Dunlin FAQs

We are committed in our objective to ensure that all appropriate stakeholders are consulted as we progress the decommissioning of the Greater Dunlin Area, and that the necessary information is made available to enable informed decision-making.

General Information

  • What is the Greater Dunlin Area?

    The Greater Dunlin Area comprises the collective assets of Merlin, Osprey and Dunlin Alpha, plus associated infrastructure.

  • Where is the Greater Dunlin Area?

    The Greater Dunlin Area is located in Blocks 211/23 and 211/24 of the UK Continental Shelf, some 500km north-northeast of Aberdeen within the East Shetland Basin, and 11.2km from the boundary line with Norway. 

  • What is the Dunlin Alpha platform and when was it installed?

    Installed in 1977, Dunlin Alpha is a four-leg platform, constructed on a Concrete Gravity Base Substructure (CGBS), with a steel box girder modular support frame (MSF) based topsides supporting two levels of modules. The installation stands in 151m of water and is over 200m high from the seabed to the top of the drilling derrick. The concrete legs extend to 8m below LAT, with steel transition columns spanning the splash zone to support the topsides.

    The Dunlin Alpha topsides was originally designed as a drilling and production facility. The topsides is constructed over 3 levels and weighs approximately 19,640 t (dry).  The CGBS was originally designed to provide oil and water separation and storage prior to oil export and consists of 81 individual cells, arranged in a 9 x 9 matrix.  The CGBS weighs approximately 342,000 t including internal equipment in the legs and solid ballast in the CGBS base, and was not designed to be re-floated.

  • When did production start?

    Production from the Dunlin Alpha platform started in 1978, and from Osprey and Merlin in 1991 and 1997 respectively.

    The Osprey field facilities comprise separate production and Water Injection subsea manifolds, linked to 8 production and 4 water injection wells located some 7km north of Dunlin A in water depths ranging from 155m to 165m.  The Merlin field facilities comprise three subsea production wells and a water injection well, located 7km west of Dunlin A in water depths ranging from 155m to 165m. Subsea fields are connected to Dunlin A via a variety of pipeline bundles, individual steel or flexible pipelines and control systems. This infrastructure contains further structural elements such as tow-heads and cross-over manifolds.  A 23km long, 119mm diameter electric power cable runs in a seabed trench from the nearby Shell-operated Brent Charlie platform to Dunlin A, through which available electrical power, generated on Brent Charlie can be supplied to Dunlin A.  A 10.2km long, 100mm diameter gas pipeline was installed during 2012 to import fuel gas to Dunlin A from the NLGP system via Thistle. The pipeline is trenched and backfilled along its entire length.

  • What did Fairfield do to maximise production at the Greater Dunlin Area?

    Fairfield became a late life operator in 2008 with an agenda to invest in and revitalise Dunlin production, and took the previously outsourced duty holder remit in 2014 to become a fully-fledged production licence and asset operator. 

    During this time, with the inclusion of proceeds from the sale of oil & gas, Fairfield, its investors and Dunlin JV Partners invested hundreds of millions of pounds in the Greater Dunlin Area.  Comprehensive studies were undertaken to understand all late life vulnerabilities and help focus investment on most critical improvement areas with a view to extending life out beyond 2025. The investments made included Drilling systems upgrades, Fuel Gas import infrastructure, ESP wells on the sub-hydrostatic Block 10/14 reservoir, power generation enhancements, Service water and WI Pump refurbishment and additional plant improvements to enhance water injection rates and thereby increase well productivity. Two over-riding integrity challenges that in the end influenced the ability to continue investment in Dunlin were a) the Subsea pipelines to Osprey and to Merlin fields, which along with riser systems needed replacement and b) accelerated deterioration of the Dunlin A well conductors which were suffering increased failures at the -10m conduction guideframe. These together would have required a further $100M plus of investment to extend the field life at a time when crude oil price was dropping and forecast to stay low.

  • How much oil has been recovered?

    Over 522 million barrels of oil has been recovered from the Greater Dunlin Area during 37 years of operations.

