Article - Issue 57, December 2013

Decommissioning North Sea giants

Brian Nixon

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‘Decommissioning North Sea giants

Decommissioning North Sea giants

The UK Continental Shelf has been producing large amounts of oil and gas since the 1970s. Virtually all of the infrastructure put in place in the North Sea since then will require decommissioning over the next 30 years. Brian Nixon, Chief Executive of Decom North Sea, outlines how the industry plans to do this in one of the harshest of maritime environments.

Over the last few decades, the North Sea oil and gas industry has steadily developed into one of the strongest and most highly regarded clusters anywhere in the world, with engineering contractors, technology developers, service specialists and consultants now active in over 100 countries. Part of this success has been due to the industry’s ability to extend the economic and productive lives of mature offshore platforms, developing marginal and remote satellite reservoirs, introducing new technologies, optimising efficiency of the production processes and assuring the integrity of the assets.

Despite this success, it is now recognised that a growing number of oil and gas assets have either reached, or are approaching, the end of their economic lifespans, and, in accordance with current regulations, will have to be decommissioned and removed. This presents challenges for the owners and operators of these assets, but offers major business opportunities for engineering consultants, contractors and service specialists.

The best estimate of decommissioning expenditure in the UK Continental Shelf over the next five years is a figure approaching £5 billion; this includes 40 platforms, approximately 350 wells, pipelines and subsea structures across 80 fields. To put this figure in context, the latest estimates for the same period show that the decommissioning costs in, arguably, the world’s most mature petroleum region, the Gulf of Mexico, will amount to around £3 billion. From this background, Decom North Sea was established in early 2010 to drive the development of the industry in advance of the main programme of decommissioning - see Decom North Sea.

Decom North Sea

The industry forum Decom North Sea is charged with sharing the (limited) experience in this sector, developing models and guidelines, and facilitating of joint industry projects designed to increase efficiency and reduce or contain costs. It also stimulates collaboration and cooperation, and seeks to secure economic benefit from a programme of activity estimated at some £35 billion over the next 30 years. The not-for-profit organisation now has 230 member companies drawn from operators, contractors, consultants, service providers, technology developers, equipment providers, marine and heavy lift specialists, logistics, subsea engineering, wells, onshore disposal facilities, and professional services providers. In other words, the whole industry.

The forum is witnessing encouraging signs of cooperation, sharing of ideas, joint industry projects, and open dialogue between operators, contractors and supply chain specialists. This is important because the cost of the decommissioning programme will be shared between the private and public sectors.

Financial responsibilities

The owners and operators of oil and gas infrastructure in the UK Continental Shelf are liable for the cost of each decommissioning programme. However, following recent confirmation from the UK government, tax relief will be made available once decommissioning expenditure is incurred, effectively resulting in the public sector contributing between 50 and 75% of the costs of each decommissioning programme.

Although some 7-8% of North Sea infrastructure has already been decommissioned and removed, this has taken place sporadically. As a result, the approaches and models needed to optimise the performance of decommissioning projects have yet to evolve. The majority of operators gearing up to undertake their first decommissioning programmes are taking time to develop their own approaches and strategies. There is currently no time constraint on offshore decommissioning programmes, which gives project teams time to commission various forms of engineering studies, surveys, inspections and analyses from the very beginning of the process.

The industry is currently utilising the same planning, approval and investment decision procedures as are used for the design and development of new offshore production facilities. However, the respective performance measures are very different. A new capital investment project will be judged on its ability to produce first hydrocarbons by a certain date; its operating efficiency, availability and reliability once in production; and by a prompt return on investment. Decommissioning is expenditure with no return; there is little perceived benefit in accelerating the completion date; and reliability and process performance are not relevant. Certainly safety, environmental performance and cost containment are common to every oil and gas industry project, but the other drivers are very different.

