The UK's oil and gas industry, regulators and offshore wind developers are optimistic about overcoming technical, commercial and other challenges — including a bill of up to £5 billion ($6.76 billion) — to electrify enough North Sea platforms to meet impending emissions reduction deadlines.
The North Sea Transition Deal signed with the UK government last year committed the industry to reducing greenhouse gases emitted during production by 10% through 2025, rising to 25% by 2027, and 50% by 2030 — against a 2018 baseline — before hitting net zero by mid-century.
The UK sector currently produces about 1.6 million barrels of oil equivalent per day, emitting about 14 megatonnes of carbon dioxide equivalent per annum in the process, about 4% of the UK economy’s total.
Some is from the flaring or venting of natural gas, some from logistics, but the bulk — about 70% — is from greenhouse gases in the exhaust fumes given off by the gas or diesel-fired generators that power equipment and lighting on platforms far out in the North Sea.
Societal licence to operate
Some of the cuts are expected to be met as older, more polluting platforms naturally fall out of service as their reserves dwindle and output becomes uneconomic.
But amid growing public concern about global warming, switching facilities that remain to run on cleaner electricity — usually generated onshore, at a nearby wind farm, or by an integrated combination of both — is now widely considered as a minimum requirement for the industry to maintain its so-called "societal licence to operate".
It is also seen as essential for propping up investment and helping the UK meet its legally binding targets of becoming a carbon neutral economy by 2050.
Some high-voltage, direct current power-from-shore systems have are already running platforms off Norway, notably at Equinor’s giant Johan Sverdrup development and at BP’s Valhall facilities, but this has not yet been achieved off the UK.
The Norwegian schemes have largely been greenfield, making electrification technically easier cheaper than the extensive brownfield modifications and retrofitting to many producing platforms that will be needed in the UK sector.
Participants in an online discussion of the topic organised by newly rebranded trade organisation Offshore Energies UK (OEUK), formerly Oil & Gas UK, heard that while technically possible, achieving this will not be cheap.
Subsea 7-owned consultancy Xodus estimated that total combined capital expenditure required will be between £3.5 billion and £5 billion, depending on number of assets to be electrified.
“We have the technology. We have all the different foundation blocks to deliver electrification projects today — at the moment it costs," said Daniel Paterson, principal consultant at Xodus.
“This is a considerable capex on a basin which has seen a historical declining trend in investment.”
Race against time
Thibault Charet, emissions improvement manager at OEUK, pointed out the basin is facing a race against time, with project timelines in need of tightening to deploy electrification in the basin by 2027 and at scale by 2030.
Typical development timelines are currently estimated at eight to 10 years.
“One of the challenges is to squeeze [these timelines] to four to six years,” Charet said, adding that facilities currently with a cessation of production (COP) date beyond 2030 are a “good candidate for electrification”.
Charet pointed out that electrifying an asset is more cost-effective the longer it has to produce but offers “diminishing returns” the nearer it gets to COP.
Another challenge is aligning the large number of different players involved in electrification schemes, including regulators, oil and gas operators, wind developers, the connection to shore, as well as onshore stakeholders, among others, many of whom might have different working cultures or commercial imperatives.
Asmund Maland, group vice-president for subsea and offshore power, at ABB told the panel his company’s experience of working on projects in Norway demonstrated that it is "quite difficult to get everybody walking in the same direction".
The Norwegian projects were successful because regulators there built in electrification obligations to operators’ licences rather than “counting on co-operation”, he said.
Current power demand for all facilities on the UK continental shelf is about 2300MW. This is expected to fall to about 1360MW in 2030, with the West of Shetland area accounting for about 200MW of that and the central North Sea about 800MW to 900MW.
Andy Brooks, Central North Sea area manager at the UK Oil & Gas Authority (OGA), said electrification will play a "crucial part" in meeting the 2027 and 2030 targets but this will need collaboration across sectors, companies, governments and regulators, as well as big investments in offshore transmission and an expansion of grid and offshore wind capacity.
