Utility Week

UTILITY WEEK | OCTOBER 2021 | 31 Customers an interim target of 60 per cent of regional demand to be restored within 24 hours. Participants in the virtual discussion were highly supportive of the project, pointing out the need to be prepared for the worst. "You can't pretend it wouldn't happen, and if it were to, we're not readily supported by neighbours, compared to a country like Italy. Interconnectors wouldn't work at that level. All the UK's coal-€ red power stations will have closed by 2024, yet by then our elec- tricity dependence will have increased by the uptake of EVs [electric vehicles]. So the motivation for the project is brilliant," com- mented one. "If we do get movement in the jet stream it is feasible that there is a period of calm conditions across the UK and this will cre- ate a lack of energy feeding into the system," said another, pointing to the recent events that have seen wind turbines becalmed and gas prices rocket as a potential taster for emergent problems. "So, there should be a lot of learning from this project, which may be applicable in other circumstances, not necessarily just a total or large area blackout." DER and dispatching power While there was agreement around the screen for the development of a distributed restart solution, there were concerns around technical capabilities and communication protocols. Some participants questioned whether communication protocols could be put in place to guarantee rapid dispatch given distributed assets are not generally geared up for this purpose and since some use communications infrastructure operated from outside the UK. When using DER it makes more opera- tional sense for smaller networks to operate as close as possible to where the demand is. Thus enabling power islands with dedicated communications arrangements becomes important, explained a guest. Reducing risk requires better local intelligence on the devices, including an ability to understand the potential state of the network and how they must respond. Chandler said that the ESO control room had 24/7 communication with transmission- connected generation assets. "But it is still an issue for distributed ReStarts so we're looking at ways we can mitigate that." "For anchor generation sites, where the generation will provide a voltage reference for other resources to latch on to, we're look- ing at those anchor generator sites being manned to 24/7. "For other resources, the ones that would latch on to our anchor to help expand the island, we're looking at those to provide a data resilient communication channel to enable that sort of linkage. "We're hoping to codify a lot of these requirements through modi€ cations to vari- ous codes, like the distribution code," he explained. As well as communications, there were a number of engineering challenges to be overcome, including persistent protection schemes and the need to provide a source of local earthing, which require network infra- structure reinforcements to make a power island approach to system restoration work. Learning from previous mistakes An issue of frustration for some of those taking part was that previous outages had — agged up that the codes in place are not always adhered to when crisis hits. "Looking back at the August 9th event we found a lot of generation on the distribution network and the transmission network did not operate as it should have done," said one. "Where we do have generation connected to the distribution network forming part of a recovery system, my plea is that it meets the compliance requirements of the standards as they are at the time of connection. "What we don't want is to have disrupted generation sources feeding back up to the grid, or arranged as island communities to support key customers, only to € nd that they don't actually work as they're supposed to." Putting a value on restoration Funding for high impact, low probability risk remains a thorny issue and there was debate as to whether Ofgem's evaluation method- ology properly considered today's inter- dependency of our infrastructure systems. "Can you really get there by doing a cost-bene€ t analysis or have you got to just have a precautionary principle that says this would be so unthinkable that we have to deal with it and make sure we have a way of dealing with it?" was the question posed by one›expert. It was felt that the methodology and € gures used no longer re— ected how the impact of lost load varied between diœ er- ent customers or how the value of lost load changed over time. "If you're oœ for 30 min- utes then it may not matter but if you're oœ for two days it's maybe more than 48 times as bad because of everything else that will be aœ ected. If Ofgem wanted to use a cost- bene€ t analysis approach then they have to have the right inputs to feed into it," our par- ticipant concluded. Denise Chevin, freelance journalist in association with What next for Distributed ReStart? Participants were asked what one development they would like to see in the next 6-12 months to boost con dence in the concept of distrib- uted restorations services. "National Grid ESO to get Distributed Restart to the point at which commercial launch is possible. That's where confi dence and investment will come from." "An operational control layer enabled by enhanced communications." "What the DNO role is likely to be and how they can evolve that for wider benefi ts in their own system." "Development of fi t- for-purpose market models." "DNOs to develop and demonstrate capabilities for safe, stable islanded operation." "Perhaps identifying the wider benefi ts that might accrue - even if a black start never happens."

• Cover