Shut-down fields and decommissioning on the Norwegian shelf

What it means when a field is shut down

The Norwegian Offshore Directorate gives every field a status: approved for production once its plan for development and operation (PDO) is approved, producing, and shut down when production has ended. In the directorate data OESA retrieved on 28 Sep 2026, 29 of 141 fields are shut down, 101 are producing and 11 are approved for production.

Shut down does not mean cleared away. What follows is called decommissioning: the wells are plugged and the installations removed, reused or, in rare cases, left in place, a step the authorities call disposal. Cod shut down in 1998, but its platform was not removed until 2013 (norskpetroleum.no, read 24 Oct 2026). Status can also change back: Albuskjell, Vest Ekofisk and Tommeliten Gamma closed in 1998 but are now approved for redevelopment.

Why fields are shut down

A field closes when its income no longer covers the cost of running the installations and maintaining the wells. It has reached the end of its economic life. The reservoir is rarely empty; what remains simply cannot be recovered at a profit.

Many fields are produced by pressure depletion: reservoir pressure drives oil and gas up the wells, and as the reservoir drains, pressure and output fall together. Injecting water or gas slows the decline. Under pressure depletion Ekofisk had an expected recovery factor, the share of the oil produced, of 17 per cent; after water injection began in 1987, the estimate rose to over 50 per cent (norskpetroleum.no). Costs climb with age too. By the early 1990s the Ekofisk Centre needed a major rebuild because of seabed subsidence and rising operating and maintenance costs (Proposition No. 51 (2001–2002) to the Storting).

End dates are hard to predict. Varg’s decommissioning plan was approved in 2001 with production due to end in the summer of 2002, yet the field ran until 2016 (norskpetroleum.no). A platform can also live on as a host: Heimdal stopped producing from its own reservoir in 2020 but processed gas from other fields until mid-2023.

The decommissioning plan and the rules

Decommissioning is governed by Chapter 5 of the Petroleum Act (Norwegian Offshore Directorate, 2019):

• The licensees must submit a decommissioning plan (Section 5-1) to the Ministry of Energy no earlier than five and no later than two years before a facility is expected to go permanently out of use, or before the production licence expires.
• The plan has a disposal part on the technical and financial side and an impact assessment on the environment and other users of the sea, which goes out for public consultation.
• The ministry makes a disposal decision (Section 5-3) with a deadline, and the licensees must carry it out. If a facility is left in place, they are liable for damage caused wilfully or negligently (Section 5-4, as set out in Proposition No. 51 (2001–2002)).

The ministry has dealt with more than 20 disposal plans (norskpetroleum.no, updated 15 Oct 2025).

OSPAR Decision 98/3, under the convention protecting the marine environment of the North-East Atlantic, took effect on 9 February 1999 and bans dumping disused installations or leaving them at sea. Subsea installations, floating steel installations, steel installations with jackets under 10,000 tonnes and all topsides must come ashore. Derogations are possible for concrete substructures, the footings of large steel jackets installed before February 1999 and in exceptional circumstances, after consulting the other OSPAR countries (Norwegian Offshore Directorate, 2019). Norway holds two, for the Ekofisk tank and the TCP2 concrete substructure on Frigg (norskpetroleum.no), out of ten across the OSPAR area (OSPAR, read 24 Oct 2026). Pipelines are not covered and can generally stay if they have been cleaned and pose no hazard to bottom fishing (Report No. 47 (1999–2000) to the Storting, as summarised by the directorate).

Before the installations go, the wells must be permanently plugged, with at least two independent barriers qualified “from the perspective of eternity” (Norwegian Ocean Industry Authority, 2023). Plugging wells and removing installations offshore are the largest costs in a disposal project (norskpetroleum.no).

What happens to the installations

The shelf has 12 concrete facilities, 64 fixed and 20 floating steel facilities in operation, and nearly 500 subsea installations (norskpetroleum.no, updated 15 Oct 2025). Every one of them will eventually have to be dealt with:

• Removal is the norm. The installation is shipped to a licensed yard on land, such as AF Miljøbase Vats, for scrapping and recycling. About 98 per cent of the waste from the petroleum industry is recyclable steel (norskpetroleum.no).
• Reuse: when Jotun shut down in 2016, its FPSO was upgraded and moved to Balder and Ringhorne Øst (norskpetroleum.no).
• Leaving in place is the exception. The Ekofisk tank, a concrete storage tank installed in 1973, was left standing with its protective wall. Together they weigh about 1.1 million tonnes including ballast. Refloating them was estimated at NOK 2.7 to 3.4 billion in 1999 kroner, with a probability of loss of life of about 10 per cent (Proposition No. 51 (2001–2002)).

