The state of storage
Renewables such as wind and solar have already proved their ability to match and even beat fossil fuels on a cost per megawatt-hour basis.
The government’s latest figures in August 2020 estimated the levelised cost of energy for the newest and most fuel-efficient H-class combined-cycle gas turbines (CCGTs) at £53/MWh (2018 prices) for projects commissioning in 2025. This excludes £32/MWh of carbon costs, which otherwise raise the figure to £85/MWh.
Meanwhile, onshore wind and large-scale solar are estimated to cost £46/MWh and £44/MWh respectively, with only offshore wind coming in more expensive at £57/MWh.
By 2030, even offshore wind is cheaper than CCGTs at £47/MWh versus £54/MWh, whilst onshore wind and solar have fallen to £45/MWh and £39/MWh. Their leads are only forecast to grow larger over the following decade.
However, these numbers only tell part of the story. Whilst gas turbines can dispatch power as and when it is needed, renewables are intermittent, with their output determined by the UK’s famously capricious weather.
Building a zero-carbon energy system with renewables as the backbone will require storage – and lots of it. It will also need to fulfil a variety of different roles, from matching supply and demand in real time and maintaining the stability of the power grid through to filling large gaps in renewable generation lasting days and weeks and even providing interseasonal storage.
Even more so than with generation, these requirements are likely to be fulfilled by a variety of different technologies, of which there are many. With this in mind, Utility Week takes a look at some of the most promising.
Three of the companies profiled in this report appeared on a special Countdown to COP webinar on 6 May at 10.30am. Watch the recording for free here.
Electrochemical and electromagnetic storage
Lithium-ion batteries are the most prominent storage technology at the moment and the yardstick against which others are measured.
Early prototypes were developed by scientists in the late 70s but it wasn’t until 1991 that the first commercial lithium-ion batteries were launched by Sony. They have since become ubiquitous in consumer electronics such as laptops and smart phones and have emerged as the clear winner in the battle against hydrogen to power the electric cars of the future, thanks in no small part to Elon Musk and Tesla.
Their plummeting costs have also seen them become viable for grid-scale energy storage in recent years, with average pack prices falling almost ten-fold over the last decade from $1,100/kWh in 2010 to $137/kWh in 2020, according to the latest figures from Bloomberg New Energy Finance (BNEF). BNEF expects a crucial tipping point to come in 2023 when average pack prices are forecast to hit $100/kWh, allowing automakers to produce and sell electric vehicles at the same price as comparable combustion engine cars.
Volume weighted average pack and cell prices
The UK’s first grid-scale lithium-ion battery facility was commissioned by UK Power Networks in 2014 at Leighton Buzzard in Bedfordshire as part of an Ofgem-funded innovation project.
But their breakthrough moment came several years later in 2016 when more than 200MW of batteries won contracts in the tender for National Grid Electricity System Operator’s trial sub-second Enhanced Frequency Response service in August of that year and more than 500MW (de-rated) secured agreements in the Capacity Market auction the following December.
Although they were less successful in the subsequent rounds after the Department for Business, Energy and Industrial Strategy (BEIS) reduced the de-rating factors for shorter duration systems, lithium-ion batteries had a resurgence in the latest T-4 auction for delivery starting in 2024/25, with agreements being awarded for 250MW of de-rated capacity.
Figures released by RenewableUK in February showed that 1.1GW of grid-scale battery storage was operational at the time, up from 0.7GW in December 2019. It said 0.6GW was under construction, whilst 8.3GW was consented, 1.6GW was seeking planning permission and 4.5GW was at an early stage of development. This pipeline, totalling 16.1GW, represented more than two thirds of the 22GW of storage capacity that the trade association said was operating, under construction or in planning at the time.
Lithium-ion batteries have a number of strengths, including a high round-trip efficiency that ranges between 80 and 97 per cent depending on the use-case, according to Lazard’s Levelised Cost of Storage report for 2020.
However, they also have several limitations, which will mean they alone will not be enough to take us all the way to a decarbonised energy system.
Lithium-ion batteries suffer from degradation between cycles, requiring careful management to retain their capacity. Lazard put this at between 1.46 and 2.59 per cent per annum on a daily cycle, again depending on the use case.
