Every time the UK adds more offshore wind or solar capacity, it runs into the same wall: where to store the surplus power. Without a way to bank large amounts of electricity across seasons, the expansion of renewables will eventually hit a ceiling. Ironically, one possible answer lies beneath the North Sea, in the very oil and gas fields that have already been emptied out. A research team at Durham University has calculated that converting depleted oil and gas fields into green hydrogen storage could hold 3,659 TWh—more than seven years' worth of the UK's projected annual electricity demand in 2040. Yet the only project currently taking concrete shape, Centrica's plan to repurpose the Rough gas field, would add just 10 TWh of storage capacity—less than 0.3% of that theoretical figure.
Seven Years of UK Hydrogen Hidden in North Sea's Spent Fields
A six-person research team led by Zongtai Zhang of the Durham Energy Institute, Durham University's energy research center, published a paper in the journal Applied Energy calculating the total hydrogen storage capacity that could be built in depleted North Sea oil and gas fields at 3,659 TWh. That figure is said to equal more than seven years of the UK's projected annual electricity demand in 2040. The team reportedly built a digital twin of the UK power system using half-hourly generation and demand data, incorporating the expected growth of electric vehicles, heat pumps, and data centers. The study itself was published in mid-June 2026, and the Tech Xplore article referenced here was republished via The Conversation on August 24 of that year.
According to the estimates, a high-storage scenario that makes maximum use of this capacity could allow the UK to fully retire conventional gas-fired power plants by 2040. Under current storage plans, which center on salt caverns, capacity would fall short, leaving surplus renewable electricity underutilized. Across all scenarios examined, the share of gas-fired power in UK electricity generation is projected to fall to around 1% by 2030.
To get a sense of scale behind the "seven years" figure, a simple back-calculation is useful. The UK's annual electricity consumption is currently estimated at roughly 280–320 TWh (as of 2024). Working backward from the study's claim that 3,659 TWh equals more than seven years of demand implies a projected annual demand of over 520 TWh by 2040—roughly 1.6 to 1.8 times today's level. This figure was not directly published by the research team, but it suggests that an assumption of substantially higher future electricity demand, driven by factors like EV and data center growth, underpins the storage-scale discussion.
Why Depleted Oil Fields Could Work as Hydrogen Reservoirs
Depleted oil and gas fields are candidates for storage because the geological formations that trapped oil and natural gas underground for millions of years have already proven their ability to hold gases without leaking. The fact that oil and gas remained sealed in place for so long means the overlying caprock has demonstrated high impermeability, and reusing existing wells and pipelines could also cut costs on new drilling and infrastructure. Building on this logic, the North Sea already has a track record of repurposing depleted hydrocarbon reservoirs for natural gas storage.
However, that track record is limited to natural gas—there is no long-term operational experience with hydrogen. Technical questions remain around hydrogen storage: concerns that microbes living in the geological formations could metabolize hydrogen into methane or hydrogen sulfide; whether the reservoir's caprock can seal in molecules as small as hydrogen over the long term; and how much cushion gas—gas kept in reserve to maintain constant reservoir pressure—would be required. The natural gas track record does not verify these hydrogen-specific challenges. The scale of the 3,659 TWh theoretical figure and the question of whether it can actually be operated need to be considered separately.
Rough Gas Field's 10 TWh Shows How Far Implementation Has to Go
At present, the only concrete development toward hydrogen storage in the North Sea is the plan to repurpose the Rough gas field. UK energy major Centrica has indicated it would invest £2 billion (roughly ¥434 billion, based on the GBP/JPY exchange rate as of August 25, 2026), contingent on reaching a regulatory support framework agreement with the UK government, to convert Rough into a long-term storage hub for both natural gas and hydrogen. If realized, this would add an estimated 10 TWh of hydrogen storage capacity. Because the regulatory framework has not yet been finalized, the investment is not confirmed. Compared with the study's theoretical potential of 3,659 TWh, this 10 TWh amounts to less than 0.3% of that scale.
The field previously operated as the UK's largest natural gas storage facility but was closed in 2017 over safety concerns, reopening in 2022 with reduced capacity. While there is technical precedent for reusing depleted hydrocarbon reservoirs, that precedent applies to natural gas—no North Sea oil or gas field other than Rough has publicly announced concrete plans to explore conversion for hydrogen. How much of the 3,659 TWh theoretical figure can be translated into actual development plans depends on whether similar conversions at fields beyond Rough prove economically viable. At least within the scope of the materials referenced here, no estimate of the total cost of developing the North Sea as a whole could be confirmed.
