Power Up

The Australian | 8 September 2017

The Crescent Dunes solar thermal power plant, built by US operator Solar Reserve north of Las Vegas

In an energy-hungry world, battery storage is the way of the future. But not all technologies are equal, says Wilson da Silva.

IT’S BEEN THE MISSING LINK in the world’s electricity system for more than a century. And now, energy storage one of the hottest areas of research and investment in the world.

In the United States, power from renewables like wind and solar have risen eight-fold in a decade, with solar power alone seeing a 43-fold rise. This has been followed by a 20-fold increase in large-scale, utility-grade battery storage – like the 20 megawatt (MW) storage plant built in California’s Mira Loma, about 65km outside of Los Angeles, which uses lithium-ion batteries manufactured by Tesla.

This had been the world’s biggest lithium-ion installation – until the South Australian government announced in July that it had contracted Tesla to build a 100 MW facility at Hornsdale’s 99-turbine wind farm, to store energy during peak generation hours, and make it available consistently throughout the day when the electricity grid most needs it.

“Battery storage is the future of our national energy market, and the eyes of the world will be following our leadership in this space,” Premier Jay Weatherill told a news conference announcing the plant, which is scheduled to be completed by December 2017.

“This is a grassroots revolution. It’s driven by billions of people wanting their smart phones and laptop computers to last longer between charges.”

Although a nascent technology, the global market is already worth US$2.7 billion and projected to grow to US$26.1 billion by 2022, according to industry analysts P&S Market Research in New York. IHS, another analyst, forecasts storage to “explode” from an annual installation of 6 gigawatts (GW) in 2017 to over 40 GW by 2022. This compares with just 0.34 GW installed between 2012 and 2013.

Why the boom? It’s partly because of “stunning improvements in battery capacity and cost,” says Australia’s Chief Scientist, Dr Alan Finkel, noting is his speech at the National Press Club in June how the technology for batteries has advanced at breakneck speed.

“This is a grassroots revolution. It’s driven by billions of people wanting their smart phones and laptop computers to last longer between charges,” he added. “To meet that market pull, global manufacturers have invested massively to improve the performance and lower the price of rechargeable batteries. Repurposing these batteries has enabled manufacturers to configure grid-scale batteries. These are now being installed internationally at a level and cost that were unimaginable five years ago.”

It’s a revolution that’s been a long time coming. For more than a century, electricity has been generated in real-time for immediate use. While a an incredibly complex systems have evolved to manage generation and distribution, the simple truth is that more electricity needs to generated than is actually used. Hence, there’s wastage and inefficiency, and more emissions generated than would occur if the electricity could be stored.

Until recently, this was solved by building new power stations. But rising energy prices, the falling cost of storage, and a pressure to reduce emissions, capturing electricity when demand is low – and then discharging it to augment peaks in electrical demand – is all the rage.

Battery storage is now less costly, more nimble and easier to site than new natural gas ‘peaker’ plants, which take less time to power up that coal-fired stations and had been the power industry’s preferred way of dealing with demand peaks that are growing feature of grids internationally. “It's tough to find sites that work for peakers in highly urbanised areas,” notes Southern California Edison’s Paul Griffo, whose utility company is planning to bring 104.5 MW storage capacity online by 2018.

The 99-turbine windfarm at South Australia’s Hornsdale, where Tesla has built a battery-storage facility

In truth, storage has been in use in Australia since the 1890s, but has been applied in limited scope. Dams like the Snowy Hydro Scheme are an example: water is stored, and then released gradually to drive turbines that generate electricity. But in a nation short on water and high on electricity demand, dams are a limited solution – although the Turnbull government is exploring a major expansion of the Snowy scheme.

Hydro still accounts for 90% of the world’s existing energy storage, with technologies like compressed air, flywheels and thermal storage also in use. But things are changing fast. Batteries are on the ascendant, with research also taking place on superconducting magnetic storage and fuel cells. And Australian researchers are active in all these fields, with the CSIRO particularly advanced in developing high performance batteries and fuel cells.