Production is currently constrained by supplies of lithium which, despite its natural abundance, remain limited. There are environmental concerns over some mining practices and ethical concerns over the mining of other constituent elements such as cobalt. These resource requirements mean that, despite falling costs, they are unlikely to ever be cheap enough to provide large-scale, long-duration storage.
Matt Harper, chief commercial officer at Invinity Energy, claims the technology they are developing – flow batteries – addresses some of these limitations.
In lithium-ion batteries, the storage and delivery of energy are “tightly wound up” within the cell. In flow batteries, these capabilities are separated, with energy being stored in tanks of liquid electrolyte and power being generated in cell stacks through which the liquid is flowed – hence the name.
“What that allows us to do is two things,” Harper explains. “First of all, by separating those two elements from one another we can independently vary the capabilities of the system from both a power and an energy perspective. This is how we can get to comparatively long discharge durations at comparatively low cost, because if you just need more hours of storage, you don’t need to double the entire system, you just double the amount of electrolyte.
“The other thing it allows us to do is, because you’re flowing the electrolyte through the cell stack, you can very discretely control that electrochemical charge and discharge process in ways that are not possible with conventional battery cells. That’s part of how we get the very, very durable high cycle life out of our batteries, because we’re controlling that charge and discharge reaction a lot more discretely than you would see in a conventional battery cell.”
Harper says in some flow battery chemistries, the positive and negative electrolytes are “fundamentally different species” meaning they do still suffer from degradation as they slowly mix together over time. But he says the positive and negative electrolytes in their batteries are essentially the same – both consisting of vanadium dissolved in battery acid – meaning they lose very little capacity over time.
Round-trip efficiency is, however, lower than lithium-ion batteries at around 70 per cent on average.
Harper says these characteristics mean their batteries are well suited to “ultra-high throughput” applications: “There’s no impact of the number of discharge cycles on the performance of this battery. And what that means is instead of looking at applications that might cycle a hundred or two hundred times a year to meet the peak requirements of the electric grid, we can be cycling these batteries two to five a day and still have that long-run performance remain in place.”
He is also confident that vanadium, which is a relatively abundant element, can be supplied in sufficient quantities to meet demand: “There are resources all around the world that are currently not being extracted.”
The market for vanadium is closely tied to the steel industry, with most being produced as a by-product of iron mining and added to steel alloys to strengthen them. It is also a by-product of the burning and refining of heavy fuel oil. “There are tremendous reserves of vanadium sitting in waste piles waiting to be used,” says Harper.
Furthermore, the electrolyte can also be reused: “We’ve taken vanadium electrolyte that has operated for, not decades at this stage, but certainly years in the field. We bring it back into our facility, we test it’s within spec, and then we repurpose into new projects.”
If it is not suitable for reuse, Harper says they have demonstrated that vanadium can be extracted from the electrolyte, meaning there’s “a very high degree or recyclability on top of the reusability.”
Whilst lithium-ion batteries are liable to catch fire following damage or failure, Harper says flow batteries are not subject to the same risk, with the liquid electrolyte more likely to act as an extinguisher.
Harper says the battery systems they currently manufacture are “slightly more expensive on a first cost basis” than equivalent lithium-ion systems but says their greater durability means they are ultimately cheaper on a per-megawatt hour basis over their full lifespan of 20 to 30 years. He also expects to achieve significant cost reductions over the coming years.
Despite emphasising their comparative advantages, Harper believes flow batteries will be a complementary technology to lithium-ion batteries: “If you were to think about what capabilities the two battery technologies are replacing on the electric grid, lithium will do a great job of replacing the spinning reserves that added a lot of grid stability in the past and the peaking capacity that is currently embodied in gas turbines and reciprocating generators.
“Where we step in is to take renewable power and turn it into baseload and that’s something where the levelised cost map just doesn’t work for lithium-ion batteries. They’re just too short a life for that.”
He says they can additionally assist lithium-ion batteries by acting as a buffer within hybrid systems: “That’s a big part of what we’re doing, for example, at the Energy Superhub Oxford with Pivot Power and EDF.
