Electricity and Energy Storage
(Updated 28 March 2017)
- Electricity storage on a large scale has become a major focus of attention as intermittent renewable energy has become more prevalent.
- Pumped storage is well established. Other megawatt-scale technologies are being developed. These can provide dispatchable capacity as required by demand.
- For storage plus intermittent renewables to replace base-load capacity the storage needs be able to meet demand for multiple days, not simply hours.
- At household level, behind the meter, battery storage is being promoted. It reduces grid demand.
The rapid increase in many parts of the world of generating capacity by intermittent renewable energy sources, notably wind and solar, has led to a strong incentive to develop energy storage for electricity on a large scale. The extent to which electricity storage can be developed will determine the extent to which those intermittent renewable sources can displace dispatchable sources, taking surplus power on occasions and bridging intermittency gaps. There are questions of scale – power and energy capacity which are indicated below in particular cases – and whether the stored electricity is available over days and weeks rather than minutes and hours.
Electricity cannot itself be stored, but it can be converted to other forms of energy which can be stored and later reconverted to electricity on demand. Electricity storage systems include battery, flywheel, compressed air, and pumped hydro storage. Such systems are limited in the total amount of energy they can store, expressed in megawatt-hours (MWh), and the maximum power output at a given time, expressed in megawatts of electric power (MW or MWe). Electricity storage is a type of energy storage, which may use another form of energy – for example, thermal – as input or output.
Pumped storage comprised 95% of the world’s large-scale electricity storage in mid-2016, and 72% of the storage capacity added in 2014. Battery storage, however, was deployed strongly through 2014, with a record 400
MW additions, more than doubling the installed base in 2013. Building-scale power storage emerged in 2014 as a defining energy technology trend. This market grew by 50% year-on-year, with lithium-ion batteries prominent but flow cell batteries showing promise.
This schematic of the Gordon Butte project is typical of pumped storage (Gordon Butte)
A World Energy Council report in January 2016 projected a significant drop in cost for the majority of energy storage technologies as from 2015 to 2030. Battery technologies showed the greatest reduction in cost, followed by sensible thermal, latent thermal and supercapacitors. Battery technologies showed a reduction from a range of €100-700/MWh in 2015 to €50-190/MWh in 2030 – a reduction of over 70% in the upper cost limit in the next 15 years. Sodium sulfur, lead acid and lithium-ion technologies lead the way according to WEC. The report models storage related to both wind and solar plants, assessing the resultant levelised cost of storage (LCOS) in particular plants. It notes that the load factor and the average discharge time at rated power is an important determinant of the LCOS, with the cycle frequency becoming a secondary parameter. For solar-related storage the application case was daily storage, with six-hour discharge time at rated power. For wind-related storage the application case was for two-day storage with 24 hours discharge at rated power. In the former case the most competitive storage technology had LCOS of €50-200/MWh. In the latter case, levelised costs were higher and sensitive to the number of discharge cycles per year, and “few technologies appeared attractive."
Following a two-year study by the California Public Utilities Commission, the state in 2010 passed legislation requiring 1325 MWe of electricity storage (excluding large-scale pumped storage) by 2024. In 2013 it brought forward the deadline to 2020, then having 35 MW total. The legislation specifies power, not storage capacity (MWh), suggesting that the main purpose is frequency control. The stated purpose of the legislation is to increase grid reliability by providing dispatchable power from an increasing proportion of solar and wind inputs, replace spinning reserve, provide frequency control and reduce peak capacity requirements (peak shaving). The storage systems can be connected with either transmission or distribution systems, or be behind the meter. The main focus is on battery energy storage systems (BESS). Energy arbitrage may enhance revenue, buying off-peak and selling for peak demand. Southern California Edison in 2014 announced plans for 260 MW of electricity storage to offset the closure of the 2150 MWe San Onofre nuclear plant.
In the USA, 221 MW of new storage capacity was deployed in 2015, and this is expected to grow to 1700 MW by 2020, when costs are expected to drop to $200/kWh of energy stored, half the 2016 cost. In 2015, 160 MW of the total 221 was installed by a single regional TSO, PJM Interconnection, which provided regulatory support.