Platform characteristics

‘The 8,800 tonne module support frame from Total E&P Norge AS’s Frigg Field is brought ashore. It was one of the
biggest single decommissioning lifts undertaken in the North Sea to date. The S600 transport barge was the largest yet
to berth at Lerwick Harbour’s Greenhead Base © Lerwick Port Authority/Peterson (UK) Limited – Shetland Office

The 8,800 tonne module support frame from Total E&P Norge AS’s Frigg Field is brought ashore. It was one of the biggest single decommissioning lifts undertaken in the North Sea to date. The S600 transport barge was the largest yet to berth at Lerwick Harbour’s Greenhead Base © Lerwick Port Authority/Peterson (UK) Limited – Shetland Office

There are a variety of different sizes and types of asset found in the North Sea, and the dismantling of each presents specific engineering challenges and opportunities. The southern North Sea is a region with relatively shallow water and modest sea states, accommodating almost 400 platforms producing (mostly) natural gas. These platforms typically have ‘topsides’, that part of the platform above the water. These are able to be removed in a single lift using a single-hull lifting vessel, known as a shear-leg. The supporting structures (jackets) are in a similar weight range and can also normally be lifted from the seabed in one piece. The topsides and jackets can then be transported by barge or on the lift vessel (singly or together) to a shore-based facility for final cleaning and waste treatment, dismantling, disposal and recycling.

Platforms located in the harsh climatic conditions and deeper waters of the central and northern North Sea are designed to support complex oil, gas and condensate production facilities (including high pressure and temperature), and throughout their productive lives can experience a buildup of hazardous waste streams. The options for removing these facilities are very different to those in the southern North Sea.

North West Hutton platform

Until it ceased production in 2003, the North West Hutton platform, 140 km North East of the Shetland Islands in 144 m of water, was the only integrated oil and gas drilling, production, processing and accommodation facility in that field. Its topsides
alone included 21 modules and seven caissons weighing some 20,000 tonnes, while its jacket support structure comprised a further 17,500 tonnes of steelwork. Overall, this giant early-1980s structure posed a significant challenge to engineers charged with its decommissioning and removal

‘A cross section of jacket which has been diamond cut under water is lifted onto the North West Hutton platform © BP

A cross section of jacket which has been diamond cut under water is lifted onto the North West Hutton platform © BP

Offshore removal was carried out in two separate phases, with topsides removal in 2008 and jacket removal in 2009. All materials removed were brought back to shore on cargo barges for further processing and recycling. The pipelines decommissioning was
executed in 2011 and 2012 with some sections of pipeline and mattresses being removed and brought onshore for recycling and other sections trenched into the seabed

In total, 98.34% of the platform and pipelines was reused and recycled. Apart from the accommodation module and the module support frame, which were reused, the rest of the steel went for smelting or cold rolling.

Twenty-two modular lifts were needed to complete the reverse installation of NW Hutton’s topsides and module support frame. The largest module removed was 2,800 tonnes. Attention then turned to the 17,500-tonne jacket, a mass beyond the capability of then current single-lift vessels. Derogation permission was granted which enabled the jacket footings (extending 40m above the seabed) and the piles that fix the structure to the sea bed to remain in place while the remainder of the structure, totalling some 9000 tonnes, was dismantled by cutting and lifting sub-sections onto barges for transportation to shore. The largest jacket section removed was 2,250 tonnes.

‘The top section of the North West Hutton jacket being lifted onto a transportation barge to be taken to Teeside for recycling and disposal © BP

The top section of the North West Hutton jacket being lifted onto a transportation barge to be taken to Teesside for recycling and disposal © BP

For the jacket removal, a total of 224 subsea cuts were made using a combination of diamond wire, abrasive water jetting and hydraulic cutting shears to remove 58 jacket sections. Innovative diamond wire techniques were developed by Cutting Underwater Technologies of the UK (one of three contractors), that were used to cut the massive 3.05m-diameter corner legs with a wall thickness of 6.9cm. The company also developed a novel castellated form of cutting to maintain maximum stability of the severed leg structures before lifting operations began

The total topsides and jacket offshore removal programme and pipeline decommissioning was executed over 266 days, requiring over 1 million hours of work

BP carried out all North West Hutton decommissioning and removal activities under a UK government-approved decommissioning programme.

