Strengthening storage solutions

Nant de Drance hydropower plant
The Nant de Drance hydropower plant near the Swiss/French border will use the latest innovation in pumped-storage technology to generate 628 MW of electricity when it comes into operation in 2017 Source: Alstrom

Distributed renewable energy sources are contributing significantly to the world’s power supply, but their unpredictable power-generation capability challenges grid stability. This is a key factor driving energy storage technology. PEi reviews the range of projects currently in development.

Penny Hitchin

The ability to ‘bottle’ energy could smooth out some of the uncertainties of wind and solar photovoltaic (PV) generation, improve supply efficiency and keep costs down. Renewable energy sources such as wind turbines and PV plants are increasingly contributing to the mix of electricity power. But because they generate intermittently and unpredictably, expanding their use creates challenges for system stability, integration into the power grid, operating reserves, maintaining the quality of voltage and supply, as well as peak load management.

The technology for decoupling electricity generation exists, but so far the business case for investment has not stacked up. In Europe, as well as the US and China, the political imperative driving low-carbon energy generation means the development of storage technology is very much on the agenda, although regulatory regimes have yet to catch up.

Range of storage technologies

Technologies that could contribute to utility-scale energy storage systems include: pumped hydro; batteries (including conventional and advanced technologies); superconducting magnetic energy storage (SMES); flywheels and fuel cell/electrolyser systems. All are at varying stages of development, and offer different advantages and disadvantages. For short-term energy storage, rapid power delivery is more important than energy capacity, so SMES and flywheel systems are more suited to systems where consistent power quality is important.

Pumped hydro is the only established system for large-scale bulk electrical energy storage, although it requires appropriate terrain and massive capital. Pumped hydro is also the gold standard of energy storage, in comparison with which other technologies discussed here are small fry. But this needs to change. Accelerations in electrical energy storage technology and unit-cost reductions make systems more viable, although political and regulatory changes are needed to ensure energy storage is incorporated into the heart of distribution systems.


Pumped hydro

Pumped hydroelectricity is an established technique for energy storage, and is the most widely used system on power networks with more than 127 GW in operation worldwide. It stores energy efficiently during off-peak hours and releases it during high power demand in peak hours, evening out load variations on the power grid and balancing the network.

Pumped storage systems work through using two water reservoirs built at differing heights. Energy is stored by pumping water from the low to the high storage reservoir during off-peak hours using available surplus energy. During peak demand, the stored water is released through turbines for hydroelectric power generation. It converts an oversupply of electricity during off-peak hours into peak-demand energy. The global pumped storage market is expected to grow 60 per cent in the next four years, with an average of 6 GW of added capacity each year.

Power company Alstom expects half the market to come from China, although Europe’s Alpine regions account for a quarter of the current market. Switzerland’s mountainous terrain enables it to generate half of its energy from hydro resources. The new Nant de Drance hydropower plant near the Swiss-French border involves building a pumped storage power station in an underground cavern between the Emosson and Vieux Emosson reservoirs. The plant will use the latest pumped storage technology: variable-speed pump turbines, which offer fast-power output or input variation to optimise turbine or pump efficiency. It will generate 628 MW of electricity when it comes into operation in 2017.

Compressed air energy storage (CAES)

CAES compresses air in underground caverns for use as an energy source. Excess electricity is used to power an electrical motor, which drives a compressor that stores air in the cavern. When electricity demand increases, the compressed air is released and used to run a turbine to produce electricity. Energy is stored underground during periods of low-energy demand for use in periods of higher demand. CAES is suitable for large-scale energy storage, provided suitable geological formations, such as underground salt domes, can be found.

There are two working CAES plants currently in operation: E.ON’s 290 MW plant in Huntorf, Germany, built in 1978, and Alabama Electric Corporation’s 110 MW plant in Alabama, US, commissioned in 1991. Unlike the technology, the business case is yet to be understood. But the arrival of intermittent renewable energy on the grid means the economics may change, with new projects likely to come on stream.

RWE Power and partners GE and the German Aerospace agency DLR are working on the ADELE (adiabatic CAES) project. CAES technology components will be developed and a demonstration plant will be constructed. The project will have a storage capacity of 360 MWh and an electric output of 90 MW. The €12 million ($15.5 million) ADELE development programme started in 2010, and the construction of the StaàƒÅ¸furt plant will begin next year for completion by 2016.

Another planned CAES project is Gaeletric’s proposed à‚£175 million ($282 million) project in Antrim, Northern Ireland, which the company believes has the potential for a plant of between 140 MW and 300 MW. The project team is currently exploring whether the local salt deposits are suitable for the proposed scheme.

