The evolution of the UK’s energy system to become decentralised, decarbonised and digitalised is well under way. Some 99.3TWh of electricity was generated by renewables in 2017 compared with 21.6TWh in 2008. Meanwhile, consumers are not just users of energy but can now generate, store and even sell it back to the grid. The growth of electric vehicles is poised to take this trend even further.
However, the grid is not yet fully capable of handling the new reality of electricity flowing in different directions from a large number of smaller, intermittent generators. Without radical changes, costly upgrades to energy network infrastructure will be necessary – a report by the Carbon Trust and Imperial College London estimated the bill at £17-40 billion between now and 2050.
However, if distribution network operators (DNOs) are successful in developing new technology, and the business models to take it to market, they could boost decarbonisation by enabling more renewable generation on to the grid while also reducing costs to customers.
As they move from their traditional role of simply distributing electricity to playing a far more active role in balancing supply and demand, DNOs have been researching, developing and trialling innovative ideas to deal with decentralisation. Some 1,400 projects have taken place since 2004, according to trade body the Energy Networks Association (ENA).
Randolph Brazier, head of innovation and development at the ENA, says one of the highlights of projects so far has been integrating findings from research on flexible connections and active network management schemes into everyday business operations.
“The fact that this innovation has been rolled out into business as usual is a real milestone. Some of this has been on the back of their own trials, while other DNOs have followed ideas developed by other networks,” he says.
But what have DNOs learnt so far? Myriad projects have investigated ways to allow more generation on to the grid, reduce household demand at peak times, remove the need for back-up power during power station outages and even decarbonise heat. Utility Week spoke to five DNOs about some of their recent pilots to find out what worked, what challenges each faced and what will follow.
Wales & West Utilities: the Freedom Project
The accepted view in energy policy and industry circles just a few years ago was that heating in buildings would be decarbonised by electric heating systems replacing gas boilers, with hybrid systems as a transitional phase. Wales & West Utilities set out to challenge that with the £5.2 million Freedom Project.
Trialled in South Wales, it has investigated the consumer, network and energy system implications of domestic smart-controlled hybrid heating systems, which provide heat by switching between a gas boiler and an air source heat pump according to the cost of the fuel.
As part of the Freedom Project, led by West & Wales Utilities, Western Power Distribution (WPD) and PassivSystems, 75 hybrid heating systems were installed in residential properties in Bridgend, South Wales, in 2017. Householders can set the time when they want their home to be warm, and the system automatically calculates whether it is cheaper to provide that warmth through the air source heat pump or the gas boiler, and switches between them accordingly.
Air source heat pumps from three different manufacturers were selected and installed in a range of housing types, which were chosen to broadly represent UK housing stock. During the trial, which took place over last winter, the operation of the hybrid heating systems was varied to explore different scenarios, for example changing the fuel cost ratios that determined when the system would switch from one energy source to another.
Hybrid heating systems would benefit the energy system in several ways, explains Ollie Lancaster, project manager of Freedom at Wales & West Utilities. If the UK chooses to meet decarbonisation targets by electrifying heat, the electricity network will have to be rebuilt to take the extra heat.
But if homes were instead heated using air source heat pumps that can switch to the gas boiler at peak times to reduce demand on the system, network operators can avoid the costs of infrastructure upgrades. It avoids the cost of building more peak generation capacity, such as low carbon and peaking gas plants, he says.
Hybrid heating also avoids the huge cost and disruption to householders of replacing pipework and radiators, since the system can be bolted on to existing heating equipment, Lancaster says. Research carried out by Imperial College London as part of the project found that smart hybrid systems could provide £15 billion a year savings to the UK compared with full electrification.
Hybrid systems were also found to reduce customer bills. Lancaster explains: “One of the case study houses was a stone miner’s cottage on a hillside, that had no insulation – the hardest type of home to decarbonise. The heat pump provided 78 per cent of the heat demand in that home, meaning that they saved £736 over the winter, compared to using their LPG boiler.
“This presents the opportunity to install low-carbon ready smart hybrid gas systems now to help with fuel poverty, which is more prolific in areas off the gas grid,” he adds.
The main challenge experienced by the project was gaining consumer trust in the heating equipment, which is very different to the typical “on/off” boilers most people are used to, Lancaster says.
“There was a lot of confusion about why the heat pump needed to be on a few hours before you wanted heat. People thought that would waste energy, whereas it was actually using the electricity when its available at a lower cost.”
Next steps planned by the DNO include developing the commercial proposition to introduce “heating as a service”. Rather than paying for gas and electricity supply, households would pay a fixed fee for heating, with the equipment provided free. The heat service provider would recover the cost from the savings they make using the flexibility on people’s homes.
The DNO wants to test adding other smart-controlled appliances such as fridges and washing machines on to the Freedom system to boost the options for householders to provide flexibility to the grid. It is also looking at the feasibility of introducing hybrid heat in non-domestic settings such as shops, schools and offices.