All that now remains of North West Hutton are the footings, which extend 49 m from the seabed (95 m below sea level) and the cuttings pile. The footings are marked on nautical charts and are recorded in the Kingfisher bulletin and FishSAFE database. Some sections of pipelines, which cross other operator pipelines or enter 500 m zones, will be subject to future decommissioning activities. BP is responsible for the periodic integrity and environmental surveys of the footings within the 500m zone, and is required to report on this regularly to the responsible government departments as part of the agreed North West Hutton decommissioning programme.

Decommissioning strategies

At the moment, there are three accepted strategies for the removal of these larger production facilities, namely piece small, reverse installation and single lift. The piece small approach is achieved by systematically freeing the topsides facilities of all hydrocarbons, hazardous wastes, asbestos and naturally occurring radioactive materials (NORM). The platform facilities and structure are then cut into small pieces using track-mounted guillotine cutting shears. These pieces are loaded into open-top containers and transferred to supply boats for transportation to shore. With this concept, jacket structures can similarly be cut into suitably sized sections using either diamond wire, abrasive water jet, mechanical cutting tools, hydraulic shears or explosives, deployed either using divers or remotely operated vehicles.

The reverse installation method recognises that several offshore platforms were built in a modular fashion. During the 1970s and 1980s, several fabrication yards would be contracted to build as many as 30 modules, decks and support frames which were loaded out and then installed using the heaviest marine lifting vessels of their time, with 3,000 or 4,000 tonnes capacity. These modules were then hooked up and commissioned to achieve integrated production platforms. Reversing this process is seen as a viable strategy for many of the assets that were designed in this manner, although significant engineering and inspection will be needed to ensure the integrity of the module structures and lifting points. The lifting capacity of the vessels used to construct these platforms has increased over time as a result of regular upgrade and refurbishment programmes, with today’s fleet of heavy lift vessels having capacity up to 8,000 tonnes.

The third concept, single lift, is expected to become a reality during 2015 when a new breed of ‘super heavy lift vessel’ comes to the market. The Pieter Schelte is being built by Allseas, one of the world’s largest pipe-lay contractors. Although also designed as a pipe-lay vessel, it has the ability to lift complete topsides of up to 48,000 tonnes on its bow, plus a jacket structure of up to 25,000 tonnes on its stern. This offers the potential of a game-changing approach to offshore decommissioning by being able to transfer complete production platforms from an offshore to an onshore location in single movements. It is anticipated that this will help to manage many of the safety, technical and environmental risks inherent in offshore working, and also help to contain costs. Other designs of single lift vessel exist but they are still at the funding stages.

Sea bed heavyweights

North Sea production platforms provide accommodation for hundreds of people. They also contain power generation services, drilling equipment, a helideck, refuelling and evacuation systems, and various production processes that are housed together in the topsides. These can weigh up to 40,000 tonnes for larger facilities and the large majority are supported on steel ‘jackets’, lattice-framed tubular structures, which themselves weigh up to 25,000 tonnes. These are held in place on the seabed with multiple piles, often several metres in diameter and tens of metres long.

Although the great majority of North Sea installations are supported on steel structures, a smaller number are concrete gravity-based structures. With similar topsides to the steel ones, these installations are among the oldest in the basin, having been built at a time when design concepts were still evolving. These platforms are acknowledged as probably the largest manmade structures ever transported and, ranging from 300,000 to more than 500,000 tonnes each, they present significant engineering challenges to the industry.

It is clear that any attempt to re-float a structure of this magnitude that has been sitting on the seabed for decades present huge safety, technical, environmental and economic challenges. It is therefore likely that the operators in question will qualify for a derogation. ‘Derogation’ in relation to decommissioning means being granted permission to leave certain structures and facilities in place - see North West Hutton Platform. However, there is no blanket agreement in place at this time, and so each operator must undertake large-scale research and engineering analysis in order to demonstrate why this is the best solution.