Cryogenic energy storage (CES)

An innovative 300 kW CES system, based on Highview Power technology, is operating in a project at a power plant in Berkshire, UK.

The Cryo Energy System harnesses existing technology in a liquefaction plant and power generator. The process liquefies air, which can be stored in large volumes at atmospheric pressure. Liquefied air has a high expansion ratio between its liquid state (-196 à‚ºC) and its everyday gaseous state; expanding about 700 times when re-gasified. A cryogenic engine relies on phase change (from liquid to gas) and expansion within a confined space, such as engine cylinder or turbine. Since liquid air boils at -196 à‚ºC, ambient temperature will superheat it, creating re-gasification and expansion. An engine can therefore use freely available environmental heat as the heat source.

The energy density of cryogenic fluids compares favourably with alternative energy storage fluids such as compressed air. Cryogenic storage also has the advantage over compressed gases in that it can be bulk stored above ground in low-pressure tanks. Cryo Energy System operates by using electrical energy from the adjoining power station to drive an air liquefier. The liquid air is stored in an insulated tank at low pressure. When power is required, liquid air is drawn from the tank and pumped to high pressure. Ambient heat is applied to the liquid air via heat exchangers, resulting in a phase change from liquid air to a high-pressure gas, which is used to drive a turbine and generator. During the power recovery, very cold gas is exhausted, which is then recycled back into the liquefaction process, reducing the energy demands for producing liquid air and thereby increasing the overall round-trip efficiency.

Waste and low-grade heat can be used in the power recovery system to increase the amount of extractable power. The cold energy is captured using technology similar to that used in steel and chemical industries, where cold energy is stored in sand or gravel beds. It then re-liquefies air to store more energy. The SSE plant is part-funded by a à‚£1.1 million grant from the Department of Energy and Climate Change (DECC).


Batteries are essential for household and business appliances. Off-grid systems rely on battery storage, but grid-scale battery use is in its infancy, although that looks set to change.

The two main types of battery used in distributed energy systems are flow batteries and high-temperature batteries, notably sodium sulphur (NaS) and sodium nickel chloride (NaNiCl) batteries. Unlike lead-acid batteries, these devices cycle on a daily basis, with operating lives of between 10 and 20 years. The systems can be designed to charge or discharge for up to eight hours per day with no emissions.

Flow-battery technology uses an active element in a liquid electrolyte pumped through a membrane to produce an electrical current. The system’s power rating is determined by the size and number of membranes, and the run time (hours) is based on the volume of electrolyte pumped through the membranes. Pumping in one direction produces power from the battery; reversing the flow charges the system.

High-temperature batteries operate above 250 à‚ºC using molten materials as the positive and negative elements of the battery. These chemistries produce battery systems with very high-power densities that can store large amounts of energy.

(i) Sodium sulphur batteries

Sodium sulphur batteries have been used on a commercial scale since 2002. To keep their sulphur-positive electrodes in a molten state and to enable the sodium ions passed through the electrolyte to combine with the sulphur, they operate at temperatures of about 300 à‚°C. By end March 2011, NaS batteries storing 305 000 kW of electricity were in use in 174 locations in Japan, France, Germany, the UK, the US and the UAE.

Large NaS battery technology suffered a setback last year when batteries storing electricity at the Tsukuba plant belonging to Mitsubishi Materials Corporation in Japan caught fire. NGK Insulators, the major supplier of the batteries, halted manufacture in September 2011, and advised customers to refrain from using the batteries during investigations. A à‚£3.3 million project to install a 1 MW NaS battery energy storage system on the Shetland Islands is on hold pending the outcome.

(ii) Nickel salt batteries

During charging of sodium-nickel chloride batteries, the salt (NaCl) and nickel (Ni) are transformed into nickel chloride (NiCl2) at the cathode and sodium (Na) in the anodic section. Discharge occurs by means of an opposite reaction, with the sodium reacting to the nickel chloride at the positive electrode.

In the US, Arista Power is using Durathon nickel-salt batteries developed by GE’s transportation division to develop power-on-demand systems. These use energy generated by wind turbines, solar PV, the electric grid and other power sources in conjunction with a battery storage system and proprietary real-time demand-monitoring technology. The monitoring system is designed to smooth power demand on the grid by maintaining grid demand within optimal parameters and releasing stored power only during peak-demand periods, reducing peak demand charges, prolonging battery life and lowering commercial electricity costs.