Early in 2016 the UK’s National Grid got a strong response to a tender for 200 MW enhanced frequency response (EFR). It offered four-year contracts for capacity able to provide 100% active power output in a second or less of registering a frequency deviation. Some 888 MW of battery capacity was offered, 150 MW of interconnection, 100 MW of demand-side response and 50 MW of flywheel capacity. All but three involved battery storage. In August the winning bids were announced – the eight chosen tenders being from 10 MW to 49 MW (totalling 201 MW) and costing £66 million in total. The winning bids ranged from £7 to £12 per MW of EFR/h, with an average of £9.44/MW of EFR/h. Batteries are also expected to become the main choice for firm frequency response, slightly slower than EFR.
In the UK storage is treated as generation for licensing purposes, but on connection to a distribution network it has to comply with two different connection and charging methodologies, with one half connecting as demand and the other as generation. A single storage connection methodology is proposed, and the Department for Business, Energy & Industrial Strategy and energy regulator Ofgem are aiming to define ’electricity storage’ in legal and regulatory terms so as to expedite deployment. The Electricity Storage Network, an industry body, supports the move.
On demand response, the UK government said providers should have easier access to a range of markets so they can compete fairly with large generators, including the balancing market, ancillary services, and the capacity market. There is concern that storage and demand response providers should be able to access the same length capacity market contracts as new diesel generators. In this area the response needs to be over hours, and batteries are less economical.
In November 2016 the European Commission proposed a new definition of electricity storage to include “deferring an amount of the electricity that was generated to the moment of use, either as final energy or converted into another energy carrier” such as gas. This brought power-to-gas (P2G) concepts within the regulatory definition of energy storage so that excess power from intermittent renewables can by electrolysis be turned into hydrogen which can be added to the normal gas distribution network (up to 20%, though much less allowed in most countries), or sold directly. Electrolysers could thus be providing ancillary grid services for which they are paid. The redefinition of P2G from simply a load to storage has implications for both electricity grids and reducing CO2 arising from gas. P2G electrolysers can be seen as part of the grid, not simply end users.
ITM Power, which develops electrolysers for P2G systems, proposes to build a number of hydrogen refuelling stations for fuel cell cars in the UK, with these having some grid balancing function. In March 2017 it had four in operation, with hydrogen production timed to absorb excess power from the grid. The UK government wants 65 hydrogen refuelling stations by 2020. Each has 200 to 250 kW capacity, so a number of them are needed to be able to bid for enhanced frequency response (minimum 3 MW).
Polymer electrolyte membrane (PEM) electrolysers are now available at about €1 million per MW, with smaller footprint and more rapid response than alternatives, enabling grid balancing and energy storage. Some 4.7 TWh of renewable electricity was curtailed in Germany in 2015.
Pumped hydroelectric storage
In some places pumped storage is used to even out the daily generating load by pumping water to a high storage dam during off-peak hours and weekends, using the excess base-load capacity from low-cost coal or nuclear sources. During peak hours this water can be released through the turbines to a lower reservoir for hydro-electric generation, converting the potential energy into electricity. Reversible pump-turbine/motor-generator assemblies can act as both pumps and turbines. Pumped storage systems can be effective in meeting peak demand changes due to rapid ramp-up or ramp-down, and profitable due to the differential between peak and off-peak wholesale prices. The main issue apart from water and altitude is round-trip efficiency.
Relatively few places have scope for pumped storage dams close to where the power is needed, and overall ‘round-trip’ efficiency is 70 to 80%, but pumped storage has been used since the 1920s and today about 150 GW pumped storage is installed worldwide, including 21 GW in the USA and 38 GW in Europe. This amounts to some 500 GWh able to be stored – about 95% of the world’s large-scale electricity storage in mid-2016, and 72% of that capacity which was added in 2014. The International Energy Agency's World Energy Outlook 2016 projects 27 GW of pumped storage capacity being added by 2040, mainly in China, USA and Europe. The scope is limited by suitable sites.
Unlike wind and solar inputs to a grid system, hydro generation is synchronous and therefore provides ancillary services in the transmission network such as frequency control and provision of reactive power. A pumped storage project typically has 6 to 20 hours of hydraulic reservoir storage for operation, compared with much less for batteries. Pumped storage systems are typically over 100 MWh stored energy.
The largest pumped storage facility is in Virginia, USA, with 3 GW capacity and 30 GWh of stored energy. However, useful facilities can be quite small. They also do not need to be supplementary to major hydroelectric schemes, but can use any difference in elevation between upper and lower reservoirs of over 100 metres if not too far apart. In Okinawa seawater is pumped to a cliff-top reservoir. In Australia a disused underground mine was considered for a lower reservoir.