  • When did production terminate?

    The intention to cease production from the Greater Dunlin Area was announced in May 2015.  Following the demonstration of achievement of Maximising Economic Recovery (MER) from the oilfields, approval for Termination of Production was agreed with the Oil & Gas Authority on 9 July 2015. Last production was exported from Dunlin on 15th June with official COP subsequently confirmed to have occurred on this same date.

Decommissioning Information

  • What is decommissioning?

    Decommissioning commences with a process by which options for the physical removal and disposal of facilities/structures at the end of their working life are comparatively assessed.  Subsequently, a plan of action is developed by the operator, approved by government and thereafter implemented. The overall timescale for decommissioning activity is several years, as it needs to take into account many diverse factors and involves many stakeholders.

  • Why was the decision taken to decommission Dunlin?

    A combination of flow rates, prevailing oil price, the need for major investment in subsea infrastructure and conductor integrity issues, meant that decommissioning was the appropriate course of action.  

  • What are the decommissioning project’s key objectives?

    This is a multi-year project that has been subject to a robust planning process. The project’s key objectives are the safe and cost-effective execution of activities in full compliance with the approved Decommissioning Programme(s), namely: the plugging and abandonment of the Dunlin Alpha platform wells; Dunlin Alpha topsides removal and derogation of the Dunlin concrete gravity base and legs to the approved state; the plugging and abandonment of the Osprey and Merlin subsea wells; the removal and/or decommissioning in-situ of the Dunlin, Osprey and Merlin subsea infrastructure; the onshore recycling / disposal of topsides; and development of an agreed plan for the management of post-removal ongoing obligations.

  • How long will decommissioning of the Dunlin facilities take?

    In recognition of our Decommissioning Provisioning obligations, we began the long-term planning for the Dunlin decommissioning in 2010 although at that time the plan was to invest to extend the operational life of the Greater Dunlin Area fields and facilities to beyond 2025.  Following cessation of production at the facilities in June 2015, a detailed planning process for the decommissioning of the facilities was commenced.  We recognised this to be a complex and technically challenging undertaking that will involve a multi-phase, multi-year process.

  • How much will Dunlin decommissioning cost?

    Depending upon the final scope of the project, agreed through the Decommissioning Programme and Stakeholder Engagement process it is anticipated that the costs will be several hundred million pounds. A more accurate estimate will be possible once all aspects of the decommissioning project have been subject to evaluation, consultation and final determination

  • What will happen to redundant pipelines?

    Following completion of the stakeholder engagement and comparative assessment process for Greater Dunlin Area subsea infrastructure, Decommissioning Programmes have now been approved by BEIS for Osprey, Merlin and Dunlin subsea infrastructure respectively.

    For the Osprey Field, all surface laid pipelines will be removed, whilst the Osprey Bundle system will be decommissioned in-situ and made safe to other users of the sea.

    For the Merlin Field, the Merlin water injection pipeline will be fully removed, whilst the Merlin oil production pipeline will remain trenched and buried under the seabed.

    For Dunlin Field subsea infrastructure, the Dunlin Fuel Gas Import (DFGI) pipeline will remain trenched and buried under the seabed.

  • How is decommissioning activity regulated?

    In the UK sector of the North Sea, there is a clearly defined regulatory regime controlling the decommissioning of offshore oil and gas installations. Under the Petroleum Act 1998, as amended by the Energy Act 2008, it is a requirement to decommission offshore facilities at the end of their producing life. Operators have to submit detailed programmes for the decommissioning of offshore installations and pipelines which are considered on a case-by-case basis by the Department for Business, Energy & Industrial Strategy (BEIS) via its Offshore Decommissioning Unit (ODU), which is responsible for ensuring compliance with the Petroleum Act.

    The UK’s international obligations on decommissioning are governed principally by the 1992 Convention for the Protection of the Marine Environment of the North East Atlantic (OSPAR Convention).  BEIS is the competent authority on decommissioning in the UK for OSPAR purposes. In July 1998, the OSPAR Commission adopted a binding Decision (OSPAR Decision 98/3) to ban the disposal of offshore installations at sea, but considers derogation cases where full removal is determined to be impracticable.