“That battery is a hybrid that includes both vanadium flow and lithium batteries and what our battery is doing is its acting as the first line of response for calls into that plant to discharge power.
“That means that our batteries are going to be responding to those initial calls for power, not once a day or once a week, but two times a day, five times a day or even more, and that’s a duty cycle that would be incredibly damaging for lithium-ion but one that for our technology has zero impact on the long-term life and performance of the battery.”
Like the regular capacitors commonly found on printed circuit boards, ultracapacitors store energy as electrostatic charge at the surface of two separated electrodes.
However, ultracapacitors have a slightly different structure, enabling what’s called “double-layer” capacitance. The electrodes are also made of “activated carbon”, with many small pores that massively increase their surface area to “over 1,500 square metres per gram”, according to Sebastian Pohlmann, vice president of innovation at Skeleton Technologies.
This allows them to achieve higher capacitances, measured in thousands of farads rather than microfarads or millifarads.
Pohlman says lithium ion-batteries still have “up to 30 times the energy density or even more when compared to today’s ultracapacitors”. The ultracapacitors they produce can currently store 7 watt-hours per kilogram, although they are hoping to raise this to 15 to 20.
But ultracapacitors also have a much higher power density, meaning they “you can charge them up in seconds and discharge them in a second”. They suffer from far less degradation, giving them a long lifetime of “over a million charge, discharge cycles”, and have an even higher round-trip efficiency of more than 99 per cent “even with very fast charge, discharge cycles”. These low losses as heat mean “they can mostly get away without cooling”.
He says this lower energy density but higher power density is reflected in pricing, with ultracapacitors costing an order of magnitude more than lithium-ion batteries per megawatt-hour but an order of magnitude less per megawatt.
Pohlman says they therefore excel at delivering frequent, short bursts of power as is often needed for frequency response. He says they are ideally suited to providing synthetic inertia – a form of fast-acting frequency response that seeks to mimic the effects of synchronous generators such as coal and gas plants that contain large spinning turbines rotating in harmony with the frequency of the power grid. Voltage control is another potential use case.
He says ultracapacitors can be easily recycled, can operate at a wider range of temperatures than lithium-ion batteries and are also safer. As with flow batteries, Pohlman says they do not see ultracapacitors as competitors to lithium-ion batteries, “rather a complementary technology that can actually help lithium-ion batteries to be more efficient” when combined into hybrid systems.
To the extent that ultracapacitors can replace lithium-ion batteries, Pohlmann says it is in applications where “batteries are just used because nothing else is there and then they are massively oversized and cost a lot or have very poor lifetimes”.
Chemical energy storage
One of the biggest unanswered questions for the energy sector going forward is how to store energy in sufficient quantities to cover prolonged periods of low renewable output lasting days or perhaps weeks. Graham Cooley, chief executive of ITM Power, believes the solution is to “transform electrons into molecules.”
Although still fairly limited in the power sector, the UK already possesses energy storage at this kind of scale in the form of natural gas packed into pipes, tanks and underground caverns. Converting them to carry hydrogen could allow some of this storage capacity to be retained.
As readers will know, there is a fierce debate at the moment about whether Britain’s gas boilers will be converted to hydrogen or whether heating will be fully electrified using heat pumps. But even in a world of fully electrified heat, hydrogen could still play an important role in the power sector.
Whilst most batteries currently being installed can be filled within an hour or two, Cooley says the proton exchange membrane (PEM) electrolysers his company manufacturers to split water into hydrogen and oxygen can keep storing energy 24 hours a day: “You can leave it on for days, weeks, years if you want, and spill the excess electricity into the gas grid, storing the electricity as molecules.”
“That’s why all of the renewable energy companies are moving to green hydrogen. They’ve all understood the limitations of batteries. They all know they’re good for about an hour of storage and that’s about it and they want energy storage that gives them a new product.
“They can make molecules that they can store and sell to a different industry. Instead of just having one product – electrons – and selling it into the electricity industry, they can now make a storable product and supply to the gas grid.”
Cooley says their electrolysers have an efficiency of around 70 per cent in terms of the power consumed during production versus the energy content of the hydrogen. He says this is “close to the limits” of what’s achievable, although they may still be able to gain a few more percentage points. He says recovering heat from the process can also raise the overall efficiency to 86 per cent.
