Energy

Tackling old oil and gas platforms

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ENDS Report 505, March 2017

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Much oil and gas infrastructure in the North Sea is coming to the end of its life and is no longer commercially viable to run. Isabella Kaminski investigates the emergence of the offshore decommissioning industry

The Brent oil field has been earmarked for decommissioning. Photograph: Royal Dutch Shell
The Brent oil field has been earmarked for decommissioning. Photograph: Royal Dutch Shell
There is a long legacy of oil and gas production in the North Sea. For 40 years, operators have exploited fields across the UK continental shelf, setting up rigs far out and deep down into the water and installing a network of associated pipelines and other infrastructure. Over that time, they have extracted more than 43 billion barrels of oil and gas equivalent.

But many of these fields are now reaching the end of their productive lives and need to be closed. The industry is already closing more sites than it is opening and by the 2050s much of it is expected to be gone. That will eventually mean plugging and abandoning over 3,500 wells and deciding what to do with more than 250 platforms, 250 subsea production systems and thousands of kilometres of pipeline (see map).

Map: Oil and gas fields in the North Sea
Map: Oil and gas fields in the North Sea

In 2015, £1.1bn was spent on decommissioning in the UK, compared with £800m the previous year, according to trade body Oil & Gas UK’s Decommissioning Insight 2016 report.1 This was 5% of industry expenditure in 2015, up from 2% in 2010.

The organisation is keen not to characterise the increase in decommissioning as a “rush”, noting that the decision to start decommissioning is driven by complex reasons.

Some operators have certainly been given pause for thought by a decrease in operating costs (partly through revenue tax cuts), an increase in operational efficiency and an obligation on producers and regulators, introduced in 2015, to “maximise economic recovery” by ensuring every last viable drop has been extracted.

But the overall trend is an inexorable one: the age of much of the infrastructure, combined with a depressed oil price, have made extraction much less economic and driven a big increase in ‘cessation of production’ requests submitted to the industry’s regulator, the Oil and Gas Authority (OGA), since 2013 (see figure). 

Figure: Decommissioning and field development requests
Figure: Decommissioning and field development requests

The Department for Business, Energy & Industrial Strategy (BEIS), which regulates the industry under the Petroleum Act 1998, has also seen an increase in the number of decommissioning programmes submitted.

The changing economics of energy generation across the world, particularly the falling cost of renewables, and the potential for stronger climate change legislation in future may also be playing a part. But none of the documentation on decommissioning ENDS examined from government, its regulators, trade organisations or companies themselves mentions these subjects.

The OGA expects the rise in requests to continue for the next few years, alongside a fall in new field development plans. The Insight report notes that 94% of North Sea decommissioning projects are still in the early planning stage, with peak activity forecast for around 2024/25. That is because they are complicated projects, requiring a lot of groundwork and planning. 

While there are various options for decommissioning oil and gas infrastructure, the process is heavily controlled, partly in response to Shell’s abortive attempt to dump the obsolete Brent Spar oil storage platform on the ocean floor in 1995. This catalysed a sea-change in the regulation of decommissioning, culminating in an amendment to the 1992 Convention for the Protection of the Marine Environment of the North-East Atlantic, known as OSPAR.

This prohibits the disposal and abandonment of offshore installations at sea. All topsides – the upper part of a rig, which houses the helipad, accommodation block and other operational areas – must be removed, although in a few cases a derogation can be sought to leave substructures in place.

BEIS’s decommissioning guidelines are currently under review, but at present plans must be accompanied by a ‘comparative assessment’ examining the technical feasibility, environmental and social impact, economic and health and safety implications of all viable approaches. Operators can choose how they weigh up these different factors. An environmental impact assessment (EIA) is not a statutory requirement at the decommissioning stage, but BEIS still expects to see one.

Before approving a programme, BEIS also consults with the Environment Agency (and the Scottish Environment Protection Agency if appropriate), which are then responsible for regulating any associated wastes.

Clare Lavelle, Scotland and north-east energy consulting business leader for engineering consultancy Arup, says there has been a general reluctance among operators to tackle the problem of decommissioning. “It was historically perceived as a less valuable part of the business and so you often saw that people were very focused on [exploration and production] and put off making decisions.” But this is changing.