Its UltraBattery – an advanced system that combines lead-acid batteries with supercapacitors (like those that power camera flashes) – is an economical, fast-charging battery with long-life power. It is now manufactured by Japan’s Furukawa Battery Company and being tested in a large-scale trial in the United Kingdom, and in rural India by battery manufacturer Exide Industries.

Uniquely, redox flow batteries can also be refuelled by pumping in fresh electrolyte. And once refilled, power is instantly available, and can be varied by controlling electrolyte flow.

Redox flow batteries are another storage technology that is taking off. Like lead-acid and lithium-ion, it contains electrolyte solutions — the fluid that transfers charges inside a battery — and a positive and negative terminal, around which electrons flow when the circuit is connected. Unlike other batteries however, the energy is stored in the electrolytes rather than in solid electrodes, which means the amount of stored energy can be boosted simply by adding more electrolyte.

Uniquely, redox flow batteries can also be refuelled by pumping in fresh electrolyte. And once refilled, power is instantly available, and can be varied by controlling electrolyte flow. This makes them easier to adapt to large-scale applications without adding a lot of cost: you just make the tank bigger. This reduces the cost per unit of stored energy, making flow batteries ideally suited to large megawatt-scale applications that require several hours of stored energy.

There are various designs – zinc bromide, polysuplhides, and zinc-cerium – but it’s vanadium-based batteries that are now most common worldwide, and were pioneered in Australia by Professor Maria Skyllas-Kazacos and her team at the University of New South Wales (UNSW). A 130kWh vanadium redox battery system is installed at UNSW’s Sydney campus, and a 15 MW storage facility was completed in Hokkaido in 2015, located near to Japan’s biggest solar power station: a 111 MW facility in the town of Abira. An even larger, 200 MW vanadium battery facility is now under construction in Dalian City, China.

While lithium-ion batteries are getting a lot of attention as a storage solution, they do have some drawbacks. They lose capacity over time, can overheat and catch fire, last only 7,000 recharge cycles (less than 10 years), discharge only 70% of the electricity stored without damage, a single faulty cell can degrade a whole network, and disposing of the batteries once spent is an issue.

Vanadium, by comparison, doesn’t overheat, lasts at least 25,000 cycles (and up to 100,000), discharges 100% of stored energy without affecting battery life, and the electrolyte can be repeatedly recycled.

Sumitomo Electric has been trialing vanadium redox batteries since the late 1990s

Then there’s cost: the average cost of a lithium-ion based storage system is $1,750 per kilowatt hour (kWh), including cells, electronics, installation and systems expenses. By 2020, Tesla’s planned lithium-ion ‘gigafactory’ could reduce this to $400 per kWh. Vanadium storage systems, on the other hand, already provide energy for $500 per kWh; this is forecast to fall to $300 per kWh in a few years, and could fall to $150 per kWh by 2020.

Solar thermal is another hot new storage technology, and again, South Australia is in the lead: a 150-MW plant is to be built outside Port Augusta, costing $650 million and due to start operations in 2020. It uses a field of billboard-sized mirrors uses heliostats, or sun-tracking mirrors, to concentrate sunlight onto a 227-metre tower that heats molten salt (sodium nitrate and potassium nitrate), which stores the energy.

Known as the Aurora Solar Energy Project, it is to be built by U.S. operator Solar Reserve, it’ll be the world’s biggest solar thermal plant. It will account for five per cent the state’s energy needs, provide between eight and 10 hours of storage and last for 20 years.

“The significance of solar thermal generation lies in its ability to provide energy virtually on demand through the use of thermal energy storage to store heat for running the power turbines,” said Professor Wasim Saman, an energy engineer at the University of South Australia. “This is a substantially more economical way of storing energy than using batteries.”

Wilson da Silva is a science writer in Sydney, and the founding editor of COSMOS magazine.

© 2019-20 Wilson da Silva. All rights reserved.