Even in the last year, Brooks has seen a lot of progress and welcome evidence of changes in working cultures in oil and gas operators, who now appear more ready to listen to wind developers and contractors and relax their usual insistence of keeping tight controls over all aspects of project management.
“We need to get out of this of traditional oil and gas ‘we know how to do projects best’ [mindset] and actually hand some of that control and work over to those that clearly know better than we do,” he said.
Stuart Leitch, an analyst with Westwood Global Energy Group, told Upstream that while the UK will undoubtedly see some assets being electrified, it will not be a case of “one solution fits all”.
“Platform location, topsides processing and security of power supply are just a few of the technical constraints, while field maturity, remaining reserves and proximity to nearby infrastructure will have a significant impact on commercial viability of any project," he said.
Almost 20 UK electrification projects are being considered in the UK, some led by oil and gas operators, some by pure-play renewables developers and some by private equity-backed infrastructure funds trying to replicate their success in the midstream oil and gas sector.
In the central North Sea, the main thrust is coming from two schemes, one focusing on the Outer Moray Firth, led by CNOOC Petroleum Europe in the Buzzard Area, and a second in the Central Graben Area, run a by a consortium of Harbour Energy, Shell, BP and TotalEnergies.
Both are looking at a range of concepts, including power from shore with integrated wind, and are expected to reach to a “select gate” around mid-2022, Brooks told the OEUK panel.
“Tangible progress” is being made, he said, after the government divided £1 million ($1.4 million) of funding between three schemes to carry out pre-front-end engineering and design work to address some of the “perceived barriers” operators and the supply chain feel they are encountering.
One winner, a joint scheme between wind developer Orsted and oil and gas operator Neptune Energy, claimed nearly £240,000 to "establish the key technical and commercial aspects of how to get stable and reliable power from a windfarm to an oil and gas facility".
In summer 2021, a new forum bringing together all the main regulators — including UK government departments, Marine Scotland, the Offshore Petroleum Regulator for Environment & Decommissioning, the OGA, Crown Estate Scotland, Ofgem and the Health & Safety Executive — was formed to look at the regulatory barriers facing electrification.
This Government & Regulators Electrification Group is expected to update industry “very soon” on the progress it has made so far, Brooks said, which is expected to provide welcome regulatory clarity and could kindle new activity.
Bottlenecks and back-up
One other sticking point, the panelists cautioned, was that the industry could face bottlenecks in obtaining grid connections and windfarm access if many players want access at the same time.
To give developers the opportunity to build offshore windfarms specifically to provide low-carbon electricity to decarbonise the oil and gas sector, Scotland’s seabed landlord, Crown Estate Scotland, is planning the Innovation & Targeted Oil & Gas leasing round, known as Intog.
Another issue operators need to take into account is ensuring facilities have enough back-up power capacity if wind fails to blow.
Beatrice d'Eufemia, technical package manager at Orsted, told the panel: "It's constantly a battle between what's possible and what's expensive.
"You won't get 100% wind even if you put 1000 wind farms out there. So, it's what are the back-ups? Do you accept 95% and take that 5% and consider that a commercial loss or do you invest in back-up solutions to cover that last portion? So technologically speaking, we're all there. It's just money and time."
Despite the numerous challenges, many seem confident these will be overcome.
Rosy Jones, communications manager at Orsted, said the offshore wind and oil and gas industries “do talk slightly different languages”.
“So there has almost been 'onboarding' between the two,” she said.
“But there is a real push from both industries to achieve [these timelines]. We have definitely found some very good collaboration.”
D'Eufemia said: "The offshore wind industry has got a history of doing things everybody thinks is completely impossible within about half the time frame. So yes, I think we can,"
Xodus's Paterson said: "I think industry is motivated to deliver this, and there will be solutions that address some of the issues around costs and the regulatory challenges."