In Montana, USA, the $1 billion, 4 x 100 MW Gordon Butte Pumped Storage Hydro Project in the central part of the state will use excess power from the state’s 665 MWe of wind turbines. Absaroka Energy will build the elevated reservoir on a mesa 312 metres above the lower reservoir from 2018. It expects to supply 1300 GWh per year to supplement wind, with ancillary services.
In Germany the Gaildorf wind and hydro project near Münster is expected to be operational in 2018. It comprises 13.6 MWe of wind turbines and 16 MWe of hydro capacity from pumped storage.
Battery energy storage systems
The requirements for battery storage are high energy density, high power, long life (charge-discharge cycles), high round-trip efficiency, safety, and competitive cost. Various compromises are made among these criteria, underlining the limitations of battery energy storage systems (BESS) compared with dispatchable generation sources. The question of energy return on energy invested (EROI) also arises, which acutely relates to how long a battery is in service and how its round-trip efficiency holds up over that period.
In 2015 lithium-ion batteries accounted for 51% of newly announced energy storage system (ESS) capacity and 86% of deployed ESS power capacity. An estimated 1,653 MW of new ESS capacity was announced around the world in 2015, with just over one-third coming from North America. Lithium-ion batteries are the most popular technology for distributed energy storage systems (Navigant Research). Lithium-ion batteries have a 95% round trip direct current efficiency, falling to 85% when the current is converted to alternating current for the grid. They have a 10-20 year lifespan, depending on use.
At household level, behind the meter*, battery storage is being promoted. There is obvious compatibility between solar PV and batteries, due to them being DC, in contrast to wind generation. In Germany, where solar PV has an average 10.7% capacity factor, 41% of new solar PV installations in 2015 were equipped with back-up battery storage, compared with 14% in 2014. This increase, in both household and grid-connected PV systems, is encouraged by the KfW Development Bank, which arranges low-interest government loans and payback assistance covering up to 25% of the required investment outlays. KfW requires that sufficient PV electricity be used for onsite consumption and storage so that no more than half of the output reaches the transmission network. In this way, it is claimed that 1.7 to 2.5 times the usual solar capacity can be tolerated by the grid without overloading. In 2016, 200 MWh of installed storage capability was reported for Germany.
* Household and small business PV is not part of the distribution system but is essentially domestic to the premises, with much generated power used there and some possibly exported to the system through the meter which originally measured power drawn from the grid to be charged for.
Over one-third of the 1.5 GW ‘battery storage’ in 2015 was lithium-ion batteries, and 22% was sodium-sulfur batteries. The International Renewable Energy Agency (IRENA) estimates that the world needs 150 GW of battery storage to meet IRENA's desired target of 45% of power generated from renewable sources by 2030. In the UK about 2 GW is required for rapid frequency control in a 45 GWe system, and National Grid spends £160 to £170 million per year on this.
A large BESS is a 40 MW/20 MWh Toshiba lithium-ion system at the Tohoku Electric Power Company’s Nishi-Sendai substation in Japan, commissioned early in 2015, and San Diego Gas & Electric has a 30 MW/120 MWh lithium-ion BESS in Escondido, California. Also STEAG Energy Services has started a 90 MW storage program in Germany, and Edison is setting up a 100 MW facility in Long Beach, California.
Sodium-sulfur batteries have been used for 25 years and are well established, though expensive. They also need to operate at about 300°C, which means some electricity consumption when idle. PG&E’s 2 MW/14 MWh Vaca-Dixon NaS BESS system cost about $11 million ($5500/kW, compared with about $200/kW which PG&E estimated to be break-even cost in 2015). Service life is about 4500 cycles. Round-trip efficiency in an 18-month trial was 75%.
A general finding from the PG&E trial was that if batteries are to be used for energy arbitrage, they should be co-located with the wind or solar farms – often remote from the main load centre. However, if they are to be used for frequency regulation, they are better located close to the urban or industrial load centres. Since the frequency control revenue stream is much better than arbitrage, utilities will normally prefer downtown rather than remote locations for assets they own.
The first of six planned 90 MW STEAG units in a €100 million program was energised in June 2016 at its Lunen coal-fired site in Germany. To qualify for commercial operation, the batteries need to respond to automated calls within 30 seconds and be capable of feed-in for a minimum of 30 minutes.
