Whilst the public debate around renewables is often centred on what happens when there’s too little wind and sunshine to meet demand, a more immediate concern for the ESO right now is what to do when there’s too much.
Replacing fossil fuels is about more than just megawatts. Among other things, conventional thermal generators also impart inertia on the power grid. Their large spinning turbines act like shock absorbers, dampening swings in frequency and giving the ESO time to respond.
Wind and solar generators provide no such inertia, which must instead be replaced or replicated. In its absence, the grid would be twitchy and prone to blackouts of the kind seen in August last year.
National Grid has long expected this issue to emerge over the summer when demand is low and solar output is high. But the recent lockdown and resulting drop in demand has meant the ESO is now facing it much sooner than it had anticipated.
It might only be May, but analysis by Cornwall Insight suggests inertia has already dropped significantly in 2020, spending much of the year so far below 150GVAs – a level which would normally be considered very low.
“Covid-19 demand changes and reductions have brought about lower levels of inertia on the system sooner than previously forecast,” said analyst Joe Camish. “As a result of the demand changes, more expensive coal and gas plants are being pushed out of merit and renewables penetration is consequently rising substantially as a proportion of demand.
“The problems of falling levels of inertia are not new or solely related to Covid-19. Instead, this is an acceleration of something that was already on the horizon.”
Estimated inertia
Source: Cornwall Insight
For the time being, there is no replacement for the inertia provided by fossil fuel generators – at least not enough of it. And so, the ESO has been forced to make room for them – turning down other generators and reversing interconnector flows.
In preparation for a period of especially low demand on the transmission network over the bank holiday weekend, National Grid recently undertook a series of measures to ensure it has enough space. It launched a new downward flexibility service, effectively resurrecting the demand turn-up service that was shelved in 2018 due to low uptake; signed an agreement with EDF to limit output from the Sizewell B nuclear plant; and affirmed its authority to disconnect distributed generators as a last resort.
“Demand at the weekend, without our actions, would have been pretty close to what is was at Easter,” said ESO head of networks Julian Leslie. In the end, it turned out at slightly more than 15GW. With warmer weather still to come, the ESO expects demand on the transmission network to regularly fall below this level over the summer, “even if the relaxation of the lockdown does cause a bit of a pick-up”.
Speaking to Utility Week, Leslie said the agreement with EDF and the 3GW of downward flexibility it is procuring should enable National Grid to cope with demand as low as 12GW.
The ESO utilised around 300MW of downward flexibility on Sunday morning. Leslie said it was probably mostly wind: “That’s why the demand for us was looking so low – because wind was picking up, which we see as a reduction in demand. We went from a very warm and calm Saturday to a cool and breezy Sunday and that was happening through the night.”
“Considering, normally we’d spend a year or more bringing in a new service and this was less than 10 days, it all worked really well,” he added. “The DNOs knew what was happening. The generators knew what was happening, and we were able to dispatch.”
Leslie said the ESO’s effort to replace or replicate inertia from conventional generators should make this unnecessary once the pandemic is over: “I think as we move to 2025 and our zero-carbon system operation ambitions, then we won’t have the same need as we do today, because we’ll have found other ways of getting inertia and frequency response on the system that doesn’t require us synchronising conventional gas-fired power plants.”
However, the ESO will still require downward flexibility in the future to keep the system in balance as embedded and domestic generation continues to grow. Leslie hopes the launch of the new service will help pave the way: “I think it will change a lot of the mindsets of some of these smaller embedded generators that actually there is a national market that they could and should play in.”
National Grid was assisted in its efforts by Octopus Energy which ran a series of ad hoc trials over the weekend to boost demand by offering its customers low or even negative prices.
“Our Agile tariff itself automatically adjusts to times of low and high demand and potential imbalance on the grid,” said chief executive Greg Jackson, “and so our customer base naturally has a chunk of people whose price varies according to what’s happening on the grid and there’s a strong reaction to that.”
“In addition, this weekend we ran a series of trials with test groups and control groups to study a variety of other ways of using price to incentive customers to change demand. And the early indications are that it was very effective but we’re still running the analysis so we can’t quantify it yet.”
