Pioneering Spirit moving in around the Bravo platform

Oil and gas platform decommissioning: salvage, sink or save?

Image credit: Allseas

The decommissioning of aged North Sea oil and gas rigs is gathering pace, but it’s a big challenge.

When offshore oil and gas exploration began in the North Sea during the 1950s, the UK saw an opportunity to boost its industry and economy. And as the country slipped from seventh place in the world in terms of economic prosperity to 20th (measured by gross national product per person) between 1950 and 1975, this new source of income and jobs was welcome.

It also meant that from 1980 to 2004, the UK was no longer reliant on oil imports. Now, more than 40 billion barrels of oil equivalent (BOE) has been produced from the North Sea, according to the industry regulator the Oil & Gas Authority (OGA). While there’s still around 10-20 billion BOE that could be extracted, some fields are now depleted, and a new industrial challenge is emerging: decommissioning the infrastructure that was built to extract those billions of barrels.

However, this is a huge task. In total, there are around 270 facilities in the North Sea, comprising both ‘topsides’ (housing accommodation, utilities, production and process technology), and steel ‘jacket’ support structures or gravity-based foundations made of reinforced concrete. All of these need safely removing from what is a pretty unforgiving environment. Also, some 50,000km of the subsea pipeline (including cables and umbilicals), 370-plus subsea structures and more than 5,000 wells, drilled into the seabed over the past five decades, need to be remediated, removed and sealed.

It’s a daunting task, especially as, in the early days, little thought was given to how these structures, and the wells beneath them, would be removed in a way that meets today’s regulations, such as leaving behind a clean seabed.

It also has a big price tag. The OGA’s current estimated cost of removing it all adds up to over £50bn, a number it and industry want to cut by 35 per cent.

“Decommissioning is spending that operators want to reduce. Less spending on decommissioning means more can be spent elsewhere (for example, exploration),” says Joe Leask, decommissioning manager at industry body Oil & Gas UK. It also reduces how much government forfeits in tax receipts – as operators get tax relief on decommissioning activity.

To a large extent, the industry is learning by doing. So far activity has been limited, but it’s ramping up. Over the next 10 years, around £15.3bn is expected to be spent on decommissioning. “It’s now a part of the life-cycle and amounting to about 8-10 per cent of all expenditure in the North Sea,” says Leask.

Some 74 platform removals are expected over the next decade, mostly from the southern North Sea, which is a shallow-water area with smaller platforms, Leask says. “There is a lot of front-end activity: plugging and abandonment (of wells), and the initial engineering that needs to be done to remove facilities. As we learn how to do things better, costs will become more certain.”


Removal statistics

Platform removals over the next decade

Northern North Sea: 10

Central North Sea: 16

Southern North Sea: 16

Removals by weight

Topsides: 600,000 tonnes

Steel substructures: 244,964t

Subsea structures: 54,000t

Additional scope

Well plugging and abandonment: 1,400

Concrete mattress removal (subsea): 18,000

Pipeline decommissioning (remove or bury): 5,274km

(Source: est., Oil and Gas UK)

Unsurprisingly, this challenge is driving innovation, including the creation of Pioneering Spirit, the world’s largest construction vessel in terms of gross tonnage, breadth (123.75m) and displacement (900,000t). The twin-hull vessel enables large topside structures weighing up to 48,000t, which would have originally been installed in numerous modules, to be removed in a single lift. It took 20 years to design and cost €2.6bn (£2.3bn) for Swiss company Allseas to build. It’s fitted out with eight pairs of lifting beams that reach over an open-slot bow in which platforms are positioned.

The beams work together in coordination with the ship’s dynamic positioning systems, to compensate for the movement of the vessel on the sea as topsides are lifted out (having previously had the legs beneath cut and held in place with purpose-built shear restraints).

Pioneering Spirit has already removed several platforms, including Shell’s 24,200t Delta and 25,000t Bravo topsides in the Brent oil field near the Shetland Islands. It’s now also lined up to remove the Statfjord topsides, offshore from Norway, weighing 48,000t.

There are other heavy lifters and other methods. Dutch firm Heerema Marine Contractors (HMC) has removed the 40,000t topsides of the Murchison platform – in modules – using two of its heavy-lift crane vessels, Thialf and Balder, which have 14,200t and 6,300t lifting capacity respectively.

Not all of the platforms in the North Sea are of this scale, however. In fact, across northwest Europe (including Norway, UK, Denmark, the Netherlands and Germany), around half of the installed platforms weigh under 1,600t. “There are a considerable amount of smaller lifts to be done in the southern North Sea, and that’s an area where there has been a success in industrialising the process,” says Leask. “Operators are churning out work and improving from platform to platform.”

