Europe has been slow to invest in wind energy storage. But as installed capacity increases, the business case may soon be too strong to ignore.

By Emma Clarke, London correspondent

The problem with wind is that it is intermittent. As more wind farms are built, managing this large, intermittent power supply will present significant problems to grid operators.

One solution is to store the energy, absorbing excess power at periods of low demand and then releasing it when electricity demand is high. The other solution is to develop smart grids and demand-manage energy consumption.

Currently several energy storage solutions exist, all at different stages of commercial readiness. The options include pumped hydro storage, compressed air energy storage, batteries, super capacitors, and flywheels.

Japan has already installed more than 300MW of stored energy on wind farms, most of it using sodium-sulfur (NaS) batteries. The United States also recently earmarked US$185m to fund utility-scale energy storage projects.

Progress in Europe, however, has been slower. Unlike in Japan, developers here have little incentive to build storage facilities at individual farms, which means the onus is on local network companies or transmission system operators (TSOs) to install or use storage.

So far, there has been minimum motivation to do so. But as wind penetration increases, and the difference between off and on-peak prices in the electricity market widen, storage will become more attractive for utilities so they can buy low, store the energy, and then sell high.

This is already happening in Germany with concentrations in offshore wind widening differences in prices, says Cian McLeavey-Reville, analyst at research company, Delta Energy & Environment.

Technologies in the pipeline

With this incentive in mind, RWE Power is working with General Electric to investigate the feasibility of a compressed-air energy storage power plant (CAES).

CAES compresses air at times of high electricity availability, storing it in underground caverns. When electricity demand rises, the compressed air drives turbines to generate electricity.

RWE’s first demonstration is expected after 2013 with a storage capacity of 1,000Mwh and an electric output of up to 200MW.

CAES has been on the design table for decades, with the first commercial plant built in Hundorf, Germany in 1978. The reason it has been slow to take off is because better value is obtained using caverns for natural gas storage rather than air, says Anthony Price, of energy storage consultancy, Swanbarton.

Another well-established alternative for large-capacity grid storage is pumped hydro. Here, water is pumped up to an elevated reservoir and then released to drive a generator at periods of high demand.

There is over 90GW of pumped hydro already in use worldwide. However, there are limited sites left that have the right topography.

The Dutch Government, working with Dutch utilities, is exploring the creation of an “Energy Island” developed by energy consulting firm, KEMA. This hollowed-out artificial island would be installed off the Dutch coast, using a pumped hydro system but in reverse.

Batteries are another alternative, and those with capacities in the megawatt region are becoming evermore prevalent worldwide. “Lithium ion battery suppliers can install batteries as quickly as people will buy them,” says Price.

NaS batteries have been demonstrated in around 200 sites in Japan. The largest is a 34MW battery installed on a 51MW wind farm in 2008 by Japan Wind Development Company.

In the UK, EDF Energy Networks is in the process of installing a battery storage system as part of a trial on its 11kV distribution network.

In 2008, E.ON awarded €6 million (US$8.5mn; £5.2mn) in grants towards a number of research projects into energy storage technologies including highly-efficient batteries as well as mobile solutions such as electric vehicles. These research projects have another 15-18 months to run, says an E.ON spokesperson.

Flow batteries are also on the cusp of becoming commercially available, says McLeavey-Reville. The UK utility, Scottish & Southern Energy, has acquired a minority stake in Premium Power, a developer of zinc bromide flow batteries and has installed a trial system at its transmission sub-station in Nairn, Scotland.

Denmark’s TSO, Energinet is also testing a 1MW, 2MWh vanadium redox flow battery system.

Flywheel systems, such as developed by Beacon Power, are also being installed at MW sizes, says Price.  These are designed primarily for balancing system supply and demand over milliseconds to minutes rather than hours or days.

Storage technologies can be dedicated to individual wind firms, though the general consensus is to use them on a system-wide basis. Distributed storage, at individual building or community level, could also support system operations, says McLeavey-Reville.

Sky high costs

Investment costs vary between technologies. Flywheels, for example, cost around $3,000-4,000 per kilowatt and NaS $3,500- 4,000 per kilowatt, says McLeavey-Reville.

Premium Power claim their flow batteries would bring the cost down to around $2,000 per kilowatt, though this remains to be seen, he adds. 

There are large differences in terms of investment costs. But as Price says: “If you take into consideration the expected lifetime of the technology, most technologies work to the same sort of numbers.”

The costs for pumped storage and CAES in terms of dollars per kwh, are around $250-300 for pumped hydro and $600-700 for CAES, McLeavey-Reville points out.

That said, no matter which technology is used, it’s going to be expensive - which implies that energy storage will lead to an increase in electricity prices.

The alternative solutions

Storage, however, is not the only solution for ensuring grid stability, says Nick Medic, BWEA spokesperson. “[Wind energy storage] should only be the last line defence”, he argues.

“To routinely manage the grid we need to use either greater interconnection, better demand side management, or have renewable energy resources spread over larger geographical areas.”

International connections, such as through a European supergrid, would balance fluctuations between different renewable sources at a continental, instead of national, level.

Demand side management could also be improved through the development of a smart grid and smart metering by allowing electricity networks to function more efficiently.

With a smart grid in operation, electric vehicles could also be used as mobile storage devices, feeding electricity back into the network when needed.

However, Price argues that developing storage technologies is more cost effective than building a smart grid.

Isolated European countries, such as Ireland, are also less able to make use of international connections. “Ireland has a huge renewables targets, so it is likely storage will play an important role,” says McLeavey-Reville.

What is clear is that creating a secure and efficient low-carbon power system relies on a number of solutions.

“We are going to need all these tools, but the technology already exists to install storage,” says Price. “What we need now is to open up the debate to move storage forward.”

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