The directorate’s facility data (retrieved 28 Sep 2026) lists four installations as abandoned in place, among them the Ekofisk tank and Frigg TCP2, and four as partly removed, among them Heimdal.

Who pays

The licensees pay in proportion to their shares, but the costs are deductible against petroleum tax, where the combined marginal rate is 78 per cent (norskpetroleum.no, updated 8 Oct 2026). For a company in a tax-paying position, each krone spent on disposal therefore cuts its tax bill by 78 øre. The state also pays directly through Petoro, the state-owned company that holds the state’s licence interests (the SDFI), according to norskpetroleum.no. Petoro owns 20 per cent of Frigg (directorate data, retrieved 7 Oct 2026).

From 1986 the state instead covered a share of removal costs through a separate grant act. In 2003 the Ministry of Finance proposed repealing it and making removal costs deductible like other operating costs (Proposition No. 92 (2002–2003) to the Odelsting). According to norskpetroleum.no, disposal costs are relatively small compared with exploration, development and operating costs, but uncertain.

Shut-down fields on the Norwegian shelf

The table lists the 28 shut-down fields that have produced. Troll Brent B has neither a production start nor recoverable volumes in the data and is left out. Seven closed before 2000, two in 2000–2009 and 19 from 2010. Together they have produced about 492 million Sm³ of oil equivalent (o.e., see the units), with Frigg alone accounting for 116.66 million.

• Start and shut down are years from the status history. For Mime’s start-up and Yttergryta’s shutdown, norskpetroleum.no gives a different year, so those cells are blank.
• Last production is the last month with any output in the monthly figures, which begin in 2000. Veslefrikk and Flyndre show tiny volumes years after shutting down.
• Mill. Sm³ o.e. is recoverable volumes as of 31 Dec 2025 (Frøy and Lille-Frigg 31 Dec 2024). Remaining reserves are zero, so this is what the field produced.
• Operator is the current operator in the data. A dash means the field has neither an operator nor licensees there.

The Ekofisk area: Albuskjell, Cod, Edda, Tommeliten and Vest Ekofisk

Ekofisk was discovered in 1969 and in 1971 became the first field on the Norwegian shelf to produce oil (Proposition No. 51 (2001–2002)). Smaller fields around it piped their oil and gas to the Ekofisk Centre.

In 1998 five of them shut down: Albuskjell, Cod, Edda, Tommeliten Gamma and Vest Ekofisk (norskpetroleum.no). In August that year Ekofisk II came on stream, leaving many of the old installations, known as Ekofisk I, redundant. On 21 December 2001 it was decided that 14 steel platforms and the topsides of the Ekofisk tank would be removed (Proposition No. 51 (2001–2002)). The Tommeliten Gamma subsea template came out in 2001, the Edda and Vest Ekofisk platforms in 2012 and those on Albuskjell and Cod in 2013 (norskpetroleum.no).

Three of the fields are now coming back. In 2026 the redevelopment of Albuskjell, Vest Ekofisk and Tommeliten Gamma was approved, using subsea templates tied back to the Ekofisk Centre: two templates with six wells on Albuskjell, one with three on Vest Ekofisk and one with two on Tommeliten Gamma. Start-up is planned for 2028 for the first two and 2029 for Tommeliten Gamma (norskpetroleum.no, read 24 Oct 2026).

Nearby Tommeliten A was discovered in 1977, had its PDO approved in 2022 and came on stream in 2023 with two subsea templates tied back to the Ekofisk Centre (norskpetroleum.no). From August 2025 to July 2026 it produced 2.95 million Sm³ o.e., against 3.26 million from Ekofisk itself (directorate monthly figures, retrieved 7 Oct 2026).

The Frigg area and Heimdal

The Frigg gas field straddled the boundary between the Norwegian and UK sectors, with a Norwegian share of 60.82 per cent (Proposition No. 38 (2003–2004)). It produced from 1977 to 2004 and sent its gas through a 180-kilometre pipeline to St Fergus in the UK. The field had five platforms, three of them on concrete substructures, and also processed oil and gas from Frøy, Nordøst Frigg, Øst Frigg, Lille-Frigg and Odin (norskpetroleum.no). The satellites were small, and as the table shows, all of them closed before Frigg did.

Frigg is the largest field on the shelf where decommissioning has been completed. Offshore disposal work began in 2005 and was finished in 2010 (norskpetroleum.no). In 2003 it was decided that the steel structures and the TCP2 topsides on the Norwegian side would be removed. The TCP2 concrete substructure was allowed to stay because removal would carry an unacceptably high risk to life and cost considerably more, and the UK authorities let the two concrete substructures on their side remain (Proposition No. 38 (2003–2004)).