The trials included a cross section of customers and not just those on Octopus’ Agile tariff: “Some customers got one offer, others got another and some got none. We were able to start doing some really statistically meaningful trials of the extent to which we can use a combination of smart meters, dynamic pricing, customer messaging and data science to have a positive impact on how the grid manages with, for example, very high renewables.”
Jackson said the trials were launched at very short notice: “This ability to take cohorts of customers, even those who are traditionally seen as being non-engaged and enable them to play a role in balancing the system – it’s really exciting… The whole of the communications plan, the flexible pricing, the data analysis and so on was all done in less than a week.”
“It’s kind of bonkers that when we’ve got high renewables, we end up turning generation off. Instead, encourage people to use the most of those green electrons,” he remarked. “That way, it’s better for generators, better for the grid and better for customers and far more importantly than anything else, it’s better for net zero.”
Leslie said the ESO is also analysing their impact but the trials appear to have had a noticeable effect on demand.
On the Thursday before the bank holiday, Ofgem approved an urgent modification to the Grid Code to enable to the ESO to instruct distribution network operators (DNOs) to disconnect generators on their networks as a last resort.
Leslie said the amendment was merely introduced as a precaution. They were “nowhere near” having to issue an instruction over the weekend and if all goes to plan, they shouldn’t need to over the summer.
He also stressed that is not a new power: “The Grid Code mod wasn’t changing anything that we didn’t have the right to do anyway. It’s providing legal clarification, predominantly for the DNOs, that if they were to take action there would be no recourse from the embedded generators.”
In approving the modification, Ofgem criticised the ESO and DNOs for failing to address this issue sooner, stating: “This urgent modification shows that no timely review was undertaken prior to this summer, which is particularly concerning given that summer minimum demand has been falling for some years, increasing the need for robust emergency controls.”
Leslie believes this criticism is unfair given the unique circumstances in which they are operating: “If we were unable to predict that we were going to have a global pandemic three months ago and that therefore we needed to get all of our ducks in a row to prepare for low demand, then yeah, absolutely, we should have spotted it sooner.”
But, he added: “We’ve been looking at forecasting across the summer; looking at what are the worst case scenarios and what tools and techniques we need in our toolkit, and in doing so, saying to the DNOs: ‘We’re going to have to have access to embedded generation to meet these very low demands.’
“It’s only through those conversations that some of the DNOs flagged up that, although they agreed that the Grid Code gave us the right to give them the instruction to disconnect embedded generation, some of them were just uncomfortable that it wasn’t as clear and as black and white as they would have liked the code to have been.”
He said the modification merely made clear that this authority applies to generation as well as demand, as was always assumed to be case.
Leslie said the ESO’s preparations for zero-carbon operation of the power grid are otherwise progressing well and have been largely unscathed by the lockdown.
In January, the ESO awarded its first ever contracts to buy inertia separately from generation as part of the trial of a new stability service. The relatively short lead time meant the tender was only really suitable for existing assets. Winners included the Cruachan pumped hydro facility in Scotland and the Killingholme and Deeside combined-cycle gas turbines.
The second tender is about to launch and will be more appropriate for purpose-built assets such as flywheels and synchronous compensators. “Then by the end of this year we’ll be doing phase three which is a nationwide product,” said Leslie.
He said the pandemic has in fact provided an opportunity to test their models and assumptions: “What this current period of grid operation is doing is giving us more confidence that the modelling – how we represent the system – and therefore the services and products we’re designing for the future are absolutely the rights ones – that these are needed by the system.”
Leslie said the only work which has been adversely affected is the Accelerated Loss of Mains Change programme, for which site visits are required.
The pandemic has also given a glimpse of a future devoid of coal – once the backbone of Britain’s electricity system. The latest coal-free run began on 10 April and has now been going for more than a month.
“From our perspective as the system operator, we don’t need to run the coal for any system services anymore,” Leslie remarked. “It’s a change from last summer, because last summer we had some of the coal-fired plants providing black start services.”
“We’ve worked very hard to find new providers of black start. It allows not to keep a coal-fired power plant warm in case of a black start situation and that’s why you see this prolonged period with any coal on the system.
“As far as we’re concerned, we will not be dispatching coal out of merit, so the next time coal is going to run is when the market says it needs to run.”
We may well be witnessing the start of Britain’s first coal-free summer since the Victorian era.