At the beginning of this year, ITM Power christened a new factory in Sheffield that Cooley says is the “world’s largest,” with a production capacity of 1000MW of electrolysers per year: “The UK government has been trying to put together a plan so it can find a way of funding and encouraging a company to build a battery gigafactory and what it doesn’t realise is it already has an electrolyser gigafactory.”
ITM has also been scaling up the electrolysers themselves. When they first started a decade ago, they were producing 10kW systems. Now they come in 5MW modules, packaged together in 20MW systems.
This has helped bring down costs significantly. Three or four years ago, they were selling at €1,600/kW. Now they are going for €800/kW and ITM are aiming to get to €500/kW by the mid-2020s. Cooley notes that these costs cover the entirety of the system across engineering, procurement and construction.
Among its latest customers are Scottish Power, which recently announced plans to install a 20MW electrolyser system alongside a 40MW solar farm and a 50MW lithium-ion battery at its existing Whitelee onshore windfarm near Glasgow – the host city for the COP26 climate summit.
Another company producing PEM electrolysers is Siemens Energy. The company launched its first lab-scale electrolyser in 2011 and its first commercial system four years later. Its latest 17.5MW system – the Silyzer 300 – was released in 2018.
There are also other types such as alkaline and high temperature steam electrolysers.
Alexander Habeder, head of business development for the new energy business at Siemens Energy, says whilst the technologies all have their advantages, Siemens chose to focus on PEM electrolysers because they ultimately expect them to be the most cost-effective.
He says PEM electrolysers are a “fairly young technology,” with significant potential for cost reductions: “We’re still making the big jumps. The alkaline technology has already existed for a few decades. They’re getting close to the maturity of the technology and their innovations are incremental whereas we’re still going for the big jumps and we’re expecting that our cost cut potential over the next few years will be significant enough to actually overtake all the other technologies”.
He believes these improvements will allow PEM electrolysers to produce green hydrogen at a price that is competitive with so-called blue hydrogen produced using methane reformation and carbon capture: “If we can get competitive for those prices for hydrogen, then we have a very, very solid business case for our customers.”
“I believe, today, that from a technology standpoint and from a market development standpoint, we’re at that point in time where the wind power industry was 20 to 25 years ago,” says Hebeder.
“It took them two decades to get the market penetration where people understand this is not just a dream of a few people that have gone nuts and think it’s a good idea to put a windmill offshore. It has a viable business case behind it, and it helps us in decarbonising our society.”
He continues: “A lot of people believe in it and so do we, and it’s a very interesting piece of the puzzle to really decarbonise our world but it’s only one piece of the puzzle. The electrification use case is still viable for many things and the hydrogen use case is viable for others.”
Siemens Energy is looking to directly integrate its electrolysers into offshore wind turbines alongside its sister company Siemens Gamesa Renewable Energy, whose latest turbine is a true giant, with 108-metre-long blades, a rotor diameter of 222-metres and a generation capacity of up 15MW. The company is developing a containerised 5MW “plug and play” electrolyser system that could be installed on the platforms on which the turbines sit.
Habeder says all of their calculations and estimates have shown that producing hydrogen in this way is cheaper than transmitting the electricity to shore and producing the hydrogen there.
“First of all, the entire electrical infrastructure that is expensive and not easy to install; all of that electrical infrastructure falls away and you replace it the infrastructure of a piping network which is also difficult but not as complicated,” he explains.
He adds: “When you go offshore there’s a lot more space than is on land and if you have a lot more space you can install a lot more of your systems and that’s your way of scaling up.”
And he says installing the electrolysers on the individual turbines themselves, rather than an offshore platform provides greater reliability: “If you have everything on an offshore platform, you have one big system and if that fails that entire system is down for the time of the maintenance or the repair and if you have a windfarm of 40 or 50 turbines and one of these systems has a fault, the other 49 can still keep going and so your output of course is a lot higher.”
Of course, using hydrogen to store power also requires conversion back into electricity for which there are two options.
