Keeping the lights on: seven energy storage technologies to brighten our future
Image credit: Dinorwig power station
As renewables spread, we need storage technologies to cache their energy. Here are the seven most promising.
The big problem for renewables is that they do not produce energy when the grid needs it. Big seasonal and daily fluctuations make wind and solar an erratic resource that, at times, can produce more energy than the grid can use. But if that energy can be stored, it need not go to waste. In many cases, the energy need only be cached for a few hours so that it is delivered in the evening or at night – and avoid the need to turn on gas generation at night. So the race is on to find economical energy-storage technologies.
Which storage technologies get picked will be influenced as much by the economics of grid operation as by their relative efficiencies and costs. Storage options include huge systems that use the landscape itself for potential energy, such as the Dinorwig pumped-hydroelectric plant in North Wales, supporting almost 10GWh of capacity to compensate for problems in the high-voltage electrical transmission network. They scale all the way down to boiler-shaped sub-10kWh batteries for the home or office.
Grid-stability deals will provide incentives for commercial operators to put storage into the core transmission and distribution networks. Owners of industrial and housing estates will be able to supply peak-time electricity back to the grid or simply use the storage to avoid importing energy from the grid (see p38). The options on offer range from batteries packed into containers to technologies that support the evolution into a fully fledged hydrogen-based energy economy.
If there is one large-scale electricity storage technology with a long history of grid-level operation, it’s pumped hydroelectric. It has been operating for so long it is now responsible for one of the biggest regulatory headaches in the developed world: the way that storage is regarded as being part of generating capacity.
In the early 1970s, when the government expected most of its generating capacity to be in nuclear, it ordered the building of what was going to be a series of large-scale storage reservoirs. The pumping station is buried inside a Snowdonia mountain roughly halfway between the Magnox nuclear plants at Trawsfynydd and Wylfa.
Three pumped-hydroelectric stations had already been built, but at under 400MW they were dwarfed by the scale of this plant, with a nameplate generating capacity of 1.7GW.
Dinorwig’s location was almost tailor-made for pumped-hydroelectric storage. A small lake, Marchlyn Mawr, nestles close to its peak above the steep slate-quarry escarpments cut into the Elidir mountain that lead down to the lower reservoir of Llyn Peris. During low usage levels, the pumps transfer the water from the reservoir to Marchlyn Mawr. When the grid needs a boost, the water flows down through the turbines and out into Llyn Peris in the Llanberis pass. The station can run for six hours before it runs out of water.
Although it can boast an efficiency of 75 per cent, the unusual geography of Dinorwig points to one of the key problems for hydroelectric storage. Without changes to the landscape, construction relies on quirks of geography that are not easy to find. The three shortlisted locations identified for what became the Dinorwig project all lay in North Wales. Today, the other plant operating in Wales is Dinorwig’s predecessor at another former slate quarry at nearby Ffestiniog. Another small plant is to be built at another location in Snowdonia: Glyn Rhonwy. The other two working plants in the UK lie in Scotland.
Germany has found another approach: go one step further than Dinorwig and put the entire operation in the ground. The Prosper-Haniel coal mine north of Düsseldorf is set to become a 200MW pumped-hydroelectric plant once the mining operations stop next year.
Despite the problems with finding suitable locations up to now, pumped-hydroelectric is by far the most prevalent form of grid-scale electrical storage. The US Department of Energy’s Global Energy Storage Database reported in spring 2017 that PSH accounts for almost 183GW of worldwide nameplate capacity out of a total of 193GW.
Compressed air energy storage (CAES) uses the same idea as pumped hydro of building up potential energy but with the advantage of being cheaper to construct – just as long as you can find suitable locations. The natural home for CAES is in salt caverns, similar to those found in Cheshire. The caverns are massive and surrounded by rock with very limited permeability to air, making it possible to store compressed air for long periods of time.
Although the effect of pumping compressed air might seem to result in similar adverse effects to fracking – destabilising the surrounding rock – the geology of suitable caverns reduces that risk considerably.
According to a 2015 study by Imperial College and Stanford University, the energy cost of building systems that pump air into geological formations compared to the total energy such systems can store is almost two orders of magnitude better than batteries and is better even than pumped hydroelectric.
