Energy storage in the UK
Ten years after a world-leading energy storage project was cancelled, the UK is once again taking the technology seriously. Tim Probert surveys the scene.
Some argue there is a glaring omission from the UK Government’s Electricity Market Reform. While the Coalition’s flagship energy policy may ultimately subsidise every form of power generation, be it wind, wave, nuclear, coal, gas, solar, biomass, tidal or hydro, there is no specific provision in the new regime to develop energy storage. Currently, the Department of Energy and Climate Change (DECC) gives the energy storage industry only a few crumbs from its enormous subsidy table. Yet that could soon change.
In recent months, DECC has awarded more than £13m in grants to fund three projects, as part of its Energy Storage Technology Demonstration Competition. Two of the projects are geared towards large, grid-scale storage. The third, Moixa, was awarded £1.5m to develop small lithium-ion battery units to be installed in homes with direct current (DC) power for domestic energy storage.
In November 2013, Wokingham-based Renewable Energy Dynamics Technology (REDT) was granted £3.6m to install a 1.26MWh vanadium redox flow battery and connect it to a wind turbine in the Scottish island of Gigha. Once installed in early 2015, REDT’s battery will store surplus energy from the wind turbine and use it in the local network.
Vanadium redox batteries are based on the ability of vanadium to exist in four different oxidation states – V2, V3, V4 and V5 – each of which holds a different electrical charge. The electrolyte in the negative halfcell has V3+ and V2+ ions, while the electrolyte in the positive half-cell contains VO2+ and VO2+ ions. During discharge, the process is reversed – reduction in the positive half-cell converts VO2+ ions back to VO2+ ions, while oxidation in the negative half-cell converts V2+ ions back to V3+ ions. The typical open-circuit voltage created during discharge is 1.26V.
REDT’s energy storage batteries work on the same basic principles as common rechargeable batteries. Batteries consist of three main components – two half cells (one positive, the other negative), a membrane that electrically isolates the half cells from each other, and an electrolyte. A chemical reaction called reduction-oxidation (redox) occurs, which changes the composition of the electrolyte, creating a shortage of electrons at the cathode (positive terminal) and a surplus at the anode (negative terminal). When the battery is in use, the electrons flow from the anode to the cathode, which generates an electrical current. When charging, the electrical current applied to the terminals reverses the redox reaction. This returns the battery to its original state, ready to be discharged again.
Vanadium redox flow batteries were first patented in 1986 by the University of New South Wales, Australia, and although DECC says the application of a flow battery to a wind farm is innovative, several such projects have been installed around the world in the past decade. Indeed, the project is not dissimilar to the (ten times larger) flow battery system developed by erstwhile power generation National Power. Regenesys Technologies’ 12MWe polysulfide bromide flow battery system used 24,000 stacked ion exchange membranes to separate two electrolytes, sodium bromide (NaBr) and sodium polysulphide (Na2Sx). As with all flow batteries, the electrolytes stored electricity as a result of their modified chemistry, and the total electricity storage capacity was limited solely by the size of the electrolyte tanks. Although the facility was completed, engineering issues in scaling up the technology meant that it was never fully commissioned. The Regenesys project was closed in 2004 following the acquisition of National Power (now known as npower) by German utility group RWE.
Again, as with all flow batteries, the need for membranes that do not leak or become clogged over many years of operation is a pressing and technologically challenging one. Unlike other flow battery technologies, REDT claims that because its flow battery uses vanadium compounds on both sides of its ion-selective membrane, the problem of cross-contamination is eliminated, allowing for simple maintenance procedures.
At £2,857/kWh, the £3.6m cost is extremely high for what is a relatively small 1.26MWh system. However, REDT says its 20-year lifetime (the Gigha project is expected to run until around 2036 once operational), and its ability to absorb and release power for thousands of cycles – even with deep cycling – is an attractive proposition for off-grid island communities around the world.
The other grid-scale technology to be a recipient of a DECC Energy Storage Technology Demonstration Competition grant was Highview Power Storage, which has been working since 2005 to develop liquefied air energy storage (LAES). Very much a UK innovation, initial research on LAES was conducted by the University of Leeds and ultimately led to the construction of a 350kW/2.5MWh pilot plant in Slough, in the south east, which has been running successfully since 2011. Now armed with £8m funding, Highview will design and test a 5MW/15MWh pre-commercial demonstration LAES system at a landfill gas generation plant in nearby Canterbury, owned by waste management firm Viridor.
