LONDON (ICIS)--One of the fundamental advantages of hydrogen as a low-carbon energy carrier is storage.
Natural gas is injected into depleted fields and salt caverns across the summer months when demand is low, then withdrawn during winter to be used in heating.
This picture could in theory be altered to suit hydrogen.
Equally, in a decarbonised future where the electrification of heat processes is adopted in place of burning natural gas, then hydrogen could be stored during winter months, when wind outturn is highest, and used for power generation in the summer.
Under either situation, storing hydrogen is pivotal to successful decarbonisation efforts.
However, market confidence in hydrogen is paramount, and confidence comes from familiarity.
ICIS has spoken to natural gas storage operator, Storengy, to establish facts about the suitability of hydrogen as a storable molecule.
Q. How long does it take to either build a new hydrogen-ready cavern or convert an already operational natural gas cavern?
A. The time to create a new hydrogen cavern of a size comparable to the [Storengy-owned] Stublach Caverns (320,000 m3 geometrical volume) is similar to a natural gas cavern. A key parameter is the availability of a solution mining infrastructure. If this must be built an additional two years must be factored in prior to the cavern construction. The duration required to create a new cavern, which includes the drilling of the well and the solution mining is typically three and a half years, but this can be varied from two and a half to six years. The quicker the cavern development time the higher the cost of the electricity for the solution mining.
The duration required to re-purpose a similar sized cavern used for natural gas would be between one and a half and two years, depending whether the existing sub-surface equipment and the wellhead provide acceptable leak rates for hydrogen or they need to be replaced.
The testing and development requirements of obtaining certification for sub-surface safety valve and packer, wellhead assembly and casing with a screwed joint would be about a year prior to the start of the programme.
Q. What capacity do you expect hydrogen storage sites to have, and how will these sites differ from methane, for instance when looking at the different volume per molecule between methane and hydrogen?
A. Each 320,000 m3 cavern can store c.65,000 MWh of hydrogen, of which c.40,000 MWh would be working gas volume. The ratio of working gas volume vs total volume would be a bit lower compared to natural gas due to the properties of hydrogen.
Studies and testing has shown the Cheshire Salt Strata [location of majority of UK MRS] is suitable for the storage of hydrogen. The results from the tests show the salt has a mean permeability value of 0.18 [permeability measure] µDarcy which is better than the range of 1-10 µDarcy which is regarded as gas tight.
Q. Do you imagine access to stored hydrogen will be as quick and responsive as current access via medium-range sites to methane?
A. We envisage a flow rate of c.1,300 MWh/d (55 MW) per cavern, a speed to what we currently operate with natural gas caverns (30 days to totally fill or empty the working gas volume).
Q. Would you be able to store a blend of hydrogen/methane into the same cavern, or would it need to be unblended before storing?
A. This certainly would be possible but it has not been looked at in the Centurion and HySecure studies. Our sister company in France [ENGIE] has stored town gas in the 1950’s which was a blend containing 40 to 50% of hydrogen. Any blend of hydrogen and methane could be stored in salt caverns but further work is required to understand whether the mixing of the hydrogen and methane could be affected by the caverns operating conditions.
Q. What projects are you looking into at the moment for hydrogen storage and when do you see them coming online?
A. We are looking at hydrogen storage projects in all three countries where Storengy operates (UK, France and Germany). In the UK, the Phase 2 of HySecure consists in developing a new cavern at the Stublach site with our partner Inovyn.
In the absence of a large hydrogen market and of a commercial model for hydrogen storage this will require some form of public funding to happen. The Regulated Asset Base appears to be the most suitable way of funding such a multi-year development, but we are exploring all funding routes. The multi-billion Euro hydrogen investment plans announced by Germany and France may offer opportunities and we hope that the UK will follow.