One particular challenge with concrete designs lies in the contents of storage cells that often form part of these structures. If the operator and regulator are to be convinced that it is acceptable to leave such a structure in situ, then evidence is required to show that no environmental or ecological harm will result when the concrete degrades over a few centuries. These storage cells can measure up to 20m in diameter and 60m in height, and their contents will require to be analysed before a derogation can be granted.

Other engineering challenges include the large inventory of subsea infrastructures which must be accessed, cleaned for decommissioning and removed. There are also thousands of wells that will need to be permanently plugged and abandoned. Subsea and floating production developments have become important contributors to the overall production from the North Sea.

Although it is hoped that floating production and storage vessels can be relocated to alternative developments, it is unlikely that the associated subsea flowlines, umbilicals, risers, wellhead protection covers, mooring systems, mattresses or inter-field pipelines will be able to be reused. It is expected that these pieces of infrastructure will also need to be cleaned, decommissioned, removed and recycled. The plugging and abandonment of both platform and subsea wells is one of the highest-cost areas of any decommissioning programme, and is widely regarded as creating the greatest need for innovation and technology development.

Murchison decommissioning

The Murchison platform in the Northern North Sea is the world’s biggest steel jacket to go through the decommissioning process to date, weighing in at 27,600 tonnes. Decommissioning planning work started in 2009, with three years of extensive surveying, data collection and studies taking place before a decommissioning programme was submitted to the Department of Energy and Climate Change in 2012.

Work to plug and abandon its 33 platform wells started late in 2013, with permanent shutdown of the platform scheduled for 2014. The complex processes to clean it and make it safe will continue to 2016. Detailed engineering work will go on in tandem, building up to the infrastructure being taken ashore for reuse, recycling or disposal.

Read more about the Murchison decommissioning
at www.ingenia.org.uk

Decommissioning process

‘With 99.5% of its recoverable reserves produced, the Brent North Sea field is being decommissioned after more than 35 years in operation. Shell has commissioned the lease of the Pieter Schelte, which is being built by Allseas. The single-lift vessel will be 382m long and 117m wide, and the first vessel ever built to have the ability to remove topsides in one lift. The vessel will remove and transport the Brent topsides, and load them in to shore

With 99.5% of its recoverable reserves produced, the Brent North Sea field is being decommissioned after more than 35 years in operation. Shell has commissioned the lease of the Pieter Schelte, which is being built by Allseas. The single-lift vessel will be 382m long and 117m wide, and the first vessel ever built to have the ability to remove topsides in one lift. The vessel will remove and transport the Brent topsides, and load them in to shore

Long before any infrastructure can be removed, the owner/operator (and their co-shareholders) are required to develop detailed plans and programmes for each production platform, pipeline, well or similar piece of infrastructure. Each programme is submitted for review and comment prior to final approval being awarded by the appropriate regulator – a process which in itself can take upwards of a year. In the UK, the regulator is the Department of Energy and Climate Change. The research, analysis and appraisal required to develop each of these individual programmes can take additional years of analysis, comparative assessment and management consideration, and involve scores of studies and engineering reviews.

This preparation and planning phase is often followed by a period when production of hydrocarbons could have ceased but the platform remains ‘live’ – hydrocarbons are still present. During this phase (which can last months or even years), it is necessary to maintain power and utilities, helideck and safety systems, and any items of equipment that may be used during the dismantling or decommissioning phase. This phase involves continued inspection and checks on the integrity of the asset and the possible isolation, protection and removal of redundant machinery for refurbishment and reuse.

Detailed engineering studies in preparation for, and support of, the shutting down of process activities, and the preparation of major topsides for removal can take years to accomplish safely and responsibly. The work being conducted on Shell’s Brent Delta platform at the moment is a good example of this. Onboard hydrocarbons need to be flushed offshore with residues disposed of within the appropriate permits. Fuels and lubricants must be drained and transported to shore for either reuse or approved disposal.