BEIS approved 19 decommissioning programmes in 2015 and ten in 2016, compared with fewer than four a year a decade earlier, and expects this will continue to rise; the latest was received from Shell in February. It consults with operators about their future plans to ensure it has enough staff to do its regulatory work.

Expensive business

The costs of decommissioning are still very uncertain. According to a recent analysis by specialist research firm Wood Mackenzie, the industry will have to shell out about £53bn over its decommissioning lifetime. Of this, about a fifth will be spent in the next five years. That is higher than HMRC’s latest estimate of industry liabilities, which is £43.7bn from 2016/17 to 2041/42. One of the OGA’s priorities is to provide greater certainty around the cost estimate – a project on this subject is aimed to be completed by the end of March.

Fiona Legate, senior analyst on UK upstream oil and gas at Wood Mackenzie, says estimates have risen substantially over the past five years, in part because of cost inflation. “But we’ve also seen that, as the UK matures and companies are carrying out more decommissioning work, and as it becomes closer to fields ceasing, they’re carrying out much more regular and rigorous reviews of their costs, so they’re getting more accurate.

“As we’re seeing more projects being completed, we’re seeing more benchmarking information available in the public domain. With the Oil and Gas Authority there’s also more of a push for transparency for companies that have finished decommissioning work: what did it cost, what went wrong, what can other companies learn from it?” Legate adds.

Wood Mackenzie expects companies to recoup about half of the £53bn in tax relief designed to prevent clean-up liabilities deterring investment, which is set against the tax companies previously paid on offshore oil and gas. This will in effect result in a bill to the taxpayer of up to £24bn, it says, although the industry maintains that funding all the decommissioning that will be required is still a problem.

According to BEIS, decommissioning is a “stage in the life cycle of a field, and operators are expected to meet its costs as they do with any other stage”. It says the Petroleum Act 1998 aims to protect the taxpayer from picking up the cost of decommissioning by placing the obligation for the task on the owners of an installation or pipeline. 

Michael Tholen, Oil & Gas UK’s upstream policy director, said companies are fully aware of their long-term legal liabilities – operators remain liable forever for the fate of their field infrastructure – but the industry is not currently considering any form of mutualised insurance fund to manage decommissioning liabilities. Instead, it is looking at whether there is a “case for change and potential alternative mechanisms for managing liabilities associated with decommissioned oil and gas structures and associated facilities, including wells” in the UK continental shelf.

Lavelle says there were commercial reasons for operators to underestimate decommissioning costs, but the industry is beginning to understand that it must tackle the problem. “Operators are also realising that it’s an interesting challenge. You see that [they] are now really resourcing and engaging for quite a long period before they expect to stop production.”

A lot of that early work is in planning and surveying, which is where environmental consultancies can play an important role. Indeed, the UK government now considers decommissioning to be a significant socio-economic opportunity in terms of job creation and export opportunities. Scotland, in particular, hopes it will boost the local economy, which has been hit by falling oil prices. In February, it launched a £5m fund to support infrastructure upgrades and innovation in salvage and transport methods.

To do this, the industry needs to evolve and address problems such as skill shortages and supply-chain issues.2  But its biggest emphasis at present is on cutting costs.

The OGA, which has a duty to help cut costs, aims to deliver a 35% decrease by 2020. It has formed a decommissioning board populated by regulators and operators, working with industry organisations Decom North Sea and Oil and Gas UK. This has improved the sharing of good practice and expertise, although there is still some way to go.

One approach is to look to those who have already begun decommissioning. The key international reference point is the Gulf of Mexico, where fields have been forced to close because of damage caused by extreme weather. Some operators there have run ‘rigs to reef’ programmes, leaving large parts of platforms under the sea to become habitats for marine life. But the transfer of that knowledge to the North Sea is limited because the southern seas tend to be more benign, structures are often smaller and the regulatory environment is completely different.

The OGA has also noted an urgent need for new technology to save money in well plugging and abandonment, which makes up about half of overall projected decommissioning costs. Oil & Gas UK is currently working with the Oil and Gas Authority’s Technology Leadership Board and the Oil and Gas Technology Centre to improve this area. But while innovation and transformation are important, “more immediate incremental improvements and challenges to traditional approaches can also bring significant results”, the OGA adds.