The big problem for cavern-based CAES is that competition comes from another energy source, natural gas, as well as a likely future supply of hydrogen. Those same caverns are as suitable for stockpiling flammable gases as air – although the flammability does lead to protests against the technique.
Even so, the Energy Technologies Institute claimed last year that some 30 caverns were being used for natural-gas storage in 2016 as it kicked off a project to look at the feasibility of hydrogen storage.
Forcing the air into metal canisters incurs a higher capital cost but removes the need to scope out suitable locations that are already in short supply. It also makes CAES more suitable for microgrids and widely distributed storage. But that brings into question the capital and long-term maintenance costs against flywheels and batteries as well as overall energy efficiency.
Packed into a row of 20 containers, start-up UniEnergy Techology (UET) installed the second of the largest battery of its type the company has made so far in a town 15 miles north of Seattle. The 8MWh battery array uses a different approach from the near-solid batteries favoured by Tesla and many of the other storage suppliers. The UET design is a flow battery that its maker claims lasts longer and is safer than conventional lithium-ion designs.
The battery in Snohomish, Washington, will not be the largest for long. China has ordered another set of containers from UET and partner Rongke Power to create an 800MWh battery for the Dalian peninsula in the north of the country.
Until grid storage emerged as a viable market, flow batteries were rare because they call for the electrolytes to be pumped around the system. Most batteries can rely on ion pressure to move the chemicals around as they charge and discharge, so are far less bulky than their pumped cousins. In a flow battery, there are generally two separate tanks with their own pipework separated by an electrode and membrane sandwich that allows ions to pass from one side to the other.
Like others, UET favours a chemistry based on an electrolyte that uses vanadium ions to store charge. Such designs suffer from the membranes being poisoned by contaminants over time, but nearby research lab PNNL came up with a molecule carried in hydrochloric acid that runs more cleanly. Israeli company EnStorage favours a solution based on hydrogen and bromine.
Although the flow batteries show potential, storage providers are likely to view lead-acid and lithium-ion batteries as being more commercially viable simply because of the scale of their non-grid markets. Flow battery makers are mostly start-ups, which may prove a problem for longevity.
In today’s world, the sealed battery looks to be the most obvious choice for large-scale electrical storage. The grid on the remote Scottish island of Foula, lying 20 miles west of the Shetlands, today runs on a combination of solar and hydroelectric power, with a bank of lead-acid batteries used to ride out the peaks and troughs. Not very different from car batteries, they are easy to swap out and replace when they finally lose their ability to hold a charge.
As storage needs ramp up in the home and for grid use, installers are looking at batteries with much higher energy density and so have turned to the same lithium-ion chemistry used in tablets and smartphones. Having built a car around panels packed with lithium batteries, Elon Musk’s PowerWall takes advantage of the economies of scale built up by large-scale battery manufacturing at Tesla. In the UK, Moixa Technology has already seen hundreds of its lithium-battery Maslow units fitted in homes.
For industrial users, companies such as Eaton favour lithium-ion batteries because of their economics of scale and the supply security they bring. They are able to buy in batteries from manufacturers ranging from car maker Nissan to consumer-products giant Samsung. Although short-term materials shortages – particularly cobalt for the electrodes – will be exacerbated by demand from the electronics industry, the battery manufacturers themselves are well established.
The big problem for most sealed batteries comes in terms of toxicity – some sites cannot have large quantities of a lead-acid mixture lying around – or flammability. Large-scale lithium-ion storage systems need to be accompanied by automated firefighting systems. Alternative chemistries such as zinc-air may prove to be cheaper over the long-term but they will face similar concerns over supply and maintenance to flow batteries.
It may at first seem to be a blast from the past, but for hospitals and telecom companies the flywheel has been a popular choice of uninterruptible power supply (UPS) for decades because it is so reliable. One of the big problems historically with battery-based UPS is their propensity to fail just at the point they are needed. The flywheel just keeps spinning – it would take a major electrical failure for it not to kick in. It needs minimal maintenance even over decades. The big problem with flywheels lies in their stamina – they are usually sized to keep spinning only long enough for a backup generator to get going.
The idea of the flywheel may seem old-fashioned compared to batteries and hydrogen production, but there are opportunities to make the concept more attractive. One option lies in transport, with flywheel cylinders sitting alongside tram stops to cache braking energy ready for when the carriages move again.