GE describes these batteries as smaller and lighter than traditional versions, resistant to extreme temperatures, and recyclable. They come with a 20-year guarantee and require no cooling and only minimal maintenance, says GE. Although internal battery temperatures reach up to 350 à‚°C, double-walled, vacuum-insulated enclosures ensure the outer skin stays at no more than 10 à‚°C above ambient temperature, says GE.

(iii) Lithium batteries

Lithium-ion batteries dominate the portable electronics market. Higher-power designs with improved cycling capability are being developed. Materials used in lithium-ion batteries make them more expensive than halide batteries, although prices are dropping as production volumes rise.

In the US, Arizona’s largest utility, APS, is testing a 1.5 MWh lithium-ion battery energy-storage system developed by Electrovaya Incorporated. Initially, the system is acting as a distribution substation, storing electricity when demand and prices are low and dispatching it when demand surges. The second part of the test involves moving the equipment to a nearby solar zone to work with a 500 kW solar PV farm.

The world’s largest lithium-ion battery project was commissioned in China last December. Chinese electric car and battery maker BYD teamed with the State Grid Corporation of China to develop the 36 MWh storage facility in Hebei province alongside 100 MW of wind and 40 MW of solar PV. The scheme could increase to 500 MW wind and 100 MW of PV, plus 110 MW of storage.

Siemens installed a pilot energy-storage project using lithium batteries in Enel’s medium-voltage distribution network earlier this year. The Italian utility is using it to integrate PV power plants and for an electric vehicle charging station. The stored electrical energy is used for load regulation and voltage stabilisation in both cases. The system’s black-start capacity enables the start-up of the grid when the main alimentation is not available. The Siemens system consists of modules made up of a compact battery and a converter cabinet. Capacity can be expanded to up to 2 MWh and its output up to 8 MW.

UK Power Networks is trialling lithium-battery technology in a à‚£1.8 million partnership with ABB. The storage device has been installed at Hemsby in Norfolk, and stores power from local wind turbines in lithium-ion batteries. The eight stacks of 13-battery modules are housed in a 25 m2 substation-type building where they are charged and discharged repeatedly. ABB’s DynaPeaQ technology enables dynamic control of power in the transmission system, improving grid voltage and stability, and levelling off power fluctuations. The rated power and storage capacity is typically about 20 MW for about 15″45 minutes, but can be scaled up to 50 MW of power for 60 minutes.

(iv) Flow batteries

Flow batteries store the electrolyte externally and pump it through the cells of the reactor. The vanadium redox (reduction-oxidation) flow battery has been used in many countries, particularly Japan. It has two electrolytes ” both vanadium-based, but using vanadium ions with different charges ” separated by a proton-exchange membrane. Sumitomo Electric Industries has several vanadium RFB installations, including a 4 MW wind-farm operation at Sapporo.

zinc-bromine flowing electrolyte battery module
A zinc-bromine flowing electrolyte battery module has been designed to support solar PV arrays Source: RedFlow

Australian company RedFlow’s core product is the zinc-bromine flowing electrolyte battery module (ZBM). The company says that the latest ZBM delivers 10 kWh of energy, with a peak power rating of 5 kW. The battery is made out of plastics and weighs 220 kg, a fraction of the mass of comparable lead-acid batteries. It is designed for day-in, day-out deep cycling with three- to eight-hour charge and discharge times, and is suitable for grid-scale electricity-storage systems.

RedFlow plans to deploy its first megawatt-class containerised battery systems to support a large solar PV array at the University of Queensland over the next year. It will also develop demonstration plants in the US.

Are regulatory changes needed?

With renewable energy becoming firmly established as part of the generation mix, energy storage can help provide flexibility, reduce the need for additional reserve-generation capacity, and make the use of natural resources more efficient. Technical developments are underway, driven partly by development of electric vehicles batteries, but also by the prospect of changes to grid networks to accommodate new renewable generation coming on stream.

Anthony Price of the Electricity Network Association strongly advocates energy storage. “To change the nature of our energy supply away from fossil fuels, electricity storage is going to be even more crucially important,” he said.

But although the storage technology exists, current electricity market structures do not encourage investment, he argues. “The technology is not the problem ” you can buy it, install it, integrate it and it will work. But can you guarantee the return on the finance? We are currently in an uncertain market where we can have no confidence in the future income stream.”

This theme is echoed across the energy-storage industry: integrating energy storage into the distributed energy networks should be part of de-carbonising electricity supply, but electricity markets do not yet have mechanisms in place to encourage such investment. What will it take to achieve this?

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