In Germany, RWE has invested €6 million in a 6 MW battery system at its Herdecke power station site near Dortmund, where the utility operates a pumped storage plant. The system is planned to start operations at the start of 2017.
In Germany, a 10 MW/ 10.8 MWh lithium-ion battery storage system was commissioned in 2015 at Feldheim, Brandenburg. It has 3360 lithium-ion modules from LG Chem in South Korea. The €13 million battery unit stores power generated by a local 72 MW wind farm and was built to stabilise the grid of TSO 50Hertz Transmission. It also participates in the weekly tendering for primary control reserve.
German operators of battery systems which are bid into the primary control reserve market on a weekly basis are reported to have received an average price of €17.8/MWh over 18 months to November 2016.
In May 2016 Fortum in Finland contracted French battery company Saft to supply a €2 million megawatt-scale lithium-ion battery energy storage system for its Suomenoja power plant as part of the largest ever BESS pilot project in the Nordic countries. It will have a nominal output of 2 MW and able to store 1 MWh of electricity, to be offered to the TSO for frequency regulation and output smoothing. It is similar to the system operating in the Aube region of France, linking two wind farms, total 18 MW. Saft has deployed over 80 MW of batteries since 2012.
UK Power Networks has a 6MW/ 10 MWh demonstration lithium-ion system supporting a local substation at Leighton Buzzard.
UK undersecretary of state for energy Amber Rudd visits the Leighton Buzzard facility in 2014 (UK Power Networks)
In Northern Ireland, US generator AES has completed a 10 MW/ 5 MWh energy storage array at its Kilroot power station in Carrickfergus. The system consists of over 53,000 lithium-ion batteries arranged in 136 separate nodes with control system which responds to grid changes in under a second. It is the largest advanced energy storage system in the United Kingdom and Ireland, and the only such system at transmission scale according to AES. The company wants to build the storage array up to 100 MW, providing £8.5 million in system savings per annum “by displacing out of merit thermal back up plant and facilitating fuller integration of existing renewables,” it said.
In the UK, on the Orkney Islands, a lithium-ion battery storage system of 500 kWh and delivering 2 MW is operating. This Kirkwall power station uses Mitsubishi batteries in two 12.2m shipping containers, and stores power from wind turbines.
In Somerset, Cranborne Energy Storage has a 250 kW/ 500 kWh Tesla Powerpack lithium-ion storage system associated with a 500 kW solar PV set-up. Tesla claims that the powerpacks can be configured to provide power and energy capacity to the grid as a standalone asset, offering frequency regulation, voltage control, and spinning reserve services. The standard Tesla Industrial Powerpack unit is 50 kW/210 kWh, with 88% round-trip efficiency.
In the UK, Statoil has commissioned the design of a 1 MWh lithium-ion battery system, Batwind, as onshore storage for the 30 MW offshore Hywind project at Peterhead, Scotland. From 2018 it is to store excess production, reduce balancing costs, and allow the project to regulate its own power supply and capture peak prices through arbitrage.
In May 2016 renewables energy company RES signed a four-year contract with National Grid to provide 20 MW of dynamic frequency response from lithium-ion battery storage, to be operational in 18 months. RES already has more than 100 MW/ 60 MWh of battery storage in operation, mostly in North America.
In January 2017 EDF Energy Renewables signed an agreement with Nidec ASI to build a 49 MW battery storage project for National Grid at EDF Energy’s West Burton site, as part of a 200 MW frequency response system to be deployed across the UK.
Nearly 1 GW of battery storage is forecast on the UK grid by 2020, and Poyry projects 12 GW of grid-scale batteries in Europe by 2040.
In November 2016 Pacific Gas & Electricity Co (PG&E) reported on an 18-month technology demonstration project to explore the performance of battery storage systems participating in California’s electricity markets. The project began in 2014 and utilized PG&E’s 2 MW/14 MWh Vaca-Dixon and 4 MW Yerba Buena sodium-sulfur battery storage systems to provide energy and ancillary services in California Independent System Operator (CAISO) markets and controlled by CAISO in that wholesale market. The $18 million Yerba Buena BESS Pilot Project was set up by PG&E in 2013 with $3.3 million support from the California Energy Commission. Vaca-Dixon BESS is associated with a PG&E solar plant in Solano County.