    In order to ensure full compliance from a regulatory perspective, we have sought early engagement with the relevant regulatory bodies.  A key engagement was held in September 2015 with the Oil and Gas Authority and three limbs of BEIS – namely the Environmental Management Team, Environmental Inspectorate and the Offshore Decommissioning Unit (ODU).  The product of this engagement was an agreed roadmap for regulatory approvals and this will serve as a key reference throughout the lifecycle of the project.

  • What is the Comparative Assessment process?

    Comparative Assessment (CA) is a core part of the overall decommissioning planning and approval process being undertaken for the subsea infrastructure.  Our strategy for the CA process is aligned with the Oil & Gas UK guidelines for Comparative Assessment in Decommissioning Programmes (issue 1 Oct 2015) and BEIS’s Guidance Notes for the Decommissioning of Offshore Oil and Gas Installations and Pipelines under the Petroleum Act 1998, Version 6, dated March 2011.

    We have scoped all the associated infrastructure into logical groupings. All feasible decommissioning options for each group have been identified, assessed, ranked and screened to carry forward the credible options to be assessed through the process of CA.  The CA process uses five assessment criteria of Safety, Environment, Technical, Societal and Economic to compare the relative merits of each option. The assessment criteria are equally weighted to balance and represent the views of the associated key stakeholders.

    An independent consultancy using their bespoke configurable Multi Criteria Decision Analysis (MCDA) pairwise software have been employed to facilitate the CA process. 

  • Who approves the Decommissioning Programme?

    The UK Government’s Department for Business, Energy & Industrial Strategy (BEIS) is the competent authority on decommissioning in the UK.  Further information on the process for the decommissioning programme can be found in the UK Department for Business, Energy & Industrial Strategy Guidance for Decommissioning of Offshore Installations and Pipelines under the Petroleum Act 1998.


  • Are stakeholders being consulted about the proposed activity?

    Early engagement with a range of interested parties was initially undertaken in 2010 and 2011 when we engaged a number of key stakeholders in order to mature initial decommissioning concepts.  These historic engagements will form the foundation for future dialogue with stakeholders including local and national environmental groups, fishermen’s associations, key Government agencies and authorities, scientific organisations, interest groups, industry bodies, supply chain organisations and various internal and public stakeholder groups.

    Through the consultation process, we aim to find the safest and best environmental, social and economically responsible technical solution for the future of the Greater Dunlin Area.

  • Who are the stakeholders and how are they kept informed?

    Our stakeholders include local and national environmental groups, fishermen’s associations, key Government agencies and authorities, scientific organisations, interest groups, industry bodies, supply chain organisations and various internal and public stakeholder groups. They are kept informed via focused dialogue events, communication updates, direct contact and website materials. The website lists all the stakeholder organisations who attend our dialogue sessions.

    Building on the initial consultations held in 2010/2011, and influenced by the dialogue with regulators following cessation of production in June 2015, we have undertaken a formal stakeholder analysis including over 200 potential stakeholders, representing NGOs, Government agencies and authorities, scientific organisations, interest groups, supply chain organisations and various internal and public stakeholder groups.  This has resulted in an assessment of engagement need and methodology for each identified stakeholder.  The engagement methods range from the offer of bilateral (one-on-one) discussions to referral to a website repository of project decommissioning information.  This analysis will be revisited and refreshed with input from organisations such as BEIS ODU to reflect the feedback obtained during the stakeholder engagement activities.

The Supply Chain

  • What opportunities in terms of workscopes will be available to the supply chain?

    There will be a number of specialist contract services required for the execution of the decommissioning project, including but not limited to: platform and subsea well plugging and abandonment, engineering studies; subsea infrastructure decommissioning; topsides preparation for removal; topsides removal; and topsides recycling/disposal.  We will be engaging with the supply chain to identify effective technological solutions that are environmentally acceptable and safe. 

  • Have contractors been identified for various aspects of decommissioning work?

