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Grid balancing ‘needs extra firm capacity’

By Dave Elliott

Even ‘very significant’ storage, demand-side measures and interconnection would not be sufficient to cope with intermittency in a weather-dependent renewables-based electricity system, according to modeling, up to 2030, by the Energy Research Partnership (ERP). It says there would still be a need to have a significant amount of zero-carbon firm capacity on the system too – for dark, windless periods. It could, for example, be supplied by nuclear, biomass or fossil fuel plants with Carbon Capture and Storage (CCS).

It is a pretty damning report as far as renewables are concerned. It says it would be counterproductive just to add more wind capacity, rather than use CCS or nuclear plants, since that displaces “progressively lower carbon plant eventually causing significant levels of curtailment of its own output or that of other zero carbon plant”. While that may be true, you could also say the same for adding extra inflexible nuclear plant – it would potentially force variable wind off the grid. Power-to-Gas conversion and storage of this surplus energy might be a better idea than curtailment.

However the ERP worries about the turn-around efficiency of Power to Gas and also says that the scope for batteries, pumped hydro and compressed air storage in salt caverns is limited. And even if massively expanded, to 30 GW or more, storage would not be sufficient to meet the 8 TWh supply gap produced in the modeling at peak demand times when wind was low for long periods. Demand management might help short-term (up to 24 hours), by shifting peaks but the 8 TWh gap is not going to be solved through DSM [demand side management] as it represents an average reduction of 15 GW for 3 weeks. There is little domestic activity that can be delayed that long and the reduction needed exceeds average industrial demand”. Overall then, while they may help for short-term balancing (over hours and days), neither storage nor DSM seem to be credible solutions to the security of supply issue caused by lulls in renewable output lasting 2-3 weeks”.

The ERP does say that “Interconnectors could benefit the GB system by connecting it to markets with different weather influences and so take excess generation at times of GB surplus and return carbon-free generation at times of low renewable output”. However it notes that “these interconnected markets would not always be in the right state to do this – for instance when similar weather was being experienced in the neighbouring markets that had installed similar renewable energy technologies. So in effect they would act like storage with an availability that was significantly lower than a physical asset”.

The only exception, according to ERP, might be for an interconnection to a market such as NordPool, with Norway having ~28 GW of hydro. About 17 GW of this is controllable reservoir with a total storage capacity of 84 TWh. ERP says that “a further 5-7 GW could be built without too large of an environmental impact. In theory then 20+ GW of the UK’s storage needs could come from Norway, and the 8 TWh needed to fill the low wind gaps could probably be accommodated. In practice though, the UK may find other EU nations also wanting to use NordPool’s balancing capabilities and some, unlike the UK, are already connected”. The ERP concludes that, although expensive, “interconnection can help, especially to NordPool, but is unlikely to provide a complete solution as other markets compete for the same resources”.

Leaving that aside, ERP insists that with the diminishing returns of adding more variable renewables, and the need to cover 2-3 week periods of low renewable output, a complete decarbonisation is going to need a significant amount of firm low-carbon capacity, and it looks at what might work, longer term. Adding more nuclear (30 GW in one scenario) is seen as always beneficial, since it is portrayed as zero carbon. That is not quite true (there are carbon debts from producing the fuel) and, as the ERP admits, it is hard to assess total system impacts from any specific additions since there are complex interactions, which will change the overall system’s operational costs. Certainly adding nuclear will increase wind curtailment.

Reasonably enough, the ERP says “When assessing the economic effect of a technology it is essential to do so in the context of the system to which it is being offered”. For example, “the benefit of adding a technology is dependent on the existing generation mix on the system, in particular the amount of that technology already installed”. In terms of costs, the ERP notes that “using DECC’s cost estimates, the differences in economic value to the system between the key options examined (nuclear, gas-CCS and onshore wind) are much smaller than the margin of error estimating those costs. Therefore it’s difficult to claim any one of these is the optimal solution to progress grid decarbonisation. Furthermore the value to the system is highly dependent on the technology mix on the system, and the effect of diminishing returns reduces the value of all technologies as they are added, but especially so of variable renewables which generate an increasing proportion at times of surplus energy”. So the ERP says that “using a fixed number (like LCOE [levelized cost of electricity]) to characterise a technology’s economic value is quite unhelpful in these circumstances”. Fair enough: a holistic system-wide approach is needed.

However, looking to other countries for comparisons is not seen as helpful. For example, the ERP looks at Germany, which now has 70 GW of variable renewables. While “at first sight it might be thought that Germany is already tackling issues associated with intermittency that the GB system will have to face if the UK also aims for significant production from renewables”, it says “closer examination shows us that Germany is not in the same position”. Although Germany is “the world leader in the installation of weather-dependent renewables” with, in 2014, these technologies accounting for 42% of capacity, “it has still not experienced a level of production that exceeds demand”. In fact “on the hour of maximum wind + PV output half of production still came from conventional sources” and “in 2014 just 16% of electricity came from wind and solar, well short of the production needed in a high renewables scenario for the GB system”.

Actually, the figure for all renewables in Germany, hydro and biomass included, is now over 30% (34% in the first half of 2015), which is about what the UK is aiming for by 2020, and ERP’s description of the export pattern also seems dated. It claims that, “much of the renewables production (typically half) is exported to its neighbours rather than displacing the highly emitting lignite plant”. Even if it was the case once (and there are rival interpretations arguing that it has been cheap power from coal that has been exported), that is now changing, with lignite plants being mothballed (see my last post). It is still the case that the remaining nuclear, coal and gas plants provide some baseload, but Germany is developing more pumped storage, Power to Gas, CHP and demand management systems to aid grid balancing. As ERP says, it also has the advantage of being embedded in the wider EU power system, so it can balance its grid using imports and exports.

In time, so could the UK. However, the ERP report seems surprisingly dismissive of the German system as an exemplar, perhaps since Germany aims to do without nuclear, whereas that is seen as vital (by some) in the UK. So although there are some excellent insights in this report, it does still seem to be based on the belief that there could be a role for inflexible nuclear plants, although it softens that with a brief mention of mini (small modular) nuclear plants. Seems a long shot… If they really are needed, gas plants would arguably be better. Although we may not need that many. What the ERP report does tell us is that, whereas some say we will need 100% fossil backup for variable renewables, given storage, DSM, supergrid imports then, even with a “100% renewables” scenario, based on wind and PV meeting most of the demand most of the time, we might only need to have a 12% input from fossil plants to balance the grid during periods of extended low renewable input. And that’s ignoring possible inputs from other less variable renewables.


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