- A Wood study commissioned by Eclipse Energy models hydrogen production from depleted oil reservoirs at as little as $0.56/kg.
- The process recorded hydrogen at 40% of the produced gas during a 2025 field trial, but has not demonstrated sustained commercial production.
- The claimed economics could reshape the value of mature North Sea assets, although reservoir performance, gas separation, emissions and well integrity remain unproven at scale.
Hydrogen produced biologically inside depleted oil reservoirs could cost as little as $0.56/kg while generating very low lifecycle emissions, according to a techno-economic assessment conducted by Wood for US technology company Eclipse Energy.
The modelled result is substantially below most current low-carbon hydrogen pathways and even the US Department of Energy’s long-term target of $1/kg. Wood calculated carbon intensity at 0.076kgCO2e for each kilogram of hydrogen produced.
Eclipse’s RenovaStrata H2 process stimulates microorganisms in depleted reservoirs to convert residual hydrocarbons into hydrogen. Produced gases are brought to the surface through existing wells, after which the hydrogen must be separated from methane, carbon dioxide and other constituents.
Chief executive Prabhdeep Singh Sekhon said: “Our field demonstration proved the science.” Wood consulting chief operating officer David Cole said the technology showed “incredible potential to impact the energy industry”.
‘Huff-and-puff’
The assessment examined engineering configurations, capital and operating costs, power requirements, carbon-management options and commercial sensitivities. It builds on a 2025 trial in California’s San Joaquin Basin by Eclipse’s predecessor, Gold H2.
That trial reported hydrogen concentrations of 400,000 parts per million, equivalent to 40% of the produced gas stream, according to the Society of Petroleum Engineers. It used an existing well and a cyclic “huff-and-puff” process in which the biological treatment was injected before gases were recovered.
Producing a hydrogen-rich gas stream is not equivalent to demonstrating continuous commercial output. The public results do not yet establish long-term production rates, recoverable hydrogen per reservoir, decline curves, separation costs or how consistently the process performs across different geology.
The $0.56/kg figure is also a modelled best case from a study commissioned by the technology owner. Wood brings independent engineering expertise, but the assessment is not a peer-reviewed resource statement or the operating history of a full-scale plant.
That distinction is important because the claimed cost is exceptional. The IEA’s Global Hydrogen Review placed 2024 hydrogen from unabated natural gas at approximately $0.80–$4.60/kg, while renewable hydrogen remained more expensive in most regions. The US Hydrogen Shot target aims for $1/kg by 2031.
North Sea opportunity?
The UK North Sea contains mature reservoirs, wells, pipelines, offshore expertise and a large future decommissioning liability. Converting suitable fields into hydrogen-producing assets could extend infrastructure life, retain employment and reduce the amount of new surface equipment required.
Yet reuse is not automatically cheaper or cleaner. Ageing wells must remain secure when exposed to hydrogen, a small molecule that can escape through seals and affect some materials. Commercial plants would also need to manage methane and carbon dioxide in the produced stream, demonstrate that separation energy is included in the cost calculation and account for emissions from nutrient manufacture, pumping and reservoir operations.
Regulators would need to determine how the pathway fits within UK low-carbon hydrogen standards. Because the feedstock is residual fossil carbon, its eligibility would depend on verified lifecycle emissions and the ultimate treatment of co-produced gases, rather than the simple fact that the final product is hydrogen.
RenovaStrata could become valuable precisely because it combines biotechnology with existing oilfield capability. But the next milestones must move beyond concentration and modelling: sustained flow rates, independent emissions measurement, reservoir-by-reservoir screening and a financed commercial demonstration.
Until then, the assessment makes the technology worth watching, not yet bankable.