    We are very aware of the important role that the supply chain will play in solving some of the complex challenges associated with decommissioning.  We presented the Greater Dunlin position at Oil & Gas UK’s Share Fair Spotlight – Decommissioning in September 2016 with the objective of identifying where the supply chain's services, expertise and equipment can cost-effectively meet operators' most pressing decommissioning challenges.

    We are continuing to manage and amend existing contracts whilst following our normal robust contracting and procurement procedures in support of the decommissioning effort.  To date we have tendered for and awarded a contract for the subsea well P&A programme commencing in spring 2017.  In addition, there are a number of consulting firms involved extensively in a wide range of decommissioning studies on our behalf.  We are also undertaking a detailed evaluation of options for the Dunlin topsides removal method with the support and assistance of a number of specialist organisations along with understanding the capability of UK and local European ports for safe, environmentally friendly and cost effective dismantling and disposal of recovered facilities and structures.

Safety & Environment

  • How will the environmental impacts from decommissioning be managed?

    Consistent with our policies and the project’s objectives, comprehensive environmental impact assessments will be undertaken to guide activities and decisions and to ensure that environmentally robust options are selected. In support of these planned assessments, an environmental baseline survey was commissioned in late 2015.  This scope of work will form the foundation for subsequent Environmental Impact Assessments (EIA) and Environmental Statements (ES).  We will engage the appropriate technical expertise to conduct these studies and will consult with stakeholders to arrive at well-informed decisions.

  • Are the environmental NGO’s updated on project options and progress?

    Environmental NGOs are amongst a wide range of identified stakeholders and, along with other stakeholders, will be given the opportunity to provide opinion on our Decommissioning Programmes. We welcome the opportunity to continue to have discussions and to listen to all stakeholder views and input.

  • What options exist for re-use of the facilities?

    In line with the waste hierarchy principles, reuse of the Dunlin Alpha topsides (or parts thereof) is first in the order of preferred decommissioning options for assessment.  Recovered infrastructure will be returned to shore and transferred to a suitably licensed decommissioning facility. It is expected that the steelwork would be cleaned before being largely recycled.

    We will continue to engage with other companies and wider industries to discuss reuse opportunities however we believe that any further reuse or resale opportunities will be best achieved through the tendering and selection of a waste management contractor with the required knowledge and experience in this area.

    Final disposal routes and historical performance will be a key consideration within the tendering process to ensure the aims of the waste hierarchy are best achieved.

  • What measures have been adopted to mitigate safety risks to personnel during decommissioning work?

    All decommissioning activities on the Dunlin, Osprey and Merlin facilities and associated infrastructure will be undertaken in accordance with our Health & Safety Policy and Environmental Management Policy and in compliance with relevant statutory provisions.  Throughout the lifecycle of the decommissioning activities, the installation will have an accepted Safety Case.  From the perspective of compliance with regulations, the decommissioning activities will extend beyond the transition from ‘Safety Case Regulations 2005’ (SCR05) to the ‘Safety Case Regulations 2015’ (SCR15), as precipitated by the EU Offshore Safety Directive.  We have therefore engaged early with the Health and Safety Executive (HSE) to establish a submission strategy which recognises not only the physical changes to be experienced by the installation over time but also the transition in the regulatory framework.

    Following appropriate consultation with the HSE, it has been agreed that the first formal submission of a Safety Case document under SCR15 will be in late 2017, with a likely acceptance of this document by the HSE in 2Q 2018.  Based on current project schedules, this submission will almost certainly be a Dismantling Safety Case rather than an Operational Safety Case.  In the interim period, we will maintain a current operational Safety Case in line with the longstanding requirements of SCR05.  At any time, should Fairfield and the HSE agree that the physical or organisational changes on the installation constitute a material change, then a revised safety case will be presented to the HSE under regulation 14(2) of the 2005 regulations.

    Workforce safety will remain of prime importance throughout the project.  A robust HS&E Management System and associated processes, procedures and an engagement culture will be applied to ensure the safety of those working on the project.