09/08/2019 16:52:34.600. Those digits won’t mean a lot outside of energy circles, but they’re likely to be etched into the UK industry’s folklore. Just after 16:52 on Friday 9 August 2019, the UK’s power system – one of the most secure in the world – tripped, causing power outages felt by more than 1 million customers.
While National Grid’s interim report, to be published tomorrow (20 August 2019), is to provide more technical detail, what we know is that RWE’s 727MW Little Barford CCGT plant tripped, causing grid frequency to fall sharply – inside four seconds – to 49.1Hz. How the loss of ~700MW of generation – well within National Grid’s level of preparedness – caused such a drop, and a lack of system inertia’s role in that, is a matter for another time.
That sizeable collapse prompted National Grid to call on its frequency response assets, as shown in the graph below, provided by Limejump.
But as the system responded, Orsted’s Hornsea offshore wind farm tripped as well. The relationship between those trips, and the rumoured role of lightning striking grid infrastructure nearby, will also likely feature in tomorrow’s report.
The combined effort of losing both ~700MW from Little Barford and around 800MW from Hornsea was, however, simply too much for the system operator to withstand. At present, National Grid holds reserves enough to offset a failure at its largest single generator – the 1.2GW Sizewell B reactor – but at 1.5GW, the combined outage sent system frequency down to 48.8Hz.
It’s this second, subsequent drop in frequency which triggered distribution network operators into action, who turned to their Low Frequency Demand Disconnection (LFDD) protocols to shed demand loads in order to stabilise the grid and prevent a more catastrophic error. The lights went out in some places, but the entire system itself was saved.
Batteries to the rescue
It took just two minutes and 22 seconds for that combination of load shedding and frequency response – a not inconsiderable amount provided by batteries – to restore the frequency to safe levels, four-time faster than the last time such an incident occurred in 2008. Within four minutes – 3:47 to be precise – grid frequency had been restored to its usual operating limits, significantly quicker than the 11 minutes it took a decade ago.
Indeed, the lightning-quick (no pun intended) response is evident when analysing the response times of domestic batteries that were in-play that afternoon. Social Energy, an aggregator of domestic batteries, said that its fleet all detected the incident within 200 milliseconds of it occurring; between 16:52:34.600 (shown in red) and 16:52:34.800 (shown in green).
“One of [our] advantages is that we have a large number of relatively small batteries that are distributed all over the country, and particularly around population (and demand) centres. So even if some of our capacity is taken offline due to DNOs being instructed to disconnect demand, as was the case on 9 August, the remainder of the fleet can continue to help balance the rest of the grid,” the company’s chief executive Ryan Gill said.
The incident was made all the more interesting from an operational perspective when LFDD protocols kicked in. National Grid had already instructed flexible assets to discharge in a bid to make up for the lost capacity, but the moment DNOs started shedding load, National Grid quickly felt a bounce in the frequency and battery instructions were just as quickly instructed to respond. “When National Grid cut off the power, the frequency bounced back very quickly, sending the system the other way and meaning our battery sites where then called on to balance the grid by taking power out,” Anesco asset management director Mike Ryan said last week.
Within four minutes, the UK’s electricity system – widely regarded as one of the most secure in the world – tripped, recovered and was restored to within safe operational limits. Batteries played a pivotal role, but the fact the system tripped altogether has been an event contentious enough to trigger two separate official investigations.
Could more batteries have been used to greater effect?
Lessons to be learned
Limejump chief executive Erik Nygard has called for a significant increase in firm frequency response (FFR) styled products which can procure the kind of fast-acting response necessary to offset such sharp drops in grid frequency.
National Grid’s 200MW-strong portfolio of enhanced frequency response (EFR) batteries, which respond to frequency events in 0.5 seconds, have indeed helped the system operator’s response, but a drop off in the rate of FFR procurement in 2017 has meant that fewer batteries and less DSR – the kind of non-synchronous generation that’s vital during periods of low inertia – are being supported.
Nygard says that National Grid could effectively double its FFR-ready fleet, possibly mitigating for circumstances like Friday 9 August, at a cost of around £100 million per year.
Jonathan Ainley, head of public affairs and UK programme manager at KiWi Power, meanwhile, has said that National Grid must do more to open up the Balancing Mechanism (BM) to more significant quantities of distributed generation, arguing that it is currently “dominated” by large-scale, centralised generators of a dirtier heritage.
While it’s true that National Grid’s distributed energy resource (DER) desk has led to a boon in the DER capacity bidding into such markets, some rather sizeable barriers to entry remain, chiefly the need for an energy supply licence which is a particularly prohibitive obstacle for smaller companies.
“With the right markets, flexibility providers can rapidly bring forward fast-acting, flexible capacity to help National Grid avoid a repeat of last week and create a smarter, cleaner, more resilient energy system for everyone,” Ainley said.
Meanwhile, there’s also the not-insignificant problem created by inertia, or indeed the lack of it. Friday 9 August witnessed considerable wind generation and, having produced as much as 50% earlier in the day, the UK’s wind fleet was providing around 33% at the time of the frequency event. As a result, the amount of inertia on the system is expected to have been low.
Inertia’s role on the system and whether or not it had much of an impact on the events of that day have appeared to divide opinion in the energy sector so far, and will inevitably be a line of inquiry in both Ofgem and the BEIS’ investigations. Nygard says the UK would do well to create a system which produced more inertia as non-synchronous generation grows, either by adding more batteries and DSR or synthetically by forcing such generators to do so via their inverters.
Tinkering with the energy market itself may also elicit a response. Given the entire incident took just under 4 minutes from trip to recovery, energy markets – which trade in 30-minute settlement periods – were all but unaware of what was happening and unless they were actively looking, traders would have been none the wiser.
Bringing those markets to settle more frequently – a technical challenge, but not an impossibility – may have allowed price signals to act as the first canary down the mine so to speak, and the market could have responded in kind.
Whatever tomorrow’s interim report contains, it will likely be three more months of internal deliberation before official findings, recommendations and a meaningful timeline for any concrete changes to the system are to be unveiled.
What is already abundantly clear, however, is that flexible assets are already playing a crucial role in balancing the system, a role which only looks set to grow – if the market allows for it.