In recent years, the share of the UK’s electricity supplied by renewable energy (RE) sources has increased substantially to the point that RE is now the second largest source after gas: It now supplies 20% to 25% of our electrical needs. This is greater than the amount supplied by nuclear – about 15% to 18%. Coal, hydroelectric, and mainly gas (~40%) constitute the other sources. See chart for Britain’s electrical power supplies in 2019.
Why are AGR reactors inflexible?
Before his untimely death in 2018, the nuclear engineer, John Large, explained that while advanced gas reactors (AGRs) were considered safe and reliable once they were up and running, they were difficult to control, ie less safe, when ramping up and down, especially in comparison to pressurised water reactors (PWRs). (PWRs were originally designed for flexible use in US nuclear submarines.)
For this reason, in the 1970s and 1980s, the former CEGB set the pattern of a nuclear “base load” in which its Magnox and AGR reactors operated flat out most of the time. Essentially this pattern is still adhered to today by the National Grid[1]. However in recent years, a fundamental change in system economics has happened: nuclear has been undercut by the renewables. So the AGR control issue didn’t used to be an economic problem, but now it is.
Difficult situation re nuclear and RE
The National Grid keeps supply and demand balanced in real time to prevent blackouts, such as occurred on August 9 2019, when a million UK homes were cut off. But when demand is low – as in recent months during the pandemic – it is difficult to have all nuclear and all RE sources running at the same time as the Grid would end up with too much electricity. To avoid this, the Grid requests utilities to shut off their supplies and makes “constraint” payments to those who do so. A complicated reverse auction system exists for these payments in which operators bid as low as they feel able in order to secure such payments.
Because of the inflexibility of the AGRs, RE suppliers are shut off first. This is explained in a recent report by the newly-formed pressure group, 100percentrenewableuk, which explains that the inflexible nature of nuclear power is instrumental in forcing the National Grid to turn off large amounts of wind power (ie in the jargon to be ‘constrained’) in Scotland when there is too much electricity on the network. https://realfeed-intariffs.blogspot.com/2020/06/nuclear-report-published-today-by-newly.html
This means nuclear reactors are also mainly responsible for the large constraint payments paid by the National Grid to wind farms to be turned off. These compensation payments are eventually paid for by all electricity consumers in the fixed element of their electricity bills.
The problem is that these constraint payments are now very large. For example, National Grid ESO, the UK system operator expects to spend an additional £500 million to balance the grid over the course of the 2020 summer, much of it in payments to wind farms to stop generating. In total, National Grid expects to spend £826 million to balance the grid in 2020. https://www.thetimes.co.uk/article/blackout-risk-as-low-demand-for-power-brings-plea-to-switch-off-wind-farms-xv36v575x
This appears nonsensical as the Grid is turning off cheap renewables to preserve expensive nuclear, and then paying large compensation payments to them to do so. One wonders what OFGEM makes of this? As pointed out by the National Audit Office, this problem will get even worse if Hinkley C were ever to be allowed to finish construction and allowed to operate.
The situation has recently become so problematic that the Grid has been forced to request EDF Energy to shut half the generating capacity of its nuclear reactor at Sizewell in Suffolk. See https://www.thetimes.co.uk/article/big-is-not-so-beautiful-in-grid-talks-to-power-down-8w0qxbtgg “More than” £50 million is to be paid to EDF just to reduce the output from Sizewell to avert the risk of blackouts this summer.
One surmises that the reason the Grid and EDF chose the Sizewell reactor to restrict is its large capacity (1200 MW). It is by far the largest reactor in Britain (the remaining AGRs are about 460 MW), and this presents a problem. If it failed or quickly went off-line (eg it scrammed its control rods for safety reasons), the sudden loss of 1200 MW in supply would present severe problems for the grid. It could result in a drop in frequency triggering other plants to fail. This happened after the simultaneous failures of two (non-nuclear) power stations in August 2019. One shudders to think what would occur if Hinkley C (2 x 1600 MW) were ever to operate and it failed. To avoid this problem, the National Grid keeps what is called “spinning reserve” on line, but this redundant reserve is expensive and all electricity consumers have to pay for it.
Can we manage the intermittency of renewables and attain 100% renewables?
Yes. In fact, many ways are possible, including
- improved resource and weather forecasting
- interconnecting the grid over larger UK regions
- digitally-controlled smart grids giving better control of demand
- power storage, in the form of pumped hydroelectric dams, dedicated batteries and electric car batteries
- the increased use of the many existing interconnectors with Europe
- the increased use of smart wind turbines, and
- the use of heat pumps, heat batteries, liquid air batteries and hydrogen fuel cells.