Highview’s LAES system is made up of three primary processes:
Charging system – comprises an air liquefier, which uses electrical energy to draw air from the surrounding environment. During this stage, the air is cleaned and cooled to subzero temperatures until 700 litres of ambient air liquefies to become one litre of liquid air. In the case of the Viridor project, liquid air/nitrogen will be delivered to site.
Energy storage – liquid air is stored in an insulated tank at low pressure. This equipment is commonly deployed for bulk storage of liquid nitrogen, oxygen and LNG. According to Highview, the tanks used within industry have the potential to store several gigawatt-hours.
Power recovery – when power is required, liquid air is drawn from the tanks and pumped to high pressure. Stored heat from the air liquefier is applied to the liquid air via heat exchangers and an intermediate heat transfer fluid. This produces a high-pressure gas, which is then used to drive a turbine and generator. In addition to providing energy storage, the liquid air plant will convert low-grade waste heat to power. The low boiling point of liquefied air means the round-trip efficiency of the system can be improved with the introduction of above-ambient heat.
As illustrated in the diagram below, Highview’s standard LAES system captures and stores heat produced during the liquefaction process (stage 1) and integrates the heat to the power recovery process (stage 3). For the Viridor project, Highview will be integrating waste heat from the site’s landfill gas generation plants. The ultimate aim of project, which is expected to come online by mid-2015, is to demonstrate the LAES technology providing a number of balancing services, including Short Term Operating Reserve and Triad avoidance, reducing electricity demand during the winter peaks.
Challenges and opportunities
Outside of the DECC competition, there are an additional 23 electricity storage projects of various scales in development. According to the UK Electricity Storage Network (ESN), there is 5.1MW of new storage commissioned and a further 7.2 MW under construction or planning.
Anthony Price, Director of the ESN, believes there is massive potential for existing and well-proven electricity storage technology in the form of lithium, sodium and lead-based batteries to be deployed by distribution network operators (DNOs), which run the A, B and minor roads of the British electricity system. ‘The really big opportunity is to use electricity storage in distribution grid companies to optimise the increasing volume of intermittent generation and generation sources on the distribution network,’ says Price. ‘If we can run the distribution network on average load instead of peak, it would save the rewiring of Britain. That’s where the really big money is.’
While the benefits of load smoothing and load following already make economic sense in niches like off-grid island applications, for energy storage systems to realise their true value potential, the output must be sold into market. But this requires a supply licence, which is off-limits to DNOs. As DNOs cannot hold a generation licence, they cannot effectively install energy storage systems on a widespread basis without a major change in regulation.
The ESN, which wants DECC to adopt an electricity storage target of 2GW by 2020, has been lobbying Government for several years to change the regulation. So far it has largely fallen on deaf ears, says Andrew Jones, Head of A&D at KPMG’s Europe, Middle East and Africa (EMEA) Oil & Gas network and Managing Director of S&C Electric Europe. ‘We have been telling them what the barriers are, and DECC now recognises those barriers are real and that they need to make changes to licensing. However, before they make changes, they want to see action in the field to see if the business case stacks up in UK market conditions.’
So S&C Electric is doing just that. In 2014, it will start work on the £18.7m, 6MW/10MWh Smarter Network Storage battery technology project, at a primary substation in Leighton Buzzard in Bedfordshire. The project, funded under UK regulator Ofgem’s Low Carbon Networks Fund, is Europe’s largest battery energy storage trial. Using standard Samsung SDI lithiumion battery chemistry and integrated by Germany’s Younicos, the system will provide frequency regulation as well as load shifting. Most importantly, Jones thinks, it has the potential to save more than £6m on network reinforcement investment in transformers, cables and overhead lines. ‘On a like for like basis, the energy storage system weighs in at around £2m more than investing in a new transformer 40 miles away plus the cost of linking it to the Leighton Buzzard substation. But the additional ancillary services could be worth a total £8m saving in asset deferment.’
If the scheme is a success, the pressure will undoubtedly be on DECC to show greater support for the energy storage industry. Jones hopes DECC will adopt ESN’s target of 2000 MW by 2020. ‘How that will actually translate to the market, we don’t know,’ he says. ‘But what we are not asking for is subsidies. We don’t believe they are needed because if the necessary regulatory measures are taken the business case stands up without them.’