A survey run by the OGA which creates a single source of robust data. It is used to inform stewardship reviews and provide meaningful insights into current and forecast activity in the UKCS.
Used to compare options, examine differences and identify the ‘most preferred’ option in the development of decommissioning programmes for: a) All installations for which derogation is sought under OSPAR Decision 98/3 b) All pipelines being decommissioned under the Petroleum Act 1998 c) All drill cuttings piles that are not screened-out at Stage 1 of OSPAR
Cessation of Production
The Petroleum Act 1998 requires owners to set out the measures to decommission disused installations and/or pipelines in a decommissioning programme. A decommissioning programme must identify all the items of equipment, infrastructure and materials that have been installed and describe the decommissioning solution for each.
An assessment of the environmental impacts for the activities planned to take place during the decommissioning workscope.
In simple terms, oil and gas installations are in place in order to extract hydrocarbons from a reservoir and then transport them elsewhere to be processed for use. However, doing so requires considerable amounts of process equipment and infrastructure, including systems to help lift hydrocarbons from the reservoir, equipment to clean and process them for transport, and facilities for personnel to work and live. Prior to any removals, the facilities on the platform and pipelines used to recover and transport the hydrocarbons must be de-energised. This involves ensuring any pressure sources are removed and that the installation is free — as far as reasonably practicable — of hydrocarbons and contaminants. Topsides cleaning activities involve the flushing of process equipment from wells and pipework. It may also include entering pressure vessels on the installation to manually clean or to remove any solid material. The level of cleaning required on an installation depends on the removal methodology, as there may be opportunities to carry out much of the cleaning and decontamination as part of the onshore disposal. Pipeline cleaning programmes are designed to ensure the hydrocarbon content and any deposits within the pipeline are dealt with, taking into account the future Decommissioning Programme and without prejudicing any opportunities for potential reuse. Teams of operational specialists are required for these de-energising work scopes. For some of the cleaning activities, sophisticated strategies are developed to achieve the required levels of cleanliness. It is beneficial to have personnel with knowledge of the specific installation involved in these activities, when specific knowledge of the asset’s facilities can ensure a successful campaign.
‘Making safe’ of facilities includes cleaning, freeing equipment of hydrocarbons, disconnection and physical isolation, and waste management. ‘Making safe’ of pipelines involves depressurising them and removing any hydrocarbons. Then the pipelines are cleaned and purged, in line with the cleaning programme based on the specific needs of the system.
Once topsides and substructures are transported to shore they are managed under the waste hierarchy, considering re-use, recycling or disposal. Owners of oil and gas infrastructure have a duty of care which enforces the responsible handling of infrastructure from construction to final disposal. Due to the nature of oil and gas production, some of the materials and fluids in a facility being decommissioned may be contaminated. Normally Occurring Radioactive Material (NORM) and Low Specific Activity (LSA) scale are amongst the contaminants commonly encountered during decommissioning. Therefore licences, controls, mitigations, handling and disposal methods have been established to manage and dispose of such wastes. Once the infrastructure is onshore, the disassembling and processing takes place on specialist licensed sites in accordance with an approved waste management system.
When a producing facility is no longer economically viable, operators can apply to the OGA for cessation of production (CoP). Post-CoP OPEX refers to operational expenditure (OPEX) after CoP has occurred. In this application, operators are required to satisfy the regulator that all economic development opportunities relating to a facility have been exhausted (including alternative use) and that any infrastructure access considerations have been addressed. CoP does not mean that all work on an installation is stopped. Activity on a facility will continue until all major hazards have been removed, e.g. isolation of wells, removal of hydrocarbons and final decommissioning activities are underway. During this period of operations, operational expenditure continues, without economic gain from production. It is therefore desirable to minimise any activity on the platform after production has ceased. Post-CoP OPEX activities and costs will include platform operational crew, deck crew, integrity management, inspection and maintenance activities and costs associated with continuing to operate the installation such as power, water, air etc.
Monitoring programmes are required for any infrastructure that is left in place under the Decommissioning Programme. Surveys will be conducted to check the status of infrastructure and assess changes over time to ensure no increased risk to other users of the sea. The frequency of these surveys will be determined in consultation with the regulator. Typically, an owner will assume a frequency for these surveys in their decommissioning cost estimates.
Throughout the various elements of a decommissioning project, operators will need a core team to manage the day-to-day activities. This core team will fluctuate over time in proportion to workload and when different areas of specialisation are required. As well as the in-house decommissioning team, this element of the WBS also includes the preparation of the Comparative Assessment (CA), Environmental Assessment (EA), Decommissioning Programme and Close Out reports, as well as any supporting studies required throughout the project. These studies are undertaken by specialist engineering practitioners who gather information to make robust decisions for decommissioning projects from safety, technical, environmental, societal and economic perspectives. Decommissioning projects cover a broad range of activities and as a result there are many different regulations and regulators involved throughout the process. Part of any decommissioning project will be to develop a Permits, Licences, Authorisations, Notifications and Consents (PLANC) register. This register maps all necessary applications to regulators and stakeholders and is intended to ensure diligence and the approval of activities in a timely manner prior to the execution of activities. Many activities require different applications to multiple regulators.