The first is hydrogen fuel cells, which are still locked in a battle with lithium-ion batteries to become the power source for larger vehicles such as truck and trains. Fuels cells work similarly to electrolysers but in reverse, with types also including PEM and alkaline. They are generally considered to have a conversion efficiency of 50 to 60 per cent, although waste heat from the process can also be recovered.
The other option, and one being explored by Siemens, is hydrogen gas turbines. Erik Zindel, vice president for generation sales for hydrogen at Siemens Energy, says existing gas turbines can already burn hydrogen as a small proportion of their fuel but changes are needed at higher percentages.
He says there are two main issues that need to be addressed when designing a turbine for use with hydrogen, the first being its higher reactivity and flame velocity when compared to natural gas: “That pushes the flame closer to the burner, so the flame is shorter and there is a risk that you get a flashback and that the flame eats itself into the burner and damages it.”
The second main issue is the higher flame temperature: “If the combustion gases are not perfectly mixed, you get local hotspots and that increases the NOx emissions.” Zindel says new burner designs are therefore required for 100 per cent hydrogen.
The pipes feeding fuel into the turbine also need to be changed, with different sizes and materials, as well as the auxiliary systems, including fire protection and combustion monitoring. He says there needs to be a hydrogen detection system and improved ventilation: “Hydrogen is a very light gas. It accumulates at the top so if you have a very small leak of hydrogen, then you get an increased amount of hydrogen concentration at the top of the building, which can quickly evolve into an explosive atmosphere, given a much larger flammability range of hydrogen when compared with natural gas.”
“It’s a very different animal when compared with natural gas which mixed much better with air,” he adds. “And you can also smell natural gas. Hydrogen you cannot smell.”
That said, most of the turbine itself can be kept the same: “Outside of the combustion chamber and the fuel system, there is not really any change require so you can continue to use the compressor; you can continue to use the turbine sector. The generic set up of the gas turbine itself is not an issue.
“Compared with a conventional combined-cycle the changes are small. It’s only a few systems that are affected. The whole water steam cycle is largely unaffected.”
Zindel says new plants can be designed to be hydrogen ready, with relatively little upfront cost, significantly limiting the cost and disruption of future retrofits. Whether retrofits will make sense commercially for existing plants is less clear cut and will depend on their efficiency and remaining lifetime: “It will always be a case-by-case decision”.
Siemens has already begun testing redesigned burners and will start trialling a small 100 per cent hydrogen turbine at a paper mill in France in 2023. Zindel says they expect to be able to run medium and large turbines on 100 per cent hydrogen by the end of the decade, although commercial operation at scale this depends on how quickly the market develops.
For the time being: “Hydrogen is a very expensive fuel when compared with natural gas. With a few exceptions of refineries with surplus hydrogen, there is not really a business case in burning hydrogen today.”
“We expect that over the next 10 to 15 years, most of the green hydrogen will go to the mobility sector and industry sectors like steel, where the breakeven costs of sustainable hydrogen are higher than in the power sector. The large-scale use of hydrogen in gas turbines for re-electrification in the power sector will instead be something we see on a large scale starting in 2035 to 2040, when we really have to go into a deep decarbonisation of the power sector.”
The newest CCGTs can generate power at percentage efficiencies in the low to mid 60s and Zindel says this is also achievable with hydrogen. He says this would result in a round-trip efficiency, from power to hydrogen and back to power again, of slightly below 40 per cent.
Mechanical energy storage
Pumped hydro Storage
Pumped hydro storage works by transferring water between two reservoirs at different heights, pumping it uphill to store energy and releasing it back down to generate. It is currently the largest source of storage in the power sector, providing more than 2.8GW of generation capacity and 24GWh of storage capacity spread across four plants in Scotland that were built from the 1960s to 80s – Dinorwig, Ffestiniog, Cruachan and Foyers.
The round-trip energy efficiency of pumped hydro storage is specific to each plant but typically averages between 70 and 85 per cent.
In October last year, SSE Renewables received consent from the Scottish government to build Britain’s first new pumped hydro storage plant in a generation. The Coire Glas facility, named after the valley which will be dammed to form the upper reservoir, will be able to store 30GWh of energy, with water being dropped by a height of 500 metres to nearby Loch Lochy.
