By Dave Elliott
Guest posts by Energy Matters’ commentators Alex Terrell and Andy Dawson present two rival UK scenarios for 2050 with, respectively, high nuclear and high renewables. It’s an interesting exercise. They looked at DECC’s 2050 Pathways models, but say ‘it’s far from clear if the underlying models take adequate account of variations in demand’. So they developed their own demand projections.
Terrell and Dawson note that UK electricity demand can vary between 60 and at times 120 GW, with an average of 72GW. They say ‘providing a system that can produce an average of 72GW, but up to 121GW (averaged over the day) on the coldest days is not straightforward. A demand of over 120GW might occur one day every three to ten years, but it still needs to be dealt with, and in a way which minimises the capital expense of nuclear plant (or renewables), whilst minimising the use of fossil fuels’. Not easy even with some pumped hydro assumed.
For their 85GW nuclear scenario Terrell and Dawson note ‘we want to run nuclear at a high capacity factor, and avoid building more capacity than is required’. However, though ‘current nuclear power can be ramped down, it is not currently economic to do so to any great extent’. So there’s a problem: ‘a major incompatibility between the concept of an all-nuclear grid and the ability to supply the more extreme ends of the probability distribution for demand’. However, they say ‘the effects of this are not as severe as might immediately be assumed; carbon output is not particularly time-sensitive in that our key parameter is annual output, and hence short periods of what might appear to be high levels of fossil fuel output have little effect’. But new technology might help: ‘there may be future developments that could allow increased flexibility’.
Not all of the examples given are convincing. Terrell and Dawson say that Generation III reactors such as the EPR can be ramped down to 60% of nominal output, and claim that ‘in theory, doing so could extend the life of the reactor’. Well maybe, since it runs less overall, but regular fast cycling also introduces more thermal stresses and more risks associated with radioactive xenon gas production. And, as they admit, ramping down regularly also undermines the plant’s economics – EPRs, like most reactors, ideally need to run flat out to recoup their high capital costs. It’s certainly not proposed currently for the Hinkley EPR. However, they say that next generation ‘molten salt reactors may have a much lower capital cost, and could therefore economically be turned down or off’. That’s far from proven: it’s all at the concept stage at present. But they say that ‘designs based on graphite moderators (e.g. ThorCon, Terrestrial) have cores that are swapped out after a certain number of years. Reducing the power of these reactors will extend the core life and reduce the need for core swaps, making this solution more economic’. And they go on to suggest that ‘Molten salt reactors will produce heat at a high enough temperature for steam methane reforming. The resultant CO2 could then be stored, and the hydrogen used to supply energy in the winter (either for direct heating, or by electricity generation in gas turbines or fuel cells).’
Moreover, Terrell and Dawson suggest that some High Temperature reactors, such as the pebble bed design being built in China, ‘may be able to switch from the production of electricity to the thermal production of hydrogen from water, whenever demand is low’. However, they note that in both cases, ‘spare capacity would be in the summer, and demand for hydrogen will be highest in winter, and storing large quantities of hydrogen is not straightforward’. Then again they say that ‘High Temperature reactors, including molten salt reactors, can store energy in the form of hot salts’ and note that the developers of the Moltex Reactor have proposed storing ‘several hours’ worth of thermal output’, with the plants varying their electrical output meantime.
It’s all very intriguing, if speculative, mirroring the variable use of gas-fired Combined Heat and Power plants and the use of heat stores charged by surplus wind and solar power – something that’s already done in Denmark and elsewhere for balancing variable renewables and variable demand. However, given the uncertainty of these as yet unproven nuclear technologies and nuclear CHP, in their nuclear scenario Terrell and Dawson rely initially on conventional nuclear plants (PWRs and BWRs) although some Small Modular Reactors (SMRs) are introduced after ~2025, and other types may be later. A 3GW/year build programme is envisaged, mostly on existing nuclear sites, much expanded. But not probably in Scotland! Some new SMRs might be put on old coal plant sites. But even so they note there could be a 20GW site shortfall. So they look to the idea of siting some on artificial islands 12-20 km offshore in shallow waters. Bold stuff!
By contrast their 2050 renewables scenario is quite conservative, with pessimistic views on the role of P2G/hydrogen production and storage for balancing (too costly/inefficient) and no mention of supergrid balancing options. So, with 280GW of onshore wind (or 200GW if offshore) and 100GW of PV, there is a lot of wasteful curtailment of surpluses and a need for 104GW of gas backup! Evidently, by contrast, the surplus output from inflexible nuclear in the nuclear scenario is not a problem!
Some storage is used in the renewables scenario, with 50 Dinorwick-type pumped hydro schemes and some batteries including, possibly, grid-linked electric car batteries, but it is claimed that ‘adding realistic amounts of extra storage reduces the amount of gas that needs to be burnt, but makes no difference to the gas capacity required.’ Similarly, ‘adding tidal flow and tidal lagoons in place of wind to the mix results in only a limited reduction in gas usage, and should only be done if it is cheaper than wind power’. Vehicle to Grid EV battery links are seen as unlikely to be popular, while ‘converting surplus electricity to hydrogen and back again presents problems of storage and capital equipment’. Although ‘converting surplus electricity to synthetic hydrocarbons could provide a route to a low carbon supply’, it would require ‘development of carbon capture technologies and significant capital expenditure’.
These conclusions seem to reflect pessimistic views about how technology and costs may change. There are some impressive hydrogen conversion/syngas projects being planned and some are in use in Germany, while smart grid systems can cut energy costs by shifting demand from peak times. On the supply side, tidal technology is developing rapidly and costs should fall. That has already happened with PV and wind, and offshore wind capacity factors are much higher than the 27.5% wind utilization factor used in this study. 40% or more has already been achieved, and Bloomberg New Energy Finance predict that over 50% will soon be possible in UK waters. So 27.5% by 2050 is a bit conservative. As is the whole approach to renewables – for example, with higher capacity factors, less renewable capacity would be needed to meet average demand, so oversupply/curtailment would also be less.
Even so, overall, despite being ‘worst case’ in many of its assumptions, it is an interesting exercise, as is the nuclear study. Although some greens might want more energy saving and demand management, there is some demand reduction (under cold weather, high demand conditions) built into the basic model, and both scenarios meet demand around the year. Both scenarios also meet the carbon reduction targets set.
There were no overall costings offered for either scenario, although a new post has now attempted some. However, as with the rest of this exercise, it seems very optimistic about new nuclear technology and pessimistic about new green energy systems, which may limit its usefulness. For example, its estimates for balancing costs for renewables (36% extra) look very high. That pushes the renewables scenario costs up to more than for the nuclear scenario. I’ll be looking at the balancing cost issue in my next post.