The most obvious obstacles to a big ramp-up in global hydrogen production are well known. They include technological breakthroughs to bring down production costs along with new sources of demand from the power and transportation sectors.
Less obvious is that a small army of reservoir engineers, geologists, and other subsurface experts will be needed to understand where and how tomorrow’s hydrogen hubs will store their clean-burning fuel.
Bulk storage on the surface is considered by many experts to be simply out of the question. That means large hydrogen projects will need a subsurface component, and some think depleted oil and gas fields—with an emphasis on the latter—may fit the bill. Saline aquifers are being eyed for the role too.
But as this all suggests, no one has ever attempted to use these formations for hydrogen storage. Just four shallow salt formations, three salt domes in Texas and one salt field in the UK, represent the totality of the world’s hydrogen underground storage (HUS) capacity.
Research is underway to expand HUS in salt formations but that will not solve for the fact that they are not a geologic option for many locations where big industrial players are hoping to produce hydrogen. This includes most of Europe and most of the US outside of its Gulf Coast states.
By contrast, deeper sedimentary structures of various flavors are in no short supply but lack any material field experience that might help jumpstart the de-risking of storing several Bcf of hydrogen.
The upstream industry’s extensive experience in operating what are the closest analogues—natural gas storage and carbon capture and storage (CCS)—will help that process but there are new challenges when it comes to injecting the universe’s smallest molecule into porous media.
Topping the list is hydrogen’s strong propensity to migrate inside a reservoir (laterally and vertically) along with the potential for troublesome chemical and biological reactions.
Hydrogen may also be clean burning but it offers only about a third of the energy density as methane, which means it needs roughly three times the storage volume to deliver the same energy output to a gas-fired power plant.
Among those working to bring clarity to such issues is Mojdeh Delshad, a reservoir engineer and professor at The University of Texas at Austin. Her latest research involved using commercial reservoir simulators to model what would happen if selected gas fields and saline aquifers in the US used for CCS or natural gas storage were instead used to store hydrogen.
“We wanted to know about the challenges of hydrogen, which because of its properties—very low density, very low viscosity—is going to move in the reservoir much more quickly than CO2 and methane. And that’s exactly what we found, which means we’re going to have to do something differently with hydrogen storage in order to capture and produce what is injected,” said Delshad.