Once the decommissioning of the topsides, substructures, pipelines and associated subsea infrastructure have been completed, operators are required to ensure that the seabed is made safe for third-party users of the sea. This involves the removal of any debris remaining around the facility as agreed within the Decommissioning Programme. After completing the offshore decommissioning works, an independent organisation is required to complete a seabed verification trial. These usually entail a fishing vessel undertaking a trawl trial over the site from numerous approaches, using various representative fishing equipment. However, verification could also be conducted with survey equipment which can detect and analyse any features remaining on the seabed. Within one year of a post-decommissioning survey, a Decommissioning Programme Close Out Report is required to be submitted for regulatory approval. This report is required to satisfy OPRED that the approved programme has been carried out and describe any scope modifications required during execution. Close Out Reports are a key reference where learnings from decommissioning projects are shared.
When a pipeline, cable or umbilical has reached the end of its useful economic life, it must be decommissioned. In the UK, pipeline decommissioning is regulated by OPRED under national regulations. To determine the optimum pipeline decommissioning option, owners are required to carry out a Comparative Assessment, taking account of the safety, environmental impact, societal impact, technical feasibility and economics of each feasible option. There are currently no international regulations for decommissioning disused pipelines. Decommissioning options available for pipelines are as follows: • Leave in place • Full removal • Trench and bury • Rock cover • Hybrid options encompassing elements of the above Outcomes from the CA are embodied in the Decommissioning Programme, which undergoes public consultation before approval by the Secretary of State for Business, Energy and Industrial Strategy. Once the Decommissioning Programme is approved, it is up to the owner to determine the optimum way of delivering the agreed scope. Offshore decommissioning activities are performed by offshore construction contractors with specialist equipment to safely carry out the required activities.
Once the topsides have been recovered to shore, the removal of the substructure can take place. Substructures vary considerably in terms of their shape and size depending on the water depth and the size of the topsides they were designed to support. Substructures can be either concrete gravity-based (CGB) or steel piled jacket structures (SPJ). CGBs are large reinforced concrete structures which are constructed in near-shore locations and floated to site. SPJs are steel structures which consist of a lattice of steel circular hollow sections welded together. These jackets are fabricated onshore and can be installed from a barge, made buoyant and floated to site, or installed using a lift vessel. Under the current OSPAR regulations (Decision 98/3), CGB structures may be left wholly in place at decommissioning. The footings of the largest and oldest SPJ structures may also be left in place, subject to regulatory approvals. Removal of SPJ structures, like topsides, can be conducted either by single-lift or by cutting the structure into sections and transported back to shore to for recycling. Prior to cutting and lifting, tasks such as reinstatement of lift points and strengthening for transportation will be carried out by specialist contractors.
Once all sources of energy have been isolated, the topsides can be prepared for removal. The 'topsides' refer to the facilities which sit on top of an installation, typically including drilling, processing and living quarters. Preparatory activities include the separation of process equipment from the wells and pipelines as well as module separation. Any activities to upgrade the facilities are also included in this part of the scope. This may include power upgrades to the installation to meet the decommissioning requirements. If a structure is to be left in place for any period of time, navigational aids may be installed during this phase.
During a decommissioning project, all topsides must be removed. There are three principal methods for achieving this: • Single-lift – Using a large lift vessel to remove the topsides as a single unit and transport onshore • Reverse installation – Separation of modules on the installation and removed by the lift vessel one by one • Piece-small removal – Breaking the topsides into small pieces offshore and transporting the waste to shore for disposal Operators will assess the suitability of each method to individual installations and confirm a methodology for removal. Once the methodology for removal is confirmed the topsides can be prepared for lifting. Specialist structural engineers and lift experts are required for this phase of the work scope. Their activities may entail lift-point installation or re-instatement and structural strengthening for transportation.
Well decommissioning is the permanent isolation of any rock formations with flow potential and the restoration of a seabed to its previous status. There are three phases of well decommissioning:
  • PHASE 1: Permanent Isolation of the reservoir
  • PHASE 2: Permanent isolation of all intermediate zones with flow potential. This phase is complete when all required barriers are in place
  • PHASE 3: A well is considered fully decommissioned after removing the wellhead and conductor, the well origin at surface is removed and the well will never be used or re-entered again.
Well decommissioning is conducted by a team of highly skilled personnel who will engineer specific activities for each well bore and then carry out the decommissioning work scopes. These work scopes are normally carried out using one of the following methods:
  • Subsea wells: Using a jack-up or semi-submersible drill rig, or in some instances lightweight well intervention vessels (LWIV)
  • Platform wells: Using a jack-up, the existing drilling rig on an installation (which may require upgrades to make it fit for purpose); or using purpose-built, modular equipment installed specifically for well decommissioning
Each well is different and knowledge of the well and a record of previous operations is helpful in ensuring a successful campaign.
The WBS shows all elements of a typical decommissioning project and forms the basis for calculating decommissioning expenditure during different stages of the process.