UK Power Networks: Kent Active Systems Management
UK Power Networks (UKPN) has seen significant changes on its network recently. Its network is in the south east and east of England, an area attractive for both wind and solar PV generation. It has 7.9GW of decentralised energy connected to its network, from 220,000 individual generators. It also has 1.2GW of battery storage.
In Kent in particular, electricity generation far outstrips demand because of the high number of solar farms and offshore windfarms. Until now, energy from some renewable sources could be supplied to the network at certain times.
Its Kent Active System Management (KASM) project is trialling sophisticated modelling and forecasting tools to plan and operate the network more accurately and understand the impact of extra generation. Ultimately, as many generators will be connected for as long as possible. The project is designed to enable the DNO to make better decisions when modelling planned outages, explains Ian Cameron, head of innovation at UKPN. KASM is trialling contingency analysis, an advanced form of power flow modelling that can evaluate in near real-time the potential for adverse conditions to affect the distribution network.
It is also using advanced forecasting tools to provide better information on the performance of generators. For example, weather data from equipment on the site of a renewable energy plant is more detailed than Met Office data, and could include how cloudy it will be above a solar PV plant. The forecasting tool also takes power flow direction data from a far greater number of points, to take account of the increased complexity of power flow on a network where the grid is taking in energy and transmitting it.
Part of the project has been to link UKPN’s distribution network control centre with National Grid’s transmission system control centre so real-time data can be shared to allow both organisations to build an accurate long-term picture of exactly what is happening on the network, and plan future capacity accordingly.
The combination of the data sharing and the new software is expected to give control operators the confidence to allow more energy on to the system by analysing complex scenarios in seconds and predicting the possible impacts of control decisions as they are made. Ultimately, it aims to increase the export of renewable energy to the network by releasing more capacity than would otherwise be available.
“Generators need to be available more than they would have been historically,” Cameron says. “There are more than 350 grid supply points in the UK. Just on the four in our East Kent trial area, we’ve been able to achieve 4,000MWh more renewable energy generation than we would have a year ago. The aim is to achieve 8,000MWh of additional renewable energy generation in one year, enough to power about 2.6 million homes for an hour.”
One issue that was not expected was the reliability of data flowing into the software, Cameron says. “We selected the location for the trials mainly because of the volume of renewable energy connected there, but also because we thought the data there would be good, but actually we found that the input data was not as good as a system like this would require.”
Another tool was developed, which used algorithms programmed to understand power flows to deduce missing data, he says. Understanding the importance of getting consistent and accurate data from the network and third parties was a key lesson learnt during the project, Cameron says.
Northern Gas Networks: using gas for electricity storage
Northern Gas Networks (NGN) has been investigating how the gas network can support decarbonisation by using hydrogen to store and transmit surplus power.
Sheffield-based energy and clean fuel company ITM Power approached NGN and proposed the trial of an electrolyser it had developed. This would use water and electricity to turn excess power into hydrogen, injecting it into the natural gas network and using it as a renewable energy store. This could then be used in heat, electricity generation or transport via hydrogen fuel cell vehicles.
Such a system could provide an alternative to batteries as storage, explains Keith Owen, NGN’s head of systems development and energy strategy. “Batteries are good, but it’s about identifying as many options as we can within the UK to broaden the spectrum of what’s possible,” he says. “By taking excess electricity energy from the grid, in effect power-to-gas technology is allowing more renewables on the system.
“Also, because you’re putting hydrogen into the gas grid, you’re decarbonising that as well,” he adds. “It doesn’t 100 per cent decarbonise heat, but it’s a movement away from using pure and natural gas.”
The study examined potential deployment of large-scale storage capacity of 50MW and above within the boundaries of NGN’s distribution network. Following detailed analysis of NGN’s network, accounting for seasonal variations in gas demand and the amount of hydrogen able to be produced and blended with natural gas, it revealed a large area of the NGN grid could support power-to-gas.
The results were better than expected, Owen says. “We thought there would be parts of the network that would be appropriate for power-to-gas, but I was quite surprised at how available our network was.”
The study tested a 50MW contribution from hydrogen, which the team considered quite a high proportion to blend into the network, he says.
“I thought maybe there’d be two or three connection points that would be appropriate. But we found five. We also found a number of sites and were operating a 10-20MW position, the number of opportunities was far greater. We didn’t expect to see that.
The team then tested the system with 100MW of hydrogen, and found one site on the network that could handle that, Owen says. “That was quite an exciting place to be – there are larger networks out there than ours, so that bodes really well nationally for what you can do in Scotland or the Midlands.”
NGN now plans to test the technology at its Integrated Transport Electricity Gas Research Laboratory (InTEGReL) in Gateshead, an incubator it launched last year with Northern Powergrid and Newcastle University specifically to demonstrate integrated energy system technology.