Other hazardous materials such as chemicals, asbestos and paint coatings must be identified and dealt with in accordance with relevant safety and health provisions before being shipped to shore for final treatment and disposal. Tracking systems also need to be developed so that the operators can demonstrate where each tonne of hazardous waste is during each step of the decommissioning process.

‘Installation of buoyancy tanks © Aker Solutions

Installation of buoyancy tanks © Aker Solutions

Engineering surveys and inspections form an important part of the preparation for topsides and jacket removal. During the productive life of offshore oil and gas fields, numerous engineering upgrades, process plant modifications designed to improve production throughput and efficiency, and conversion projects are likely to be undertaken. Equipment may have been added, removed or relocated, with piping re-routed, or control systems replaced. Up-to-date surveys are required to confirm weights of modules and the positions of centres of gravity; lifting arrangements must be developed; and the condition and integrity of supporting structures and pad-eyes require validation.

Jacket removal

Jacket support structures also require detailed engineering assessment and inspection. It is likely that jacket structures will need to be cut into appropriate sections in order to come within the capacity of the crane vessel being used. The positions of cuts have to be calculated, the methods of cutting and attachment selected, and an inspection of the steel to spot possible buildups of grout within tubular sections and then lifting arrangements need to be developed.

In the case of very heavy jacket structures installed before 1999, operators may apply to the regulator for a derogation to leave the footings and piles in situ. This approach recognises that the withdrawal of piles, and the cutting and lifting of these heaviest sections, could cause significant environmental noise and disturbance, and from a safety and environmental perspective it may be more appropriate to leave these sections in place. If derogation is granted (as was the case with BP’s North West Hutton platform) the cut is made just above the top of the footings (or pile clusters).

One option for jacket removal is the use of buoyancy tank assemblies as designed by Aker Solutions. This solution, used once on Total’s Frigg field, involved attaching buoyancy tank assemblies to the legs of the jacket, ballasting accordingly and then towing the structure to a deepwater port for inshore dismantling and recycling – see Frigg’s buoyancy tanks.

Once removal has been undertaken, all sections of topsides, jacket and subsea infrastructure need to be transported either by barge or on the lift vessel to a licensed onshore disposal facility. Some marine growth may be removed offshore, but the majority is likely to be done at the onshore yard. Similarly, NORM (naturally occurring radioactive material) and other hazardous wastes will be managed within the operator’s waste management procedures and relevant environmental policies.

Finally, a post-decommissioning site survey is required to a radius of 500m from the installation, and 200m along the route of any pipeline, with any significant debris being recovered in these areas for disposal onshore. Independent verification of the state of the seabed is obtained by trawling the area, with a final statement of clearance being issued to relevant stakeholders. A close-out report is prepared and submitted to the regulator within four months of the end of the project, following which the operator and regulator agree an appropriate regime to inspect and monitor environmental conditions and any remaining infrastructure.

Looking forward

The decommissioning of the UK Continental Shelf is a major engineering challenge. It also represents a significant opportunity for UK industry, with expenditure estimated to be in the order of £35 billion over the next 30 years. The North Sea is not the only place where there will be decommissioning of such infrastructure, and lessons learned there will almost certainly be transferred abroad.

Knowledge transfer and the sharing of best practice will be essential if the industry is to progressively increase efficiency and reduce costs in decommissioning. Work is underway by Decom North Sea and others to drive and capture experience, but it requires greater emphasis from all parties before the true benefits can be realised.

It is fair to say that until recently, decommissioning has not been considered within the overall lifecycle of an offshore asset. As a result, maintenance regimes have often overlooked key items of plant and equipment that would be needed during the abandonment stages, leading to significant and arguably unnecessary costs. There are welcome signs that this attitude may be changing, with some companies now introducing decommissioning as part of their graduate development programmes. However, further effort is required before decommissioning is fully considered throughout the lifecycle.

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