The area is now being developed again as Yggdrasil, with the Hugin A processing platform as its field centre. The PDOs for Hugin and Fulla, approved in 2023, include redeveloping Frøy with the Hugin B platform, Lille-Frigg with a subsea tie-back and Øst Frigg with a subsea template. Exploration wells in the lower parts of Øst Frigg and Frigg found an oil column, an oil-bearing zone in the reservoir, connected with the Hugin deposits. Start-up is planned for 2027 (norskpetroleum.no, read 24 Oct 2026).

Heimdal, which produced from 1985, later also processed production from fields including Atla, Skirne, Vale and Huldra. It served as a gas centre until mid-2023, and its decommissioning is due to be finished by the end of 2028 (norskpetroleum.no). Atla, Skirne and Vale shut down that same year.

Volve: a shut-down field you can study yourself

The Volve oil field, five kilometres north of Sleipner Øst, was developed with a jack-up drilling and processing facility and the storage vessel “Navion Saga”. It produced from 2008 to 2016, and the facility was removed in 2018 (norskpetroleum.no).

For students, Volve is special. In June 2018 Equinor announced that it and its partners would release all subsurface and operating data from the field, about 40,000 files, which academic institutions, students and researchers may use under the Equinor Open Data Licence (equinor.com, read 24 Oct 2026). You can follow a whole field from seismic to shutdown.

New fields on old infrastructure

As output from a field declines, capacity frees up in its processing plant and pipelines, and that capacity can be used for new discoveries. For most discoveries being considered for development, a tie-back to existing infrastructure is the most likely solution (norskpetroleum.no, read 24 Oct 2026). Byrding in the northern North Sea, for example, produces through a single two-branch well drilled from the Fram H-Nord subsea template, and its well stream is processed on Troll C (norskpetroleum.no). Tommeliten A and Hugin, described above, are other examples.

A satellite without its own processing plant in turn depends on its host, as Atla, Skirne and Vale did on Heimdal. How long the host will keep producing therefore matters a great deal when a discovery is assessed; see how to assess a discovery.

Explore the fields yourself

• The overview of all fields shows status, ownership and production year by year from 2000.
• The guide to offshore installations covers platform types and offshore platform construction, from discovery to producing field.
• Reading the Norwegian shelf explains field statuses, resource classes and units.
• The directorate’s FactPages and norskpetroleum.no on cessation and decommissioning.

Sources

• FactPages and FactMaps – Norwegian Offshore Directorate – field status, area, operator, status history, recoverable volumes, monthly production and facilities; in OESA’s data retrieved 28 Sep and 7 Oct 2026
• Cessation and decommissioning – norskpetroleum.no – decommissioning plan, the OSPAR derogations, Frigg, recycling and costs; updated 15 Oct 2025, read 24 Oct 2026
• Field pages – norskpetroleum.no – start-up, shutdown, removal and redevelopment for each field, read 24 Oct 2026
• Recent activity – norskpetroleum.no – tie-ins to existing infrastructure, read 24 Oct 2026
• On cessation of petroleum activities and disposal of facilities – Norwegian Offshore Directorate (2019, in Norwegian) – Chapter 5 of the Petroleum Act, OSPAR Decision 98/3 and pipelines
• The petroleum tax system – norskpetroleum.no – combined tax rate and deductions for decommissioning; updated 8 Oct 2026
• State organisation of petroleum activities – norskpetroleum.no – Petoro and the SDFI
• Proposition No. 51 (2001–2002) on the disposal of the Ekofisk tank and protective wall – regjeringen.no (in Norwegian) – Ekofisk I, the Ekofisk tank and liability under Section 5-4
• Proposition No. 38 (2003–2004) on the disposal of the TCP2 concrete substructure on Frigg – regjeringen.no (in Norwegian) – Norwegian share and the Frigg decisions
• Proposition No. 92 (2002–2003) on amendments to the Petroleum Taxation Act – regjeringen.no (in Norwegian) – the removal grant act and the proposal to make removal costs deductible
• Offshore Installations – OSPAR Commission – OSPAR Decision 98/3 and the number of derogations, read 24 Oct 2026
• Topic: keeping watch on well integrity – Norwegian Ocean Industry Authority (2023) – well barriers and plugging
• Volve data sharing – Equinor – the Volve dataset, read 24 Oct 2026

The guides are written by OESA students to explain concepts and how things fit together. They are not investment advice. Figures that are not definitions carry a source and a date; if you find an error, let us know at philipstave@oesa-global.com.