The hydrogen economy might be on its way, but it won’t be arriving any time soon, not until after 2030 at least. If and when it does make an appearance, it is likely to be somewhat different to the image of popular imagination because a hydrogen economy will run primarily on natural gas.
Parts of the hydrogen economy are falling into place, notably significant gains in electrolysing power. Polymer Electrolyte Membrane (PEM) electrolysers now come as complete operating units the size of an ISO container, offering MWs rather than kWs of power and the production of hydrogen is sufficiently pressurised without the need for a compressor for vehicle fuelling or methanation.
A gradual roll out of infrastructure is taking place, but fuel cell vehicle sales lag far behind EVs. Europe, which to some extent is developing hydrogen transit corridors, has less than a 100 hydrogen refuelling stations in operation. Japan has about half that number and the US even less.
PEM technology is being tested at scale at Shell’s Rhineland refinery in Germany, where an electrolyser with peak capacity of 10 MW will be installed by 2020.
“If powered by renewable electricity, the green hydrogen will help reduce the carbon intensity of the site,” says Shell. It may well be powered by renewable electricity and as such is a valuable way of reducing refinery emissions, which is no easy task as emissions from refinery processes tend to be spread over multiple, fairly small sources making capture difficult and expensive.
However, though large-scale for an electrolyser, it is still small-scale in terms of hydrogen production. The refinery requires 180,000 tons of hydrogen a year, while the 10 MW electrolyser will produce just 1,300 tons for an investment of €20 million ($22.6 million), implying that just under 1.4 GW of electrolyser capacity would be needed to meet the refinery’s total hydrogen requirements.
Space would be required to house the electrolysers, although perhaps not as much as might be expected as they could be stacked. The cost would also be substantial, although gains would be made from the scaling up of electrolyser production.
Apart from scale, the second problem is Shell’s ‘if’ with regard to the use of renewable energy to produce the hydrogen.
Power-to-gas concepts, which have been most widely tested in Germany, offer many attractions, but all are based essentially on what is considered ‘surplus’ renewable electricity. A study published by DNV GL in March, Hydrogen in the electricity value chain argued that renewable hydrogen will be competitive with natural gas by 2035, but the primary source of energy to produce the hydrogen – an energy carrier not an energy source – will still come from cheap surplus renewable electricity.
National energy systems with a high penetration of renewables can and do produce temporary electricity surpluses already. More common is renewable energy curtailment as a result of localised grid congestion.
Power-to-gas concepts use this low (sometimes negative) cost electricity to generate hydrogen and drop it directly into the gas grid. It is an elegant solution in may ways and gas grids can absorb a lot of hydrogen – somewhere in the region of 5-15% by volume, depending on the type of end-use equipment and the nature of the natural gas, regulations allowing.
However, hydrogen producers will not be the only callers on cheap surplus electricity, and they are unlikely to be the most cost effective over the next decade, owing to the efficiency penalties of first electrolysis and then combustion. Batteries or pumped hydro where possible will compete, as will grid development and reinforcement to export surplus electricity to other regions.
Electricity surpluses are not intentional and there are financial incentives to eradicate them; electricity generators are not in the business of providing free electricity. When surpluses reduce, prices rise, and the electricity is no longer cheap.
Power-to-gas implies a deliberate strategy of surplus creation. This is not impossible, but few countries have 100% renewable targets for electricity generation by 2050, let alone the 100% plus which would be needed to meet power demand and also making inroads into heat and transport via hydrogen production.
As hydrogen production is scaled up, there may even be water use implications. PEM electrolysers require much higher water purity than alkaline electrolysers, but in neither is the water recoverable. Water is abundant, but potable water much less so with increasingly large parts of the world suffering from water stress.
Leveraging the benefits
A Japanese study on hydrogen production published in February suggested solar photovoltaics in combination with a battery assisted electrolyser could produce hydrogen in a range of $1.92-$3.00/kg, the lower end being below the US Department of Energy’s target of reducing the levelized cost of hydrogen production to $2.30/kg by 2020.
However, this is only theoretical at present based on future technological advancement. Also, the problem of scale remains, given that solar, despite expanding rapidly, is struggling to make a big dent in the electricity mix because of its low capacity factor.
This is not to undermine the benefits of hydrogen. Its attractions are many. It is easy to distribute up to certain limits with existing infrastructure. It can be produced at any point on an electricity grid, as well as acting as a means of storage for off-grid locations, where renewable energy sources are available. It has the potential to play a key role in the decarbonisation of heat, an area in which progress lags behind the power sector and where the technological options appear much more limited. In transport, fuel cell vehicles eradicate emissions at the point of use.
These advantages suggest that the technologies required to develop a hydrogen economy will continue to attract research and development in an attempt to reduce costs. But this will take time. It also suggests that in rolling out the hydrogen economy, hydrogen use will grow quicker than the ability to produce fully decarbonised hydrogen.
The fallback position is to steam reform natural gas, a process which produces carbon dioxide and one that is likely to remain cheaper than other means of hydrogen production well into the 2030s, suggesting steam reformation will prove much more than a transitional arrangement.
The hydrogen economy is likely to evolve based on natural gas and LNG in the first instance. This will deliver the benefit of single, large site rather than small, multiple-point carbon dioxide emissions, facilitating capture and storage.
The deep decarbonisation required by the targets promulgated by the EU for 2050 require an ‘all of the above’ strategy in which hydrogen cannot be ignored. Even in areas like shipping, deep decarbonisation targets to hit 2050 targets set by the International Maritime Organisation assume growth in hydrogen as a shipping fuel post-2030 – yet another call on the nascent industry.
Steam reforming natural gas can provide the volume of hydrogen production required to develop and deploy hydrogen’s end-use applications. However, it also means that Carbon Capture and Storage (CCS) becomes a critical enabling technology for the hydrogen economy, making real environmentalists’ fears not that CCS locks fossil fuels into the system long term, but that the pursuit of the hydrogen economy does - a situation in which CCS could not be allowed to fail.