The PG&E report showed that batteries were still far from cost-effective, even assuming a 20-year battery life. Used for energy arbitrage (charging when price was low and discharging when price high), the 6 MWe set-up barely covered operating expenses. The margin achieved in cost of power arbitrage was consumed by the 25% power lost between cycles due to charging and discharging inefficiencies and the energy required to keep the batteries at operating temperature (300°C). The optimum use of the BESS was confirmed as frequency regulation, with batteries maintained half-charged and ready to charge or discharge as required to compensate for mismatches between generation and load. Response time is very rapid, and hence very valuable to CAISO (or any TSO). When used entirely for frequency control the 2 MW storage netted almost $35,000 per month – better than alternative uses, but still low payback for $11 million investment. Operational control proved extremely complex. PG&E reported to the California Assembly: "With California Assembly Bill 2514 and its requirements that utilities procure 1.3 gigawatts of energy storage, California ratepayers could expect to pay billions of dollars for the deployment and operations of these resources.”
In 2017, PG&E will utilize the Yerba Buena battery for another technology demonstration involving the coordination of third-party distributed energy resources (DERs) – such as residential and commercial solar – using smart inverters and battery storage, controlled through a distributed energy resource management system (DERMS).
In August 2015 GE was contracted to build a 30 MW/20 MWh lithium ion battery storage system for Coachella Energy Storage Partners (CESP) in California, 160 km east of San Diego. The 33 MW facility was completed by ZGlobal in November 2016 and will aid grid flexibility and increase reliability on the Imperial Irrigation District network by providing solar ramping, frequency regulation, power balancing and black start capability for an adjacent gas turbine.
San Diego Gas & Electric has a 30 MW/120 MWh lithium-ion BESS in Escondido, built by AES Energy Storage and consisting of 24 containers housing 400,000 Samsung batteries in almost 20,000 modules. It will supply evening peak demand, and partly replaces the Aliso Canyon gas storage 200 km north which had to be abandoned early in 2016 due to a massive leak. (It was used for peak-load gas generation.)
SDG&E's 30MW battery storage facility in Escondido, California. (Photo: San Diego Gas & Electric)
Southern California Edison is building a 100 MW/400 MWh battery installation to commission in 2021, comprising 80,000 lithium-ion batteries in containers. Another big SCE project proposed is a 20 MW/80 MWh storage for AltaGas Pomona Energy at its San Gabriel natural gas-fired plant.
A large project is Southern California Edison’s $50 million Tehachapi 8 MW/32 MWh lithium-ion battery storage project in conjunction with a 4500 MWe wind farm, using 10,872 modules of 56 cells each from LG Chem, which can supply 8 MW over four hours. In 2016 Tesla contracted to supply a 20 MW/80 MWh lithium-ion battery storage system for Southern California Edison’s Mira Loma substation, to help meet daily peak demand.
Tesla is reported as aiming to have 50 GWh online by the early 2020s.
The 98 MW Laurel Mountain wind farm in West Virginia employs a multi-use 32 MW/8 MWh grid-connected BESS. The plant is responsible for frequency regulation and grid stability in the PJM market as well as arbitrage. The lithium-ion batteries were made by A123 Systems, and when commissioned in 2011 it was the largest lithium-ion BESS in the world.
In December 2015 EDF Renewable Energy commissioned its first BESS project in North America, with 40 MW flexible (20 MW nameplate) capacity on the PJM grid network in Illinois to participate in the regulation and capacity markets. The lithium-ion batteries and power electronics were supplied by BYD America, and consist of 11 containerized units totaling 20 MW. The company has more than 100 MW of storage projects under development in North America.
E.ON North America is installing two 9.9 MW short-duration lithium ion battery systems for its Pyron and Inadale wind farms as Texas Waves storage projects in West Texas. The purpose is mainly for ancillary services. The project follows 10 MW Iron Horse near Tucson, Arizona, adjacent to a 2 MWe solar array.
SolarCity is using 272 Tesla Powerpacks (lithium-ion storage system) for its 13 MW/52 MWh Kaua’i Island solar PV project in Hawaii, to meet evening peak demand. Power is supplied to Kauai Island Utility Cooperative (KIUC) at 13.9 cents/kWh for 20 years. KIUC is also commissioning a project with a 28 MWe solar farm and 20 MW/100 MWh battery system.
Toshiba has supplied a large BESS for Hamilton, Ohio, comprising an array of 6 MW/2 MWh lithium-ion batteries. Lifetime of over 10,000 charge-discharge cycles is claimed.
