Billions must be invested in hydrogen storage this decade to provide long-term flexibility to future grids: industry group
Newly launched organisation argues H2 is the only way to store renewable electricity on season-to-season or yearly basis, but there is major uncertainty around costs of different storage methods
A new industry group, H2eart for Europe, has warned in its launch report that between €18bn and €36bn ($19.5bn-39bn) will be needed to set up enough underground hydrogen storage systems to provide long-term flexibility for zero-carbon grids.
The group claims that hydrogen is the only zero-carbon option for replacing fossil-fuel-fired peaking power to manage variable renewable electricity generation on a season-to-season or even year-by-year basis.
“Batteries are adequate to provide short-term flexibility by storing relatively low volumes of energy with quick charge/discharge rate,” H2eart notes, adding that these technologies “fall short in providing long term flexibility due to limited energy storage”.
Larger systems meanwhile are expected to be extremely expensive or come with major environmental impacts — such as upstream lithium mining.
Pumped-hydro storage and biomass-fired power plants, which can provide dispatchable power over a longer period of time, are dismissed as “technically viable options but not sufficiently scalable and geographically limited”.
As such, while H2eart predicts that 209TWh of additional short-duration energy storage will be needed by 2030 — which can be filled by batteries — as well as 105TWh of week-to-week or month-to-month storage, it also projects 36TWh of long-term storage, ie, from hydrogen, will be needed.
H2eart also cites an estimate from an as-yet unpublished report from Gas Infrastructure Europe, a separate lobbying organisation, which states that 40-50TWh of working gas capacity from underground hydrogen storage would need to be developed by 2030.
However, H2eart only tracks 9.1TWh of new hydrogen storage set to be developed by 2030. And while this would rise to 22.1TWh of pure-hydrogen storage projects by 2040, by that year “the storage requirements have increased massively, based on the uptake of [renewables] deployment across Europe, as well as the increased demand for hydrogen and need for a base supply to various industries”, although the report notes that “it is currently unclear how large that gap will exactly be”.
Not all storage is created equal
Part of the reason for H2eart’s extremely wide range of cost estimates for building out enough underground hydrogen storage by 2030 is the sheer variation in costs between different storage methods, as well as whether assets are repurposed or newly built.
Salt caverns, or artificial structures constructed within naturally occurring underground rock salt formations, are expected to offer the lowest overall cost of storage.
However, the report cautions that these are geographically constrained primarily to northern central European countries, while the upfront cost of development is also expected to range from €700/MWh in an optimistic case to €1,100/MWh in its more conversative estimate.
Rock caverns, or structures carved into metamorphic or igneous rock, have also been proposed, but the report warns that “their costliness positions them for specialised use reserved for peaking facilities in regions lacking alternative storage options”. H2eart estimates that these would cost €1,000/MWh to build in an optimistic case, rising to €1,400/MWh in its conservative case.
The report also discusses depleted reservoirs and aquifers, both of which are porous underground rock structures, as potential options with much lower capex than salt or rock caverns.
It estimates in an optimistic case that both would cost €350/MWh, while depleted gas reservoirs would cost €550/MWh and aquifers €700/MWh in its conservative scenario.
H2eart also raises that depleted gas reservoirs often offer greater volumes of storage space than salt caverns and take one to two years less to construct depending on whether it is a new development or a repurposed gas storage facility.
However, while the report claims that “their historical competence in storing gas for extended periods suggests a capacity to accommodate hydrogen, aligning with evolving energy needs”, it also acknowledges that more research needs to be done in this field.
A recent study by the University of Aberdeen exploring the feasibility of hydrogen storage at the depleted Cousland gas field concluded that this individual reservoir “a poor site that fails to meet the criteria for safe subsurface [hydrogen] storage”.
Its lead researcher John Underhill also warned in a press release that the lack of naturally occurring hydrogen in UK gas fields “raises the question of whether it was once there and leaked, and crucially if it would stay underground if it was injected into a subsurface site”.
H2eart also cautions in its report that hydrogen and natural gas have different properties when it comes to compression.
“Hydrogen flows faster due to its low density and exhibits a negative Joule-Thomson effect, wherein it heats up during expansion and cools down during compression,” the report notes. “This contrasts with natural gas, which, like air, heats up on compression and cools down on expansion.”
The report adds that this “has implications for the design of storage systems and compressors under high pressure”, while conversion of existing facilities will require safety concepts for the permitting process.