The research team also pointed out that current plans centered on salt caverns would leave storage capacity insufficient, preventing full use of surplus renewable electricity. The theoretical 3,659 TWh capacity of depleted oil fields is positioned as an option that could fill this gap. Regardless of which path is prioritized, only one concrete development plan—Rough—is currently in motion, and what comes next will depend on future announcements of individual projects.
UK Hydrogen Policy in Context: Comparing to 2,150 TWh in Salt Caverns
UK hydrogen storage policy has so far centered on onshore salt caverns, a geology with established technical track record. Salt formations suitable for caverns are distributed across three regions—Cheshire, Wessex, and the East Coast—and a 2022 academic study (Williams et al., Journal of Energy Storage) estimated the UK's total salt cavern storage capacity across these three regions at up to 2,150 TWh (equivalent to more than 64 million tonnes of hydrogen), with the East Coast region alone accounting for 1,465 TWh. However, a separate study published in 2026 (Garvey et al., Geoenergy) reassessed the East Coast region by incorporating existing and planned industrial, social, and environmental land-use constraints, revising the actually developable storage capacity down to just 22–48 TWh for the East Coast alone—a roughly 95% downward revision. The 3,659 TWh figure for depleted oil and gas fields presented in this new Durham University study exceeds even the pre-revision, UK-wide theoretical figure, but the two numbers were calculated under different conditions—whether land-use constraints were incorporated or not—and are not directly comparable on the same basis.
The differing suitability of the two options is also worth noting. Salt caverns can have their cavity shapes artificially adjusted through solution mining (a method of dissolving salt with water to create cavities), making them suited to applications requiring frequent, short-cycle injection and withdrawal of hydrogen. Depleted oil fields, by contrast, rely on existing geological structures, offering less flexibility in cavity shape, but they can reuse surface infrastructure such as wells and pipelines, making them suited to large-volume, low-frequency, seasonal storage. Rather than competing with each other, the two are better understood as serving complementary roles—one for short-term fluctuations, the other for seasonal storage.
In its April 2022 Energy Security Strategy, the UK government set a goal (contingent on factors such as cost-effectiveness) of up to 10 GW of low-carbon hydrogen production capacity by 2030—double the previous target of 5 GW—with at least half to come from electrolytic hydrogen. Storage infrastructure development underpins this entire production target.
This target concerns only hydrogen production capacity; no numerical target for storage capacity has been set. The government's 10 GW production target and the academic estimates of 3,659 TWh and 2,150 TWh for storage have thus far been discussed in separate documents. The 3,659 TWh figure presented in the Durham University study could serve as one piece of material linking this production target with storage capacity. Professor Chris Groves of Durham University's engineering department has reportedly said hydrogen should function not as a standalone fuel but as part of a flexible system encompassing renewables, electrolysis, storage, and power plants.
A New Energy Chapter for a North Sea Japanese Firms Once Left Behind
Japanese companies have their own history of exiting North Sea oil fields. On November 26, 2021, JX Nippon Oil and Gas Exploration, part of the ENEOS group, announced an agreement to sell all shares of its wholly owned subsidiary engaged in crude oil production in the North Sea to UK-based Neo Energy. The enterprise value at the time of the agreement was $1.655 billion (roughly ¥188.5 billion at the time), but the actual transfer price, adjusted for borrowings and working capital, came to $433 million (roughly ¥53.3 billion). The deal closed on March 29, 2022, and was described as part of a portfolio shift toward a low-carbon society. That transfer price amounts to just over a tenth of the £2 billion (roughly ¥434 billion) Centrica plans to invest in the Rough conversion—reflecting the substantial gap between the value of divested oil assets and the scale of investment now flowing into hydrogen infrastructure.
What this Durham University study suggests is that North Sea oil and gas field infrastructure, left behind by companies including Japanese firms, could become the stage for the next energy transition. The next step in translating the theoretical 3,659 TWh figure into actual development plans hinges on whether operators following Centrica's lead can bring similar conversions to fruition at fields beyond Rough.
Professor Stuart Jones, co-director of the Durham Energy Institute, has reportedly said hydrogen could become a sovereign asset for the UK, free from reliance on imports. To demonstrate across the whole North Sea the vision Professor Groves described—hydrogen as part of a flexible system—will require accumulating geological surveys and pilot projects at sites beyond Rough to address technical questions such as microbial gas conversion, sealing integrity, and the amount of cushion gas required. The first piece needed to close the gap between 3,659 TWh and 10 TWh comes down to when and where these precedent-setting projects get underway.