Environmental consultants agree with this assessment. Andrew Sneddon, director of oil and gas operations at Aecom and a board member of Decom North Sea, says efficient decommissioning is about robust management. “We don’t see some magic technology as the silver bullet. Tight control over management, methodology and schedule is really the key.”

Aecom is learning from decommissioning experience in the nuclear industry. Key points are “early supply-chain involvement and helping operators switch from operations to decommissioning”, says Sneddon.“That requires a mindset change and managing that personnel side of things.” 

Arup’s Lavelle agrees, saying most innovation is about knowledge transfer. Exploration and production are quite different from decommissioning and do not always provide the best solutions, she points out. “The oil and gas industry has traditionally been somewhat insular in that people have tended to work and stay there,” Lavelle says.

“An example of what we’re doing for a number of operators is looking at their procurement processes. A lot of innovation is not about a new bit of technology, it’s about a new way of doing something. It may not be brand new, but it’s new for the oil and gas industry.”

Nathan Swankie, a principal at Ramboll Environ, points to risk assessment approaches identified as best practice. “An analogy would be to look at the UK’s approach to contaminated land. Instead of asking that it’s cleaned up to its original condition – pristine or greenfield – they identify a standard of suitable for use, and that’s because the UK has recognised that it’s not practical to return all the land to exactly how it was before.” But he notes that in other places it would be difficult to change things without changing the rules around decommissioning.

Artificial reefs

One of those rules is OSPAR’s 98/3 amendment, which is due for review next year. Although derogations from OSPAR have been sought and accepted in the past, only a few projects are even eligible to apply. Writing in The Times in January, former energy minister Ed Davey and environmentalist Jonathon Porritt called for the rules to be revised, echoing previous criticisms from people such as David Bellamy.

They said the science had moved on since 1998 and the clean seabed principle “might actually harm the marine environment”, suggesting subsea structures could be left or collapsed on the seabed to create artificial reefs, with some of the money saved to be spent on other environmental projects.

Swankie of Ramboll Environ, which has been working on a project for which a derogation application may be submitted, argues there is a lack of flexibility with the current wording in amendment 98/3. “There’s an assumption that moving the installations is the best thing for the environment, and we’d be interested in whether the wording could be amended.”

He says a comparative assessment, similar to that required for decommissioning approval, could be undertaken where an operator has to evaluate a variety of options and identify which is best. “Instead of adopting a clean seabed standard you could adopt a ‘suitable for use’ approach, which would allow a bit more flexibility.”

Doug Parr, Greenpeace’s chief scientist, is far from convinced. “They’re essentially wanting to rerun the discussion underpinning the original decision, but the decision stands. It feels to me like there’s already flexibility in the system to make the environmental case, and I struggle to see how doing a full environmental assessment each time would help more.”

But Swankie would at least like to see the debate reopened. “We’re seeing improvements in science and knowledge, and increasing costs for decommissioning, so it seems to make sense that we can take account of the different pressures and factors and come up with a more proportionate approach.”

He suggests a natural capital approach could be taken, considering the value of existing installations in providing new habitats. There are also risks of habitat disturbance or destruction from decommissioning activity such as rock dumping or drilling.

Work is being done to investigate this issue. The Insite programme, funded by a group of oil and gas firms, awarded £1.8m to several European science institutes last year to better understand the influence of man-made structures on the North Sea ecosystem. It builds on a study five years ago by Oil & Gas UK, which identified significant gaps in the available data.

Insite’s studies are due to report in 2019. That will be after the next OSPAR review, but it is hoped there will be more thorough information available to make good environmental decisions about how to decommission future infrastructure.

BEIS is also currently reviewing its environmental assessment requirements to ensure they are proportionate and fit for purpose. It is engaging with stakeholders on this and says an updated document will be published “in due course”.

In the meantime, the industry is ploughing ahead with preparatory decommissioning work and, barring a sudden resurrection in the oil price, that is unlikely to stop.

isabella.kaminski@haymarket.com