A large utility-scale electricity storage is a 4 MW sodium-sulfur (NaS) battery system to provide improved reliability and power quality for the city of Presidio in Texas. It was energized early in 2010 to provide rapid back-up for wind capacity in the local ERCOT grid. Sodium-sulfur batteries are widely used elsewhere for similar roles.
In Anchorage, Alaska, a 2 MW/0.5 MWh battery system is complemented by a flywheel, to assist use of wind power.
In Australia, near Lakeland, south of Cooktown, a 10.4 MW solar PV plant is to be supplemented with 1.4 MW/ 5.3 MWh of lithium-ion BESS as edge of grid set-up, with island mode during evening peak. It will use the Conergy Hybrid Energy Storage Solution plant, and is due on line in 2017. The AUD 42.5 million project will reduce the need for grid upgrade. BHP Billiton is involved with the project as possible prototype for remote mine sites. Other such systems are at Degrussa and Weipa mines. A 100 MW solar PV plus 40 MW BESS is proposed for near Olympic Dam mine.
Other battery technologies
RedFlow has a range of zinc bromide flow battery modules (ZBM) which can be installed in connection with intermittent supply and is capable of daily deep discharge and charge. They are more durable than lithium-ion type, and expected energy throughput for smaller ZBM units ranges to 44 MWh. Large-scale battery (LSB) units comprise 60 ZBM-3 batteries that deliver peak 300 kW, continuous 240 kW, at 400-800 volts and supply 660 kWh.
Eos Energy Storage in USA uses its Znyth aqueous zinc battery with a zinc hybrid cathode, and optimised for utility grid support, providing 4 to 6 hours continuous discharge. It comprises 4 kWh units making up 250 kW/1 MWh subsystems and a 1 MW/ 4 MWh full system.
Duke Energy is testing a hybrid ultracapacitor-battery storage system (HESS) in North Carolina, close to a 1.2 MW solar installation. The 100 kW/300 kWh battery uses aqueous hybrid ion chemistry with salt water electrolyte and synthetic cotton separator. The rapid-response ultracapacitors smooth the load fluctuations.
Lower-cost lead-acid batteries are also in widespread use at small utility scale, with banks of up to 1 MW being used to stabilise wind farm power generation. A 0.5 MW Purewave Storage Management system with 1280 advanced lead-acid batteries was commissioned in September 2011 at PNM's Mesa Del Sol, Albuquerque New Mexico, by S&C Electric Co. The GS Batteries are capable of up to 4000 deep discharge cycles. Australia’s largest lead-acid battery storage system is 3 MW/1.5 MWh on King Island.
Stanford University is developing an aluminium-ion battery, claiming low cost, low flammability and high-charge storage capacity over 7500 cycles. It has an aluminium anode and graphite cathode, with salt electrolyte, but produces only low voltage.
Ontario's ISO has contracted a 2 MW zinc-iron redox flow battery from ViZn Energy Systems.
Avista Corp in the northwest USA Washington state is purchasing a 3.6 MW vanadium flow battery to load balance with renewables.
(Flow cell batteries have two chemical components dissolved in liquids and separated by a membrane.)
In May 2015 Tesla announced a household battery storage unit of 7 or 10 kWh for storing electricity from renewables, using lithium-ion batteries similar to those in Tesla cars. It will deliver 2 kW and works at 350-450 volts. The Powerwall system would be sold to installers at $3000 for a 7 kWh unit or $3500 for 10 kWh, though the latter option was promptly discontinued and the former downrated to 6.4 kWh storage and 3.3 kW power. While this is clearly domestic-scale, if widely taken up it will have grid implications. Tesla claims 15 c/kWh to utilize the storage, plus the cost of that renewable energy initially, with 10-year, 3650-cycle warranty covering diminishing output to 3.8 kWh at year five, 18,000 kWh total.
In the UK, Powervault supplies diverse batteries for household use, mainly with solar PV but also with a view to savings with smart meters. Its 4 kWh lead-acid battery is the most popular product at £2900 installed, although the actual batteries need replacing every five years. A 4 kWh Li-ion unit costs £3900 installed, and other products range from 2 to 6 kWh, costing up to £5000 installed.
