, located in PL028B, sits at a water depth of 380 ft and holds reserves around 20 MMboe. Production is expected to start in 2024.
Aker BP operates the development with 35% interest on behalf of Equinor with 50% and Sval Energi with 15%.
After months of protests following FID in 2022, drilling on Shell’s Jackdaw development began in September.
Environmental group Greenpeace filed a legal challenge on July 26, 2022, one day after Shell made FID on the Jackdaw project, claiming it was done without checking the climate damage of burning the gas extracted. However, U.K. officials said that the North Sea Transition Authority (NSTA) cleared the project, saying it would not have a significant effect on the environment.
According to Shell, the Jackdaw Field has the potential to supply more than 6% of the U.K.’s gas production. Production is expected to begin in 2025, reaching an estimated 40,000 boe/d.
Drilling on the 100% Shell-owned Jackdaw will be conducted by the Valaris 122 jackup rig. The project calls for a not permanently attended wellhead platform (WHP), along with four production wells and a 19-mile pipeline tying back the Jackdaw WHP to the Shearwater gas hub in the U.K. North Sea.
Kvaerner performed early phase design engineering of the WHP and Aker Solutions provided EPCI of the WHP. TechnipFMC will provide pipelay for the tieback to the Shearwater platform, as well as an associated riser, spool pieces, subsea structures and umbilicals.
Located in blocks 30/02a, 30/02d and 30/03a, Jackdaw is in 256 ft water depth.
Kobra East & Gekko
Production at Aker BP’s Kobra East & Gekko (KEG) project began in October 2023. Initially expected to begin in 2024, the KEG project began both sooner and under the $712 million budget that Aker BP planned.
The KEG project, targeting estimated recoverable reserves of 40 MMboe, is tied back to the Alvheim FPSO, 10 miles away. The project is located in PL203 in the central North Sea in 410 ft of water offshore Norway. The Kobra East Field was discovered in 2016, while the Gekko Field was discovered in 1974.
Aker BP operates the development with 80% interest on behalf of partner ConocoPhillips Skandinavia, which holds 20%.
In September, Havtil gave Equinor the go-ahead to begin drilling at its Kristin Sør (South) project.
Transocean’s Spitsbergen, a sixth-generation semi-submersible rig capable of drilling HP/HT formations, will handle drilling operations on the project.
Kristin Sør, which was sanctioned in 2021, consists of the Kristin Q and Lavrans discoveries in the Norwegian Sea. The Kristin Q HP/HT discovery is located in the southern part of the Kristin Field while the Lavrans discovery is approximately 6 miles southeast of the existing Kristin Field in a water depth of 920 ft. Discovered in 1995, Lavrans was appraised with two appraisal wells.
The US$735 million Kristin Sør project is expected to start production in 2024, remain online for 11 years and recover 58 MMboe of reserves.
Aker Solutions has a contract for the subsea template with four standardized vertical subsea trees for the Lavrans center, as well as a manifold for the Kristin Q Field. TechnipFMC was awarded an EPCI contract for rigid pipelines, static and dynamic umbilicals, as well as pipeline and marine installation of the subsea production facilities.
The wells will tie back to the Kristin production semisubmersible.
The two deepwater discoveries are tied back to Talos’ Ram Powell TLP in 3,200 ft water depth in the Viosca Knoll area of the GoM. The TLP is 9 miles from the Lime Rock discovery and 4 miles from the Venice discovery. Production from both wells flow to a shared riser system at Ram Powell.
Talos acquired the Lime Rock prospect in Lease Sale 256 in 2020 and later identified the Venice prospect within the existing Ram Powell unit acreage.
The initial combined gross production rate exceeded 18,500 boe/d, averaging about 45% oil and 55% liquids. Talos estimates a combined gross ultimate recoverable resource between 20 MMboe and 30 MMboe.
Louisiana-based firm EDG installed the new subsea infrastructure on the Ram Powell TLP necessary to accommodate the tiebacks. EDG also upgraded facilities on the TLP as well.
Talos operates the two deepwater discoveries with 60% working interest.
Discovered in 2013 and sanctioned in 2019, the MJ Field is 20 miles from the Gadimoga onshore terminal on India’s east coast in 3,900 ft of water. MJ, an HP/HT gas and condensate field, will have eight production wells, with peak production expected to reach 12 MMcm/d of gas and 25,000 bbl/d of condensate.
The Ruby FPSO is processing and separating the condensate, gas, water and impurities before sending the gas onshore for sale. Condensate is stored on the FPSO before offloading to shuttle tankers for supply to Indian refineries.
The MJ gas and condensate field is the third project in the Reliance-operated KG D6 Block being developed in partnership with BP. Production from the R Cluster started in December 2020 and production at the Satellite Cluster began in April 2021. At its peak, production from the KG D6 block will account for a third of India’s domestic gas production.