Although you might expect flywheels to be made from lumps of steel, manufacturers have moved to lighter materials such as Kevlar because these can withstand the intense forces needed to maintain high rotation rates. Carbon-fibre materials can push speeds up to 100,000rpm. Steel flywheels have a tendency to shake themselves apart from internal resonances if run too fast.
Stornetic spins its carbon-fibre and plastic columns at up to 45,000rpm inside a vacuum on magnetic bearings to reduce the friction that saps most flywheels of their kinetic energy. In 2015, Japanese researchers turned to superconducting magnetic bearings to build a huge 100kWh flywheel.
Although invigorated by the demand for electrical storage, the flywheel market has seen casualties. US start-up Velkess came up with a novel gyroscope-like solution, but the company found itself unable to raise enough funding to bring the technology to production.
Instead of compressing air into a smaller space, why not cool it and convert it all the way to a much denser liquid? Early 20th-century inventor Hans Knudsen thought it might power horseless carriages but his Liquid Air Car Company did not last long.
The idea of powering vehicles using liquefied gas has re-emerged in parallel with efforts to use the concept for grid storage. Last year supermarket Sainsbury’s started a small trial on one of its refrigerated trucks with an engine designed by British inventor Peter Dearman. It runs on liquid nitrogen, which makes up nearly 80 per cent of natural air and is readily made as a byproduct of liquid oxygen.
Liquid air energy storage (LAES) is a technique that can exploit symbiotic relationships with power plants. Specialist supplier Highview first built a pilot plant that ran from mid-2011 to the end of 2014 next to the 80MW biomass plant in Slough before being moved to Birmingham’s Centre for Cryogenic Energy Storage. A second pre-commercial plant has been built next to a landfill-waste converter near Manchester. One of the proposed advantages of LAES is that it works well close to plants that generate plenty of heat. As well as biomass and gas generators, steel mills provide the kinds of thermal gradients needed to help drive the heat exchangers that perform cryogenic cooling.
Alternatively, you can go in the other direction and use the generated energy to heat up solid chunks of salt. Although both techniques look more exotic than most of the other energy-storage technologies, they can make sense in environments where you have access to more than just electrical energy. Solar arrays based on concentrators generate extreme temperatures that can be harnessed by thermal generators and storage units, retaining the energy until it can be released – usually at night after photovoltaic generators have shut down.
Most of the electrical-storage technologies designed for the grid assume a closed-loop system. But improved technologies for chemical conversion are leading to storage plants providing the fuel for tomorrow’s vehicles instead of simply caching energy in the grid for a few hours or days.
The big theoretical advantage of opening the loop is that renewable energy need never go to waste. The expansion of renewables generation in California, according to the state’s independent grid operator, is likely to lead to as much as 8GW of generation being curtailed – not capturing energy simply because there is nowhere on the network for it to go. Storage in general helps drive down the need for curtailment but a closed-loop system will always wind up full at some point. Creating a fuel that is, hopefully, easy to store, creates a way around ever needing to curtail the output from renewables.
One option is synthetic natural gas. It has the bonus of having access to a ready market, but is hardly a low-carbon option. Although it is a technology in its early days and in need of a new delivery infrastructure, hydrogen production offers a way to create a fuel that does not lead to massive production of carbon dioxide when used.
In 2015, a group of researchers from Stanford University, Imperial College and Western Washington University looked at the overall energy cost of hydrogen production and storage versus batteries – an analysis that took into account the production of the storage systems themselves. The round-trip efficiency of creating and using hydrogen is lower than that of an electrochemical battery. But it takes less energy to produce the equipment needed for a hydrogen cycle.
As storage techniques improve, hydrogen should be cheaper to store long-term and ship around in fuel tanks. The Toyota Mirai fuel-cell car has twice the mass energy density of a battery-electric vehicle.
The large seasonal fluctuation in output for solar, particularly in sunshine states, versus the daily variability of wind means hydrogen production is likely to be tied to big photovoltaic arrays. The Stanford and Imperial study found that the economics tend to work better for solar because it is more likely to be curtailed during seasonal peaks when used only with closed-loop storage.