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Electrify the North Sea, or else?

Electrification of oil and gas assets in the North Sea can offer a route to market for offshore wind while also cutting carbon. As always, though, the challenge is who would want to be the first out of the blocks?

Oil and gas operators in the UK North Sea are under increasing pressure to decarbonise their operations. The electrification of offshore oil and gas production platforms – by connecting them either to the grid or to nearby wind farms – is one way to tackle this.

Indeed, an emissions-reduction plan unveiled by UK regulator the North Sea Transition Authority (NSTA) in late March puts electrification and low-carbon power at the forefront of decarbonising the country’s production. Power generation accounted for 79% of upstream emissions in 2022, the agency has said.

The plan seeks to spur electrification by requiring operators to meet certain decarbonisation requirements.

For new developments starting up beyond 2030, this entails coming online fully electrified or running on low-carbon power with near-equivalent emissions reductions.

For existing platforms, the plan contains a warning that in cases where the NSTA considers it reasonable to electrify an asset but this does not occur, there should be no expectation that the regulator will authorise additional production from that asset in the future.

However, the electrification of brownfield infrastructure is a complex and costly proposition that will not make sense in some cases. As a result, it is possible that operators will opt not to electrify their platforms regardless of the carrots and sticks involved from a regulatory standpoint.

For those that do pursue electrification, technological advances over the coming years should help minimise the costs and challenges.

Ultimately, though, operators will need to decide on a case-by-case basis what infrastructure can be electrified. They will have to hope that the NSTA will not disagree with their conclusions in those instances where they do not find electrification to be a viable option.

The Rosebank development will be electrification ready
The FPSO for Equinor’s Rosebank

Early efforts

To date, Norway has made more progress on electrification in its portion of the North Sea. It has projects such as Johan Sverdrup, Edvard Grieg and Ivar Aasen receiving power from shore.

Clarksons Research’s managing director Stephen Gordon also pointed to Equinor’s Hywind Tampen wind farm. This is the world’s first floating wind farm built specifically to power offshore oil and gas operations.

“Equinor is expected to continue to be amongst the leaders in electrification, both in Norway and in the UK, where it is the operator of the future Rosebank FPSO West of Shetland,” Gordon told E-FWD. Equinor has said the FPSO is designed to be electrification-ready. The Norwegian company approved Rosebank in September 2023. However, it has warned that Rosebank will not be electrified before 2030.

Average emissions in the UK North Sea are around 20 kg of CO2 per barrel of oil equivalent. There are some signs that companies are already taking to heart the need to cut emissions. Equinor’s Rosebank should be around 12 kg of CO2 per boe, falling to less than 3 kg after electrification.

Equinor’s Martin Linge field in Norway, which started up in 2021, takes power via a 162 km cable. As a result, emissions are low – the company reported 1.3 kg per boe in 2023.

Equinor's Martin Linge, which has undergone electrification
Equinor’s Martin Linge

There are some early efforts underway to explore electrification of existing infrastructure in the UK.

The NSTA has pointed to examples including CNOOC International plans for the Buzzard platform in the Central North Sea, and to a consortium of BP, Shell and TotalEnergies focusing on installations in the Central Graben Area.

“Operators of infrastructure in the West of Shetland are also exploring electrification options – green power delivered from shore via cable is the current frontrunner,” an NSTA spokesperson told E-FWD.


Electrifying brownfield infrastructure is a complex, costly and technically challenging process, however.

“The electrification process necessitates comprehensive platform redesigns to accommodate the new systems,” Welligence Energy Analytics senior analyst for energy transition Fernando Tamayo told E-FWD. “In some cases, operators may even need to transport components or the entire facility to an onshore terminal to facilitate the retrofit.”

One of the major challenges centres around the fact that oil and gas platforms tend to be space- and weight-constrained. The equipment needed for electrification can be large and heavy, according to classification society and maritime advisory firm DNV.

“Careful calculations are needed around changes to the platform weight and the distribution of that weight as well as effects on the centre of gravity of the platform,” DNV manager for UK and Ireland offshore oil and gas Angus Milne told E-FWD. He added that this was especially important for floating assets.

This is in line with the findings from a brownfield platform electrification workshop held by the NSTA in February for operators and technology supplies.

The NSTA spokesperson said main topics raised in the workshop included engineering challenges primarily related to space and weight. Operators had called on suppliers to provide lighter and smaller equipment.

However, the representative was optimistic over suppliers’ ability to deliver the necessary equipment.

“The conclusions from the workshop were that the technology and equipment needed to electrify brownfield assets already exist,” the spokesperson said.


At the same time, though, the challenges extend beyond what needs to be modified on the platforms themselves. Operators also need to figure out where and how to source their power. And while opting for wind power will help bolster a project’s clean energy credentials, it comes with its own set of complicating factors.

“One of the primary challenges encountered by both wind developers and oil and gas operators pertains to the lead times associated with offshore wind projects,” said Tamayo.

Welligence estimates that wind power has a lead time of around 10 years to progress from project conception to operational implementation.

“Consequently, this extended timeline significantly restricts the number of upstream oil and gas projects that can viably connect to wind farms,” said Tamayo.

“It is crucial to recognise that in 10 years, there will be very few fields in the UK North Sea that are not in terminal decline. Consequently, these fields may not generate sufficient cash flow to justify the substantial investment necessary for electrifying existing infrastructure.”

A less favourable market has further exacerbated the challenges for wind development, given cost inflation and supply chain constraints.


Despite the obstacles, certain recent developments have been in the right direction.