Reliance holds a 66.67% operated interest in KG-D6, with BP holding the remaining 33.33%.
Located in Block 22/24h in the central U.K. North Sea, BP’s Murlach oil field is scheduled to begin production in 2025. The project, which is in 310 ft of water, aims to recover approximately 25.9 MMbbl of oil and 21.2 Bcf of gas.
In January, Wood plc secured a two-year contract to modify the topsides at Murlach to support the subsea tieback. Wood will handle engineering, procurement, construction and commissioning services to repurpose existing equipment at the central processing facility at the Eastern Trough Area Project (ETAP) to handle production from two new wells.
Wood had previously carried out pre-FEED and FEED work for the Murlach project.
The development plan, which was approved in October, calls for drilling two production wells and tying them back to a new manifold, along with a gas lift flowline installation from BP’s existing ETAP platform to the Murlach manifold and tie-ins to the repurposed Shell’s Heron A production flowline, among others.
BP Exploration Operating Company (BPEOC), a subsidiary of BP, is the operator of the Murlach project with an 80% stake in the field. NEO Energy Central North Sea holds the remaining 20% interest.
Approved for development in 2019, Seagull was developed by Neptune Energy as a subsea tieback to the central processing facility of the BP-operated Eastern Trough Area Project (ETAP) in the central North Sea, around 140 miles east of Aberdeen. The project in Block 22/29C is a four-well development located 10 miles south of ETAP in a water depth of 295 ft. It is the first tieback to the ETAP hub in 20 years.
The field is expected to produce around 50,000 boe/d. Production is delivered via a three-mile subsea pipeline connected to an existing pipeline system. A new 10-mile umbilical links the ETAP facility to the Seagull Field and provides control, power and communication services between surface and seafloor.
The VALARIS 248 jackup drilled four wells for the project. TechnipFMC manufactured, delivered and installed subsea equipment including wellheads, Christmas trees, an umbilical, flowlines and more.
BP, with a 50% stake in Seagull, operates the production phase of the development. Neptune Energy holds a 35% stake in Seagull and operated the field through the development phase, drilling wells and installing subsea equipment. JAPEX holds the remaining 15% interest.
Woodside’s Shenzi North subsea tieback in the GoM began production to the Shenzi tension leg platform (TLP) in September 2023. First production was targeted for 2024, but the field came online only 26 months after reaching FID.
Woodside made its FID on Shenzi North, a two-well subsea tieback to the Shenzi TLP in Green Canyon Block 653, in July 2021. Shenzi North is in Green Canyon blocks 608 and 609 in about 4,300 ft water depth.
Shenzi was discovered in 2002, and the BHP-operated Shenzi TLP began production in 2009. When BHP and Woodside merged in June 2022, Woodside took over operatorship of BHP’s GoM leases. The TLP has a production capacity of 100,000 bbl/d and 50 MMcf/d.
Trendsetter Engineering delivered two subsea manifolds, two high intgrity pressure protection systems (HIPPS) and Trendsetter Connection System clamp connectors. HIPPS modules allow existing flowlines, risers and topside facilities to be used to tie in the Shenzi North discovery to the Shenzi TLP. Proserv assisted with the HIPPS control system, and ATV assisted with the provision of the HIPPS shutdown valves.
Woodside operates Shenzi and Shenzi North with 72% interest on behalf of Repsol with the remaining 28% interest.
Talos Energy discovered commercial quantities of oil and natural gas at its Sunspear prospect in July 2023.
The company’s preliminary analysis indicated approximately 260 ft of gross true vertical thickness of oil pay. Talos expects gross production rates of 8,000 boe/d to 10,000 boe/d from gross recoverable resources of 12 MMboe to 18 MMboe.
The company plans to develop the Sunspear discovery in 2,211 ft water depth through the Prince Tension Leg Platform (TLP), which it acquired through its 2023 purchase of EnVen. Located in Ewing Bank Block 1003, the Prince TLP was installed in August 2001 in 1,490 ft of water, and designed for a 20-year lifespan. First oil is expected in 2025.
Hibiscus reached FID on its Teal West project in 2023.
Production on the field, which lies in Block 21/24d of the Central North Sea in 250 ft of water, is expected to start in 2025. The field will be tied back to the existing Anasuria FPSO, which is owned by Anasuria Hibiscus.
Production is expected to peak at 59,000 bbl/d and 9.8 MMcf/d of gas.
The development plan for the Teal West Field includes drilling two subsea oil wells, one water injection well, a drill center, new flowlines, control umbilicals and risers. The initial development well is planned to be drilled in mid-2024 with the tieback being installed in the first half of 2025.
The field is being developed in three phases. Phase 1 will drill a production well that will be tied back to the Anasuria FPSO via a 3.4 km production flexible flowline.
