HYDROGEN | SPECIAL REPORT
deficit” by the time Sizewell C is operating in the 2040s and it expects that the Environment Agency will reduce its abstraction licence from the River Waveney to less than half its current level by that time. Sizewell C has another option to meet the power plant’s water requirements, which is to build a desalination plant so it can use seawater instead – an option that has already run into opposition. That makes abstracting more water for hydrogen production problematic. A commercial-sized electrolyser rated at more than 100 MW could double the site’s demand for fresh water.
Several other nuclear sites in GB are also in ‘water
stressed’ areas – typically those in the south and east of the country (see map). But the UK’s Climate Change Committee foresees those areas expanding in future unless there are substantial changes in water use. The IEA says using seawater is an alternative in coastal
areas, using reverse osmosis for desalination. The IEA quoted an electricity demand of up to 4 kWh per cubic meter of water and an increase in total hydrogen production costs of $0.01–0.02/kg H₂ if desalination is required. This is far from impossible on these grounds, but onshore desalination raises environmental questions in disposing of the brine produced alongside the desalinated water. The equation is different for producing hydrogen at
offshore wind sites and piping it onshore, as has been proposed elsewhere. There is no option of using local fresh water so desalination is required, but disposal of the brine offshore is less problematic.
Pipeline issues While water supplies have been a siting issue for nuclear plants in the past, and so has the potential for heat customers, nuclear developers have not needed to consider the availability of gas transport infrastructure in the past. That changes if nuclear power is to be used as a major hydrogen producer. Using nuclear heat to boost methane reforming requires
the site to have access to gas supplies for the long-term. Electrolysis of course does not require gas input. But both options require gas export infrastructure. Today, hydrogen is transported from the point of production to the point of use via pipeline and on the road in cryogenic liquid tanker trucks or gaseous tube trailers. Pipelines are deployed in regions with substantial demand (hundreds of tonnes per day) that is expected to remain stable for decades.
This means that hydrogen producers using the methane reforming route have to be sure that the gas assets they are using will have a methane supply in the long term – which excludes pipes that may be converted to transporting hydrogen. Effectively that places methane reformers close to methane import terminals. All this adds up to a more complex siting challenge
for new nuclear plants that see a future in producing hydrogen alongside (or instead of) power – and for different customers. Gas, water, hydrogen and heat requirements all have to be met at sites that also meet the extensive restrictions that are laid down for nuclear installations. In Great Britain a comparison of the existing gas network, industrial clusters and existing nuclear sites superficially shows some consistency. But zoom in and a more complex picture emerges. HyNET in the northwest is a hydrogen growth area with a variety of users. It is also well served by the gas network, in an area where repurposing it for hydrogen transport is under consideration. But the nearest existing nuclear site is Heysham, around 60 miles away with large urban centres such as Liverpool in between. Some of these tensions will be reduced by using new
nuclear options. Smaller reactors will have smaller water footprints. But they also produce less hydrogen and smaller volumes in turn limit hydrogen transport options, as there is a point at which pipelines become uneconomic. Local hydrogen consumers will be required, along with a way to manage an intermittent hydrogen supply, if the ‘local’ reactor has other electricity customers. Other sites such as those on the south or east coast are much further away from both resources and consumers. The UK’s current nuclear planning framework largely
restricts new nuclear to existing sites. In fact, the framework has lapsed and a new siting framework is expected. That could open up new sites, although the UK has previously found it difficult to expand its nuclear site pool beyond those already existing. None of these types of issues are new to electricity
asset managers. Combined heat and power projects, for example, routinely manage heat and electricity customers and may include a heat store to provide flexibility. The problem of limited water supplies is well known, at least to inland nuclear operators who rely on river water for cooling. But the uncertainties involved in the hydrogen option will nonetheless present new challenges to nuclear investors. ■
www.neimagazine.com | September 2022 | 43
Above left: Heysham is near the UK’s northwest hydrogen hub Hynet, but it’s still too far to transport heat
Above right: Sizewell is the site for a new nuclear power station already earmarked for possible hydrogen production Photo credit: Fotogenix/
Shutterstock.com
Page 1 |
Page 2 |
Page 3 |
Page 4 |
Page 5 |
Page 6 |
Page 7 |
Page 8 |
Page 9 |
Page 10 |
Page 11 |
Page 12 |
Page 13 |
Page 14 |
Page 15 |
Page 16 |
Page 17 |
Page 18 |
Page 19 |
Page 20 |
Page 21 |
Page 22 |
Page 23 |
Page 24 |
Page 25 |
Page 26 |
Page 27 |
Page 28 |
Page 29 |
Page 30 |
Page 31 |
Page 32 |
Page 33 |
Page 34 |
Page 35 |
Page 36 |
Page 37 |
Page 38 |
Page 39 |
Page 40 |
Page 41 |
Page 42 |
Page 43 |
Page 44 |
Page 45 |
Page 46 |
Page 47 |
Page 48 |
Page 49