Scottish and Southern Electricity Networks: the Nines Project
SSEN set out to develop a smart grid on the island of Shetland, having already created one on Orkney. The 67MW Lerwick Power Station is nearing the end of its life, and the DNO wants to replace it with a smaller one, if enough flexibility can be found elsewhere. The Northern Isles New Energy Solutions (Nines) project piloted the concept that simple domestic loads such as hot water tanks and storage heaters could balance an electrical system.
Smart electric storage heaters were installed in around 750 homes to provide more comfortable and affordable heating to residents, while helping to balance the electricity network. An electric boiler was added to the existing district heating system to link to a proposed windfarm on the island.
The project also saw new technology deployed to allow more small-scale renewable generators to connect to the network, and new commercial arrangements to encourage businesses to change the times when they used the most energy. A 1MW battery was installed at Lerwick Power Station.
Stewart Reid, head of DSO and innovation at SSEN, says the project delivered more than 1MW of frequency response from fewer than 240 homes, with the system responding to demand in under a second, contributing to system stability on the island.
However, the trial also found that the business case for third party organisations, whose core purpose was not flexibility, along with the uncertainty of the value of flexibility, resulted in challenges in securing sufficient flexibility in a small geographical area within normal investment timelines. This meant the market would need to be designed with the bankability of flexibility provision in mind, Reid says.
Ensuring that residents knew and understood the motive for the trials, and the potential benefits was a resource-intensive exercise even on a small Scottish Island, he says. The DNO partnered with Hjaltland Housing Association to keep tenants informed.
“In future we would not anticipate a DNO being the organisation directly engaging with the customer with regard to the detail of their heating system, but this does emphasis the need for the organisations taking on this role to have a customer-centric philosophy, and for DNOs to work closely with them providing the data and information necessary for the flexibility operator to provide customers with the information, guidance and certainty they need,” he says.
Electricity North West: Smart Street and Class
ENW based two of its innovation projects on the knowledge that the average domestic customer’s voltage typically varies between around 225V and 250V, with no visible effect on appliances. They asked themselves how varying customers’ voltage by a tiny fraction could increase grid capacity, while also saving the customer money.
Its Class project investigated how this concept could be used to remove the need to have back-up generation to stop the lights going out during outage of a power station or interconnector. Although this only happens four of five times a year, consumers have to bear the cost of back-up generation being on standby. As well as being expensive, it is also carbon intensive because it is typically provided by coal or gas, explains Steve Cox, ENW’s engineering director.
“We know that appliances use more or less electricity depending on what you do with the voltage. But what happens if you change all voltages across the network at the same time you lose the power station? If we turn the voltage up 3 per cent, a kettle will boil a litre of water eight seconds faster, and if I turn it down by 3 per cent, it will take eight seconds longer. Most people won’t notice the difference.
“But if you do that, not to one kettle, but to millions of homes at the same time, you can effectively create more than a nuclear power station’s worth of demand reduction. It’s very significant in size, but relies on
only a tiny bit from each customer,” he explains.
The beauty of it is that it uses equipment that is already there, and does not need to be fed by fossil fuels, he adds. ENW plans to sell this balancing service to National Grid, with customers receiving a direct reduction in the network component of their bill.
ENW piloted the concept on 400,000 customers, with post-trial surveys reporting no problems with household appliances. The second phase of the project investigated how voltage control could be brought to market and the benefits shared with customers. “The regulatory mechanisms are quite complex, but unless they’re aligned properly, some savings don’t automatically transfer to customers. We needed a clear directive from Ofgem on that,” Cox explains.
It also considered whether it should sell the demand response to suppliers via an aggregator. However, Ofgem allowed it to sell it directly to avoid customer benefits being reduced through the aggregator taking its share, he says. ENW is now rolling the project out to its 2.4 million customers, and expects to complete this by May 2019.
Another project, Smart Street, has also used voltage control to increase capacity on the network. However, rather than kicking into action when there is a significant power outage, voltage is controlled continuously in response to changes in demand to keep the network as efficient as possible.
Trials identified that the average consumer would save £70 a year out of a £100 network charge by deferring expensive network reinforcement while operating their appliances more efficiently. If rolled out across Great Britain, the total annual saving could reach £519 million.
ENW maintains that its projects are much simpler and quicker to implement than engaging customers in providing demand response themselves through an app, as some DNOs have trialled.
“A lot of companies have for an almost consensual approach to asking customers to sign up to a particular tariff and change demand when they ask for it. That has its space, but it’s hard to persuade customers to do that – an individual customer will only save a small amount, £5-10 a year if you’re lucky.
“What we’re doing is getting a tiny bit of response, but from millions of customers, which gives us useable demand response, and customers absolutely don’t notice,” Cox says.
“A lot of what we’ve been doing is what makes a material difference now. Although our innovation strategy looks ahead to 2025, 2030 and 2035, we also want to save money for customers in 2018, 2019 and 2020,” he adds.