Project director Ian Innes says this is enough to power 3 million homes for an entire day: “You need a lot of batteries to match that capability.”
“This is a big step up,” he adds. “As a single project, it’s very significant.”
Innes says they have planning permission for up to 1500MW of generation, but the exact figure is yet to be finalised. Among other things, it will depend on what kind of support is offered by government.
As a mature technology, Innes says pumped hydro storage is “well-proven” and “very reliable”. Nevertheless, SSE is still aiming to make improvements over the previous generation of pumped hydro by using variable flow speeds and new construction methods enabled by modern tunnel boring machinery. The company expects the round-trip efficiency of the plant to be around 85 per cent.
Construction is currently slated to begin in 2024, with the plant becoming operational in 2030.
Whilst other projects are being developed, the potential for pumped hydro storage in the UK is limited by the availability of suitable locations.
However, one idea being considered is to access storage in neighbouring countries with geographies that lend themselves better to pumped hydro, namely Norway, which research has suggested could build another 20GW of generation capacity in addition to the large amount it already possesses.
The UK’s first interconnector to the country – the 1.4GW North Sea Link – is currently being built by National Grid and Statnett and is expected to be completed later this year.
Gravitational energy storage operates on a similar principle to pumped hydro but using solid weights rather than water.
Miles Franklin, lead engineer at Gravitricity, says the system they are developing replaces pumps with winches: “By lifting the weights, we transfer energy from an electricity grid to the gravitational potential energy of the weights. And then when the energy is needed back, the system runs in reverse, the motors act as generators and then we flow power back to the grid.”
He says their system offers the fast sub-second response times of lithium-ion batteries but without capacity degradation between cycles, meaning that, like pumped hydro, it can be operated for decades.
“The long lifetime and the long cycle life feeds into a low levelised cost of storage,” he adds. “We’re not claiming that we can be cheaper than lithium-ion on day one. That’s not the expectation. But if you have a cycle life which is an order of magnitude larger than lithium-ion, there’s a lot of space there to be more cost effective over the lifetime.”
The company recently commissioned a 250kW demonstrator at the Port of Leith in Edinburgh and is in the early stages of testing. The demonstrator takes the form of an above ground tower, but for commercial plants the company is initially looking to reuse abandoned mine shafts, “which obviously offer a big cost saving because it’s a big existing hole in the ground.”
The amount of energy storage is determined by the mass of the weight and depth of the shaft, whilst the power output is determined by mass of the weight and the speed at which it moves. Referring to a mine shaft at a colliery in Selby they are exploring, Franklin says: “In a 750-metre-deep shaft, if you have a 550-tonne mass, then that gives you a 1MWh system.”
He says different configurations will be suitable for different applications. A system with a heavier single weight would have a higher generation capacity making it better for “short-duration, high-power balancing”, whilst one with multiple smaller weights would have a higher storage capacity making it suitable for “peak shaving”.
One application Gravitricity is particularly interested is the avoidance of grid reinforcement. Franklin gives the example of a new housing development for which the distribution line can provide enough power on average throughout the day but is not sufficient to cover the new peak in demand. In this case, he said “a small amount of energy storage with a long life could be a much cheaper solution than a new distribution line”. He claims lithium-ion batteries would not be suitable for this purpose, needing to be replaced in as few as seven years.
Franklin says there are lots of old mine shafts in the UK but adds that “the massive caveat is that a fairly small number of those are known to be in a good condition for us to consider them as an early system.” He says some have been capped, some are very old or in bad condition and some a filled with toxic water or methane: “Obviously, there’s lots of potential obstacles in a mine shaft.”
It is for this reason that Gravitricity is looking for places like Eastern Europe and South Africa as possible locations for their first storage systems in mine shafts.
Franklin says although “people’s instinct is that sinking new shafts will be astronomically expensive”, their research suggests this is also feasible, although they would need to be shallower at around 150 to 200 metres deep.
He says similar volumes of energy storage could then be achieved by using multiple weights, stacking them at the bottom and then putting them to one side once they have been lifted to the top: “Then there’s the challenge of maintaining continuous output over that period and that’s where we have some specific patents to achieve that.”