Among these is the Crown Estate’s Innovation and Targeted Oil & Gas (INTOG) leasing round. This is the first of its kind in the world. This aims to attract investment into innovative offshore wind projects and provide power to North Sea oil and gas operations.

“INTOG has already yielded exclusivity agreements for seven offshore wind projects for decarbonising oil and gas platforms, allowing development work to continue,” said the NSTA spokesperson.

“Floating wind is a major factor here,” noted Clarksons’ Gordon. “Examples include the potential Aspen, Beech and Cedar floating farms in the Central North Sea.”

He added, however, that global sentiment on the potential scale-up and commercialisation of floating wind had softened over the past year or so. Inflationary pressures in the supply chain have made it a tougher market.

Nonetheless, the UK floating wind industry took a significant step forward in April with offshore planning approval granted to Flotation Energy and Vargronn’s Green Volt project. The project would generate up to 560 MW of electricity, a portion of which would be used to power offshore oil and gas platforms.

Green Volt may be used for the electrification works on Buzzard

Higher returns

Analysts have identified Buzzard as a likely candidate for power from Green Volt.

The wind project is a few years from starting up, with commissioning targeted by 2030. Its ultimate capacity depends on how many operators sign power purchase agreements (PPAs), although it is also on track to bid into the upcoming Allocation Round (AR) 6. Regardless of capacity, Welligence has highlighted Green Volt’s approach as one other developers could follow.

“During its initial years of operation, Green Volt aims to sell most of the generated electricity to oil and gas facilities, which we assume will enable them to generate a higher return per MWh sold,” said Tamayo. “As these oil and gas platforms are eventually decommissioned, any surplus electricity will then be sent into the grid.”

Similarly, other wind projects in the coming years should outlive brownfield oil and gas facilities in the mature region.

“Any power infrastructure which is installed now will likely have a longer life span that the assets it will be powering,” said DNV’s Milne.

Transition opportunity

EnergyPathways founder and CEO Ben Clube has set his sights on the energy transition opportunities offshore the UK. The company marries new thinking about electrification with a desire to exploit marginal fields.

The UK has 2 trillion cubic feet of undeveloped gas offshore Liverpool, Clube said. The company’s Marram field holds 46 billion cubic feet of recoverable resources, in shallow water.

“It’s close to infrastructure, within 10-20 km. We can develop Marram in a low carbon intensive way, at one quarter of the UK average – and one 15th of LNG imports,” Clube said. The project aims to take power from local wind resources, with EnergyPathways expecting 7-8 GW of wind resource in the area.

“Some companies in the oil and gas space try and create a veneer of clean energy. We were set up from the start to be an energy transition company. We are going to deliver decarbonised energy and energy security.”

Clube pointed to curtailment losses in the wind sector as costing the country significant amounts. “We are sitting on the UK’s major grid constraint,” he continued.

Initially, EnergyPathways expects to be able to generate enough of its own energy to meet its needs. “At some point, we will need additional compression – to convert the gas field into storage. There’s wind energy in the area and there’s more planned, we’re only a short distance away. We’re in discussions with Orsted, essentially supply is available.”

Room to run

EnergyPathways sees further potential in the energy space. Clube called for observers to consider Marram as “gas storage – that happens to be full of gas at the outset. We can use that gas storage for the price arbitrage. When the wind doesn’t blow, gas is the only solution.”

Electrification of Marram “helps secure support from the government regulator. If we were just a vanilla gas project, and we couldn’t demonstrate our decarbonisation credentials, it would be much harder to get through.”

In the longer term, Clube sees there being scope for expansion. “We can use our infrastructure to deliver hydrogen, we will already have pipelines to shore. It would involve converting our infrastructure asset base into a conduit to the UK.”

Case by case

There are alternatives to offshore wind, including power from shore. But it is in the interest of operators to find power sources located as close as possible to their assets.

“The distance of the asset from the power source is critical. An offshore power cable is costed in millions of dollars for each kilometre,” said Milne.

Some operators will still opt for a grid connection. This also circumvents the intermittency concerns associated with wind energy. Ultimately, using power from the grid still reduces emissions, even if the reduction is not as significant as what can be achieved by using “pure” wind power.

Milne still views this as a step in the right direction.

“Getting started as early as possible is important, then as more and more renewable power comes onto the grid, and as the battery storage solutions develop, the situation will improve further,” he said.

Falling short

Given the various factors and trade-offs, not all platforms will be viable candidates for electrification.

“The business case for the investment will be scrutinised very carefully and, in many cases, will fall short – meaning the upgrade project will not be sanctioned,” Milne said. “The benefits of the technical solution versus the cost of executing the upgrade project, all while considering the remaining life of field, will have to be carefully weighed up by each operator.”

As a result, some operators are looking at alternatives for decarbonisation of their offshore platforms.

“This could involve cheaper options like e-fuels, efficiency improvements and potentially using carbon capture and storage [CCS] on existing turbine exhausts,” said Milne.

The NSTA acknowledges that electrification will not be a suitable option for all platforms. Nonetheless, the regulator insists that those operators intending to produce oil or gas beyond January 2030 evaluate the technical and economic cases for brownfield electrification. And where it is reasonable to do so, they must invest, the NSTA spokesperson said.

This may not be enough to compel operators to electrify their assets, however.

“Companies will not necessarily electrify simply because they are compelled by regulation, they always have a choice and will make the best decision for their business,” said Milne.

“In fact, the cost of polluting may never be sufficient to pay for electrification,” he continued. “Even if the UK Emission Trading Scheme (ETS) hits £100 per tonne it still may not be enough to change behaviours.”

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