Phase 2 is planned about 12 months to 18 months after production from the first well. It will involve the drilling of a water injector well and tying it back to the Teal West injection riser. Phase 3 involves drilling a second production well.
Petrofac has been providing operating services to the Anasuria FPSO since 2016.
NEO Energy withdrew from the field, selling its 30% stake in the project to Anasuria Hibiscus, a subsidiary of Hibiscus, in 2022. Hibiscus is the operator of the field with 100% interest.
After receiving approval for the Tyrving tieback in June 2023, development on the Aker BP-operated project halted in January when the Norwegian government found its environmental impact assessment to be insufficient.
An Aker BP spokesperson told Hart Energy the judgment is not final and legally binding and that work at Tyrving continues in accordance with the permits granted to the company.
Formerly known as the Trell & Trine project, the $700 million tieback development was halted after a lawsuit filed by environmental groups Greenpeace and Nature and Youth invalidated three permits in the North Sea.
Tyrving consists of two discoveries. Trell, discovered in 2014, and Trine, discovered in 1973, are about 3 miles apart in PL102F/G and PL036E/F. The fields lie in 400 ft of water with recoverable resources of 25 MMboe. Production is to tie back to the Alvheim FPSO via the existing East Kameleon subsea manifold and begin in 2025.
For this project, Subsea7 was tapped to handle the majority of the EPCI of the pipe-in-pipe pipelines, spools, protection covers and tie-ins. Aker Solutions was chosen to deliver a subsea production system that included three horizontal subsea trees, two manifolds, associated equipment and close to 18 miles of subsea umbilicals.
Norwegian authorities accepted Equinor’s PDO for its operated Verdande Field development in June 2023. The $437 million Verdande subsea development will connect to the Norne FPSO, which has been producing since 1997. Production is expected to begin in fourth-quarter 2025 and run until 2030.
The project, comprising the Cape Vulture and Alve Northeast discoveries, is in 1,150 ft to 1,250 ft water depth and targets 36.3 MMboe of recoverable reserves.
Located in the Nordland Ridge area of the Norwegian Sea, production from Verdande will tie back to the existing Skuld Field and Norne FPSO facilities. A consortium of Subsea7 and DeepOcean will handle engineering, transportation and installation, which will include a 5 mile-long pipe-in-pipe production pipeline, flexibles, umbilical, subsea structures and tie-ins.
Equinor is the operator of the Verdande license with a 59.3% stake. Petoro AS holds a 22.4% stake, Vår Energi ASA holds 10.5%, Aker BP holds 7% and PGNiG holds 0.8%
Shell announced the FID on its U.K. North Sea Victory Field in January 2024 with the expectation that the field will come online in 2025.
Victory is in Block 207/1a in license P2596, 31 miles northwest of the Shetland Isles in 555 ft of water. The development plan calls for a single subsea well tied back 10 miles to existing infrastructure from the Greater Laggan Area system.
The well will be controlled from TotalEnergies’ Edradour manifold, 11 miles southwest, using a newly installed umbilical.
Shell expects the Victory Field to begin production in the middle of the decade and produce about 150 MMcf/d at peak, with most of the field’s recoverable gas expected to be extracted by the end of the decade.
Victory’s gas will head to the Shetland Gas Plant for processing before continuing through offshore pipelines in the North Sea to the National Grid entry point at St. Fergus near Aberdeen.
Shell completed the acquisition of a 100% interest in Corallian Energy in November 2022, giving it complete ownership of the project.
Discovered in 2021 and appraised in 2022, Winterfell will be tied back to the Occidental Petroleum-operated Heidelberg spar in Green Canyon Block 860, 13 miles away. Winterfell is in Green Canyon Blocks 943, 944, 987 and 988 in 5,200 ft water depth.
First oil is expected early in the second quarter of 2024 from three initial wells projected to deliver gross production of 22,000 boe/d.
The working interest parties include Beacon Offshore Energy Exploration LLC with a 35.08% interest, Kosmos Energy with 25.04%, Westlawn GOM Asset 3 Holdco LLC with 15% percent, Red Willow Offshore LLC with 12.5%, Alta Mar Energy (Winterfell) LLC with 7.55%, CSL Exploration LP with 4.5% and BOE with 0.33%.
2023-12-15 - Unit Corp.’s conditional dividend will only be payable if the company closes its previously disclosed sale of certain oil and gas properties in the Texas Panhandle by the record date.
2023-12-15 - APA Corp.’s dividend is payable on Feb. 22, 2024 to stockholders on record by Jan. 22, 2024.
2024-01-08 - Enterprise Products Partners’ distribution will be paid Feb. 14 to common unitholders of record by Jan. 31.
2023-12-11 - Hess Corp.'s dividend will be payable Dec. 29 to shareholders of record by Dec. 18
2024-01-01 - SM Energy’s $0.18 per share dividend will be payable on Feb. 5, 2024, to stockholders on record by Jan. 19, 2024.