Interestingly, in June 2020, several large power companies, including Centrica and E.ON, sent an open letter calling on National Grid to accelerate the deployment of smart electric vehicle (EV) charging infrastructure, energy storage and other flexibility services in order to manage the Grid more rationally. The utilities’ letter stated that a number of options existed to reduce its current reliance on curtailing renewables, from long-duration storage to industrial-scale demand response. They stated that EVs, smart electric heaters and home solar batteries “could all be providing services at this time if the right signals and instructions were being administered”. They added “flexible technologies and storage assets will be needed to integrate a higher level of renewable generation into the system to produce carbon savings. Harnessing the potential of these technologies is critical to ensuring green energy supply isn’t unnecessarily wasted”. https://www.greentechmedia.com/articles/read/smart-flexibility-could-slash-uk-coronavirus-curtailment-costs
Indeed, throughout the UK,local authorities and local companies are in fact steaming ahead with their own initiatives. See box below. In addition, the recent UK pressure group, 100percentrenewableuk, was also set up to press for these developments. www.100percentrenewableuk.org
| Box. Some examples of innovative flexible RE technologies
1.An Edinburgh company, Gravitricity, is planning to use disused coal mine shafts in Scotland to store renewable energy by using heavy weights. Surplus electricity at night would be used to lift weights to the tops of mine shafts. When electricity were needed, the weights can be allowed to drop by gravity turning turbines for power. 2, Flexitricity, partnered with Gresham House Energy Storage Fund, is operating a 75 MWh battery storage site in Yorkshire. The lithium-ion battery storage site is trading in wholesale markets using the National Grid ESO’s balancing mechanisms. Energy Voice 15th May 2020 https://www.energyvoice.com/otherenergy/240736/uks-largest-battery-to-help-keep-the-nations-lights-on/ 3. South Somerset District Council has built a 30 MW battery energy storage system. It works with a local company Opium Power to sell flexibility services to the grid generating income for the Council. Solar Power Portal 25th Oct 2019 https://www.solarpowerportal.co.uk/news/somerset_council_owned_battery_to_be_boosted_to_30mw 4. A Virtual Power Plant in West Sussex streamlines how low-carbon energy is generated, stored, traded and consumed. The £31m SmartHubs Smart Local Energy Systems project last year received £13m of funding through the Government’s Industrial Strategy Challenge Fund. The project acts as a demonstrator to facilitate the decarbonisation of heat, transport and energy across social housing, transport, infrastructure and private residential and commercial properties in West Sussex. Project partners include ITM Power, Moixa Technology, ICAX, PassivSystems, Newcastle University, West Sussex County Council and Connected Energy. Edie 27th May 2020 https://www.edie.net/news/8/West-Sussex-s–31m–smart–local-energy-system-to-progress-during-lockdown/ 5. Orkney already has an operational smart grid generating more than 100% of its electricity demand via renewable energy sources. It is integrating a new Demand Side Management system with the existing grid to provide intelligent control and aggregation of electric heating systems in homes, businesses and council buildings, as well as EV charging points and hydrogen electrolysers. A distinctive aspect is that demand response services are delivered by a new local energy company, a consortium of local generators and other stakeholders. The system specifications and operating parameters are approved by the Grid’s DSO, which retains final oversight of the system, but day-to-day management is by the local company and its contractors. https://www.h2020smile.eu/the-islands/the-orkneys-united-kingdom/ For the future, at least two additional technologies below could also be implemented, 6. Heat pumps in conjunction with thermal storage to be operated when RE generated electricity is plentiful and demand is low. Denmark is looking at using CHP plants in conjunction with heat pumps and additional heat storage capacity to store surplus energy on windy days. Their district heating systems could absorb large quantities of surplus wind-generated electricity by using heat pumps and electric heaters for heating water. When demand for electricity is high but the wind is low, CHP plants could sell their electricity. http://www.pfbach.dk/firma_pfb/forgotten_flexibility_of_chp_2011_03_23.pdf 7. The same principle applies to electric vehicles using vehicle to grid technology. Central and local governments across UK have fleets of ~75,000 vehicles. If these were EVs, they could come back to depots with an estimated average 50% charge which could be sold back to the grid during the peak (red zone) period of 4.30 pm to 7.00 pm. They could then be recharged in the small hours ready for morning duties. (http://projects.exeter.ac.uk/igov/wp-content/uploads/2013/10/Lockwood-System-change-in-a-regulatory-state-paradigm-ECPR-Sept-13.pdf) |
[1] This is in contrast with France. It obtains about 75% of its electricity from nuclear so that EDF in France must ramp up and down most of their reactors to follow diurnal demand patterns. But this is a risky practice, therefore for safety reasons most of the older 900 MW French PWR reactors are restricted to low burnup regimes (<25,000 MW days per tonne when designed for 33,000 MW days per tonne).