Once onshore, platform structures need to be remediated and recycled. Efforts are under way across England and Scotland to create decommissioning hubs where these hulks can be taken apart and up to 98 per cent reused, sold or recycled. (The Scottish Government has awarded £14m in funding to create capacity there).

Able Seaton Port, on Teesside, spent £28m creating what’s one of the strongest quays in Europe to receive and dismantle offshore structures, and the investment is paying off. In 2017, the Brent Delta platform was taken there, followed by Brent Bravo in 2019. More are expected to arrive in coming years, including the Brent Alpha platform and structures from Nova Scotia, Canada.

Able is reaping the benefits of its investment by doing repeated work, but there’s also competition in the market, says Leask. Murchison went to Norway whilst the Ninian North platform topsides are going to Dales Voe on Shetland, run by Veolia and Petersen, following the Buchan Alpha topsides and modules from platforms in the southern North Sea, for example.

“Around the shores of the UK we are seeing the competition grow and developing capability,” Leask says, with similar happening around neighbouring shores, such as Norway and the Netherlands.

Veolia decommissioning director Martin O’Donnell agrees, adding: “We have already recycled over 80,000 tonnes of materials and created new job opportunities to meet the growing demand for decommissioning.”

While removing up to 48,000-tonne structures using a ship is impressive, it accounts for less than 10 per cent of the entire cost of decommissioning. So, cost reduction efforts are also focusing elsewhere, including well plugging and abandonment (P&A). This accounts for the largest chunk of the estimated total decommissioning bill and also has the biggest potential for cost reduction, as Nils Cors, OGA’s outgoing head of decommissioning, highlights. It’s about 44 per cent of the total bill, according to the OGA. A 50 per cent cost saving here would amount to a £14bn saving overall, Cors adds.

Why is plugging and abandonment so costly? For a start, there are lots of wells – about 400 on the Brent field alone. Many are also old, and difficult to access, assess and remediate. The traditional approach to P&A involves setting long cement plugs across and above reservoir zones down the well. To meet regulations, these have to be in contact with the surrounding rock, which often means mechanically milling out cement and “pulling tubing”, i.e. using heavy machinery to pull the steel tubulars out of the well, which might be kilometres deep.

However, Professor Brian Smart at Compass ICOE, Edinburgh-based health, safety and environment resource for the offshore industry, says: “We believe cement isn’t sufficient for the long-term as a plug material – one recognised reason being its chemical deterioration. Another reason is its reaction to ground movements, such as reservoir subsidence or its reversal as the reservoir recharges. That stresses the rigid cement, cracking it and destroying its integrity as a plug.”

Malcolm Banks, manager of the well construction solution centre at the Oil & Gas Technology Centre (OGTC), a public-funded body tasked with technology development based in Aberdeen, says: “Historically, cement has been the default, but it’s not perfect,” and getting it in place over long well sections can be time-consuming and challenging. “So, the industry is looking at alternatives, as well as economically implementable solutions,” he adds.

The goal is plugs that are quicker and easier to place, with integrity at least as good as cement. That also means finding easier ways to place barriers. “Historically, that’s meant removing whole tubulars, completions and cutting and pulling casing, and that can take weeks,” says Banks. “So, we’re looking at how to cut or remove sections with thermal or mechanical means.

“Another challenge is understanding the condition and the integrity of the well and geology surrounding it. A lot of wells have changed hands three or four times, and information is lost. But, that information can help reduce risk and uncertainty. So, we’re looking at cheap internal surveys upfront and modelling using data and data analytics to reduce risk and uncertainty.”

New models

Plug & Abandonment

New commercial models are emerging where companies take on ‘late-life’ assets to see them through to the end of production and then decommissioning or where firms purely carry out plugging and abandonment operations with a dedicated vessel or rig.

One of those firms is Fairfield Decom, which became a late-life operator of the Dunlin field and is now decommissioning it. “Decommissioning is a distinct activity that demands a specific mindset and approach,” says Graeme Fergusson, its managing director. The North Sea has created outstanding explorers, developers and producers committed to building and safeguarding assets for the long term, but decommissioning has a completely different set of priorities, he notes.

“Fairfield Decom’s approach is to take control of the field in the last years of its life, which gives us a thorough knowledge of the infrastructure. That knowledge also enables operators and asset owners to concentrate their resources on core business activities,” he explains.

Well-Safe was set up as a pure-play plugging and abandonment company in 2017. It bought a rig – now named the Well-Safe Guardian – as its first asset, and in 2019 awarded two multi-million-pound contracts to turn it into a bespoke P&A unit.

OGUK decommissioning manager Joe Leask says the UK will be the largest market for decommissioning spend over the next decade. Successful and innovative pioneers here will help the UK industry establish an advantage in an emerging global market.

