THE HYDROGEN OPTION | BUSINESS DEVELOPMENT


biofuels, high-temperature heating in industry, transport and more. For some of these industries, such as steel processing, baseload supplies are needed for commercial reasons, to ensure high load factors and keep breakdown risks low. The Hydrogen Council, a global grouping of 141 companies


with interests in the sector, believes demand for hydrogen by 2050 will reach 660Mt per year. Currently, there are two main ways to produce ‘low


emission hydrogen’ that are being scaled up. (A third, thermochemical water splitting, using high temperatures and chemical reactions to produce hydrogen and oxygen from water, has opportunities to use heat from nuclear but is less of a development focus). Of the two options being scaled up, one is based on the


most common existing process – steam methane reforming – but with the addition of carbon capture and storage; the other uses low carbon electricity to electrolyse water into hydrogen and oxygen. Is this where nuclear can make its mark? Does it have a business case that can compete with the other options? Chris Harris, a long-standing member of the UK energy utility sector who is now at the University of Bath, says the case for hydrogen is made by its use in industrial process, in transport (direct or as vector) and as storage, replacing methane. He has examined the consequences of some hydrogen production models and the capital and operating regimes, and considered whether and how nuclear can become a major player in the industry.


Steam methane reforming As noted above, the current method of hydrogen production is steam reforming of methane. This is an energy intensive process – around a third of the gas used is consumed in providing heat to the process – and one that produces carbon dioxide. Additional processes have to be incorporated that capture the carbon dioxide emitted (generally by absorption into a chemical substrate) and transport it (by pipe or other means) to a permanent storage site (such as injecting into closed offshore oil and gas reservoirs). This option is attractive to policymakers because of the effect of clustering: industry has tended to locate along estuaries where it has access to water and transport options. How does nuclear compare as an option for producing


hydrogen? Nuclear and fossil carbon capture and storage (CCS) generation share economic characteristics that drive them to baseload operation, such as the need to recover capital costs by high load factor operation. Both are large- scale centralised facilities, and are likely to have a long lead time before permits are in place and construction – which in itself may take two decades – can begin. The process of methane reforming with CCS may have an edge on nuclear. The first reason is that steam methane reforming is already in operation and it may be possible – if economic – to retrofit CCS to existing plants. The reforming technology is proven. The second reason is that the methane/CCS option does


not require an electricity network connection. It is possible that a nuclear plant could be entirely focused on providing hydrogen – but it will not have industrial customers for the hydrogen until it is up and running. Industry has to be local to the plant to use the hydrogen, but will not invest, or sign contracts for hydrogen supply ahead of plant operation


(although as the plant completes construction they may be ready for ‘in principle’ agreements). That contrasts with nuclear’s history in the electricity sector: investors in nuclear, as in other power generating plant, know it will have permanent and open access to a customer base via the electricity network. Until a nuclear plant intended to provide hydrogen has


secured customers, it will require the option of electricity supply and it will have to invest in the physical and contractual arrangements that allow it to do so – as well as the infrastructure required to supply hydrogen to nearby customers. Once the plant is in operation, electricity contracts can be unwound or lapse as new contracts to supply hydrogen go into effect.


The ‘back end’ of the various cycles also have to be


considered in comparing the methane/CCS and nuclear options. The core question is how much the cost of disposal is taken into account (carbon dioxide for fossil and spent fuel and decommissioning for nuclear). Current CCS technologies are limited because they do not capture all the carbon produced. That means CCS at 90% capture is a not a long term solution, as there are not enough sequestration resources to deal with the residual 10%. Potential technologies such as oxyfuel are more efficient at capturing carbon dioxide – up to around 95% capture may be achievable long term – and may be a long term solution but it still requires a positive benefit to outweigh the cost of managing residual carbon dioxide emissions.


Harris suggests the best option is to run nuclear flat out and spill non-used hydrogen into storage caverns. The storage supplies flexibility as well as energy security. They are highly valuable to the electricity system and to industrial users, respectively. But this involves the cost of storing hydrogen. Ideally, the nuclear plant and cavern will be very close to each other to minimise pipework. This does add another siting requirement to the hydrogen-fuelled industrial cluster though. Alternatively there are numerous non-cavern ways to


store hydrogen. That may involve low temperatures (below 20K) or high pressure. There are also chemical options, such as hydrogen adsorbed on a substrate possibly combined with low temperatures, which include metal organic,


www.neimagazine.com | WNE Special Edition | 9


Above: The Carbon Engineering Direct Air Capture (DAC) carbon capture plant in Canada


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