Restarting from the bottom

At the beginning of 2019, National Grid ESO, SP Energy Networks and TNEI launched a ‘world-first’ initiative to explore whether distributed generators, including renewables and storage, could be used to restart the power grid in the event of a nationwide blackout. With the project coming to an end last month, Utility Week speaks to some of those involved about what was achieved and what’s next.

All day, every day, National Grid’s control room engineers are working hard to avoid the nightmare scenario of a complete power grid shutdown. If the whole electricity system goes down, getting it restarted is not just a case of switching it back on.

The power grid must be rebuilt block by block, starting from a “power island” on an isolated part of the network. The seed of a power island is a generator that is able to self-start and has “grid-forming” capabilities, meaning it can establish its own independent source of voltage.

The restoration process has traditionally taken place from the top down, starting with large synchronous fossil fuel power plants connected to the transmission network.

During normal operation, these plants’ turbines spin in synchronisation with the frequency of the power grid, but when creating a power island they can also set this beat for others to follow. The physical inertia of their turbines also provides an inherent resistance to changes in frequency.

More than three years ago at the beginning of 2019, the Electricity System Operator (ESO) at National Grid, along with the distribution network operator (DNO) SP Energy Networks and the consultancy TNEI, launched an innovation project to see whether the restoration of the electricity system could instead be undertaken from the bottom up, starting with generators connected to distribution networks.

Simon Harrison, head of strategy at Mott McDonald, says the conventional process, previously known as “black start”, is “relatively straightforward” by comparison. “You had a few power stations that provided the service. There were very established routes involving quite small numbers of trained people to deploy that service when needed.”

He describes it as a “well-oiled machine, poised and ready to go in the event that it is ever necessary”.

By contrast, Distributed Restart, as the ESO’s innovation project was named, involves a large group of assets and people that haven’t previously provided such a service.

“The people involved need to be trained and available and the way in which the network needs to be built back up at the distribution level needs to be understood and rehearsed,” Harrison says.

The limited size of energy assets connected to distribution networks means power islands must be built up in smaller, more numerous, increments. The capabilities of the initial “anchor” generators used to seed these islands must be supplemented by “top-up” assets, which are likely to include asynchronous generators that do not inherently provide inertia.

The power islands they can initially form are smaller and less stable and so loads must be added in smaller blocks to keep frequency and voltage within required limits. The lower number of customers in these blocks and their reduced diversity means this demand is also more variable.

Harrison, who was one of three members of the independent advisory panel for the project, says one of the early findings was that “you could easily overwhelm distribution control room staff because of the sheer amount of assets and information involved”.

A key development was therefore the creation of Distribution Restoration Zone Controller (DRZC), which “takes quite a lot of the pain away from the control room”.

Jack Haynes, lead systems specialist at SP Energy Networks (SPEN), says this controller, comprising both hardware and software, “acts as the brain of the island”. In doing so, the controller “monitors all the resources it has at its disposal in the island like load banks, generators, batteries and dispatches them in an optimal way to make sure that the island is as resilient as possible so that it can react to things like instantaneous loss of demand or generation”, he explains.

“But it also does a bit of forecasting. It can not only react to sub-second events, but also think about, and forecast into, the future to try and keep the island as stable as possible.”

This includes, for example, ensuring that batteries are as near as possible to 50% charge so “you can have a buffer in either direction.”

“One of the other key things it can do is automate a lot of the functions that would usually be manual,” adds Haynes.

“You can imagine in a genuine black start scenario, the pressure on the control rooms across the UK is going to be inordinate. The more that we can automate for our control rooms and build the island up from software and from non-manned devices, the better it is for them.”

He says more work will need to be done before this tool can be applied to other networks around the country: “The power island in UKPN’s region is going to be very different to the power island that we have in SPEN’s.

“You need to essentially reprogramme the DRZC to cope with the assets that it would have at its disposal depending on the geographical location. But it’s much easier to just reprogramme the device as opposed to build it from scratch so I would argue that the hard work in that regard has already been done.”

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