Some inroads have been made, with the cost of P&A falling from 48 per cent of the total bill to 44 per cent since 2016, through being more efficient. But, bigger changes are needed. This includes changing what’s used as a plug or barrier so that rigs are not needed, saving the up to $300,000 (£243,000) a day that rigs can cost.  

Some exotic solutions are being developed. Norwegian firm Interwell is developing thermite as a barrier. The thermite is deployed on wireline – a wired system that can be deployed from the vessel and run down into the well to a specific depth, where it’s ignited and then burns through the rock. Since 2016, the firm has run trials in 18 different wells, but the focus, according to Christian Rosnes, P&A commercial manager, is still a lot on modelling and testing while looking at the geochemistry/geology, chemistry, well elements, thermo science and mechanical design.  

Several other firms are working with the element bismuth. BiSN, based in Warrington, UK, is qualifying a bismuth alloy as a well barrier material. Heated using thermite, it flows into cracks and then, when it sets, uniquely it expands. Aberdeen-based Isol8 is looking at a similar technique.

Meanwhile, Rawwater, also based near Warrington, has a bismuth alloy seal concept which it calls ‘molten metal manipulation’ that it’s been testing since 2010, and which uses an electric heating element instead of thermite. The firm is now investigating the use of two bismuth alloys in well decommissioning, Alloy 80 and Alloy 150, which resist creep to 80°C and 150°C respectively and resist corrosion in sour environments. Both were certified to be fit for the 3000-year life requirements in wells. Rawwater is working with UK-based engineering consultancy Astrimar, and looking for partners to deploy trials.

Some companies are looking to stick with cement, but to improve it. Well-Set, based in Norway, is looking at magneto-rheological cement. This involves using traditional cement but controlling how it is set – its rheology – more accurately. Banks says to do this, they would need to impregnate the cement with magnetic particles then use a magnetic field to place it.

At the University of Strathclyde in Glasgow, nanoparticulate silicate and biogrout technologies are being looked at. “Cement, over time, will shrink, crack and degrade,” says Banks. “The ability in the annulus to retain the barrier long-term is something that’s a concern to the industry.” Especially as there’s no way to go back in and repair it. So, ideas from civil engineering are being researched and this includes biogrout, which uses enzymes that deposit calcium carbonate in the downhole environment.

“The nanoparticular silicate, meanwhile, would get into the cement or cracks where it gels,” says Banks. “It hasn’t got compressive strength, but it has pressure-retaining capacity, so it helps to seal areas in a wellbore that might otherwise flow.”

Another cement adaptive technology is being developed by UK-based Resolute Energy Solutions, which is testing the use of additives in cement that expand downhole to eliminate shrinkage.

A big challenge, however, is proving that these plugs can both provide an adequate seal, last a long time and provide a better barrier than cement.  

The National Decommissioning Centre (NDC) in Aberdeen has a test chamber that can put barrier materials to the test at up to 150°C and pressures equivalent to 7,000m depth, which would cover 80 per cent of UK Continental Shelf’s wells. The University of Aberdeen’s Dr Richard Neilson, who’s been working on the project, says: “We can set a plug and test it under pressure and then examine it: the morphology of what’s been generated. There’s a big advantage to being able to do that. You can show that these materials will do what was expected in downhole conditions.”

Some of the ongoing work is starting to pay off. The total UK decommissioning bill was estimated at £59.7bn in 2017; the most recent like-for-like estimate is £49bn, but that’s some way from the industry’s £39bn target. So, there’s still a lot to play for.

North Sea

The scale of the issue

UK offshore oil and gas infrastructure covers large swathes of the North Sea. However, it’s not spread evenly. The largest majority – in terms of removal cost – is in the central North Sea. That’s an area that covers from east of Newcastle to east of Aberdeen, out to the maritime border with Norway – another big oil and gas producing nation.

There are more installations in the southern North Sea, which spans from east of the Yorkshire coast, down to offshore Norfolk and right across to the maritime border with the Netherlands. This is because the waters are shallower there, so it’s possible to install more smaller facilities, covering a larger area of what are predominantly gas fields in this zone. In the northern North Sea, to the north and east of Aberdeen, the waters are deeper and the weather harsher, so there are fewer facilities, but they’re bigger.

Deeper again – down to 1800m in fact – is the west of Shetland area. Here, the water depth has mostly meant that floating production facilities need to be used. These are moored and use risers to transport the oil and gas from subsea wellheads, which contain and control the fluids and gases, up to the vessel for processing and onward transport, usually via tankers. In one case, however, an entirely subsea based production system has been used. The subsea well, on Total’s Laggan-Tormore field, is connected via a manifold into a pipeline that transports the production 120km to a receiving terminal on Shetland.


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