Compressed air energy storage (CAES)
Energy storage with compressed air (CAES) in geological caverns is being trialled, using gas-fired or electric compressors, the adiabatic heat being dumped. When released (with preheating to compensate for adiabatic cooling) it powers a turbine, up to 300 MW, with overall about 70% efficiency. CAES capacity can even out the production from a wind farm and make it partly dispatchable. Two CAES systems are in operation, in Alabama and Germany, and others trialled or developed elsewhere in the USA. CAES capacity in the USA was 450 MW in 2010 and is expected to grow to 6000 MW by 2020. Nearly one-third of the 1.5 GW ‘battery storage’ in 2015 was CAES.
Batteries are reported to have better efficiency than CAES (output as proportion of input electricity) but they cost more per unit of capacity, and CAES systems can be much larger.
Duke Energy and three other companies are developing a 1200 MW, $1.5 billion project in Utah, ancillary to a 2100 MW wind farm and other renewable sources. This is the Intermountain Energy Storage Project, using salt caverns. It is targeting 48-hour duration for discharge to bridge intermittency gaps, hence apparently over 50 GWh. The site may also store surplus solar power transmitted from Southern California. It is to be built in four 300 MW stages.
Gaelectric Energy Storage plans a 550 GWh/yr CAES project at Larne, Northern Ireland.
Toronto Hydro with Hydrostor has a pilot project using compressed air in bladders 55m underwater in Lake Ontario to yield 0.66 MW over one hour.
Other electricity storage
As described in the solar thermal subsection of the WNA Renewable Energy paper, some CSP plants use molten salt to store energy overnight. Spain's 20 MWe Gemasolar claims to be the world's first near base-load CSP plant, with 63% capacity factor. Spain's 200 MWe Andasol plant also uses molten salt heat storage, as does California's 280 MWe Solana.
Another form of heat storage is being developed in South Australia, where the 1414 Company is using molten silicon. The process can store 500 kWh in a 70 cm cube of molten silicon, about 36 times as much as Tesla’s Powerwall in much the same space. It discharges through a heat-exchange device such as a Stirling engine or a turbine and recycles the heat. A 10 MWh unit would cost about A$ 700,000. (1414 °C is the melting point of silicon.)
In Germany Siemens has commissioned a 6 MW hydrogen storage plant using proton exchange membrane (PEM) technology to convert excess wind power to hydrogen, for use in fuel cells or added to natural gas supply. The plant in Mainz is the largest PEM installation in the world.In Ontario, Hydrogenics partnered with German utility E.ON to create a 2 MW PEM facility that came on line in August 2014, turning water into hydrogen through electrolysis.
San Diego Gas & Electric is working with Israeli GenCell to install 30 GenCell G5rx back-up fuel cells at its substations. These are hydrogen-based alkaline fuel cells with 5 kW output.
Flywheels store kinetic energy. Ontario’s ISO has contracted for a 2 MW flywheel storage system from NRStor Inc. Hawaiian Electric Co is installing an 80 kW/320 kWh flywheel system from Amber Kinetics for its Oahu grid, this being one module potentially of several. Normally flywheels, storing kinetic energy ready to turn back into electricity, are used for frequency control rather than energy storage, they deliver energy over a relatively short period and can each supply up to 150 kWh. Amber Kinetics claims four-hour discharge capability.
The principal use of flywheels is in diesel rotary uninterrupted power supply (DRUPS) set-ups, with 7-11 second ride-through synchronous function during start-up of an integrated diesel generator following mains supply failure. This gives time – e.g. 30 seconds – for normal diesel back-up to start. The flywheel is otherwise storing energy.
A form of flywheel is the Synchronous condenser, used for frequency and voltage control in weak parts of a grid or where there is a high proportion of variable renewable input requiring grid stability to be enhanced. It can compensate either a leading or lagging power factor, by absorbing or supplying reactive power to the line. It is like a synchronous motor but not mechanically connected to provide energy.
Another form of energy storage is ice. Ice Energy has contracts from Southern California Edison to provide 25.6 MW of thermal energy storage using its Ice Bear system, attached to large air conditioning units. This makes ice at night when power demand is low, then uses it to provide cooling during the day instead of the aircon compressors, thus reducing peak demand.
The US Department of Energy's Global Energy Storage database has more information.
Jeffrey Michel, Germany sets a new solar storage record, Energy Post, 18 July 2016
Todd Kiefer, CAISO Battery Storage Trial, Transmission & Distribution World, 21 November 2016