He continues: “If you have a single weight system then clearly there’s one lifting system that needs to be able to lift that complete weight. The lifting system – as in the winches and the cables and the motors and electronics – is then a large proportion of the total cost of the system.
“If you want to then double the mass of the system, you double a significant proportion of the cost of the system. But if you just have two weights and don’t double the lifting the system, then there’s a route there to scaling energy much cost-effectively.”
Compressed air energy storage (CAES)
This technology works by compressing air from the atmosphere and storing it an underground cavern. When the energy is needed, the air is allowed to expand, driving a turbine.
The main challenge that arises is the changing temperature of the air during this process. The heat generated as it is compressed needs to be removed before it can be stored safely. This heat must then be returned to the air or replaced before expansion, otherwise the subsequent cooling would freeze the turbine.
Tallat Azad, managing director of Storelectric, says his company is looking at three different solutions to this issue.
The first is to reheat the air using the exhaust from a gas turbine fuelled by either methane, hydrogen or a mix of the two. The air is then used to drive a secondary turbine, which together with the first form a combined-cycle system: “The flue gas that goes to create steam in a conventional combined-cycle gas turbine, we would actually use that to heat the air from the cavern.”
Azad claims this solution, which Storeletric has branded as “H2 CAES” but is more commonly known as diabatic CAES, is expected to have an efficiency of 56 to 60 per cent, with this figure representing the output of both turbines against the electricity used to power the compressor and the energy content of the gas used as fuel.
The second is to store the heat extracted from the air and then return it to the air prior to expansion. Azad says this solution, which he calls “green CAES” but is generally referred to as adiabatic CAES, is expected to have an efficiency of 65 to 70 per cent.
The third solution combines the previous two together into one system. When utilising both, Azad says this “hybrid CAES” is expected to have an even higher efficiency of 75 to 80 per cent.
Two diabatic CAES plants are already operating in Germany and the US, which were commissioned in 1979 and 1991 respectively. Azad says they differ from the solutions proposed by Storelectric in that the compressed air is fed into specially modified gas turbines that have had parts such as their compressor blades removed and heated upon combustion of the fuel. As the turbines do not have to compress air themselves prior to combustion, this increases their efficiency, thereby harnessing the stored energy.
Azad says their solutions not only offer significantly higher efficiencies but also allow them to use unmodified gas turbines, which they can continue to run when stores of compressed air are depleted: “The concept is already proven. All we’re doing is making it better – a lot of more flexible – by using standard equipment.”
When they are not producing power, the gas and air turbines could also be disconnected from the generators and used as synchronous compensators – essentially flywheels – to provide system inertia and voltage support.
Depending on their size, each plant would be connected to one or more salt cavern ranging in size from 100,000 to 500,000 cubic metres. In the case of the hydrogen and hybrid solutions, one of these caverns could be used to store hydrogen, possibly supplied by co-located electrolysers. Azad says a cavern of 350,000 cubic metres could store enough compressed air to generate around 250 to 300MWh of electricity and enough hydrogen to generate 30 to 40 times that amount.
He says the company is currently looking at four possible locations – Cheshire, Fleetwood, Humberside and Teesside: “In all of those cases, and this is really important for sustainability, it’s not our intention to solution-mine new caverns everywhere because re-repurposing existing infrastructure where available is quicker and cheaper and represents a lower carbon footprint. It also generates revenues for the owner of an otherwise stranded asset.”
“The Cheshire one is probably the most likely one for our first plant right now,” he adds. “We’re in the process of trying to secure a lease agreement with EDF that has leased the caverns off Cheshire Salt.
“We’re looking at four caverns right now but there are another four caverns right next door to it and for us to be able to combine those together is quite easily done.”
Thermal energy storage
Liquid air energy storage (LAES)
Liquid air energy storage essentially works the same way as adiabatic CAES, except the air is not only compressed but refrigerated until it becomes a liquid.
Javier Cavada, chief executive of Highview Power, says liquefied air is 700 times smaller in volume and can be stored at atmospheric pressure in tanks. He says the technology is “piggy backing” on the oil and gas industry, using “engineering processes that have existed for decades” and standard “off-the-shelf” equipment, including the tanks, which are already used to store liquefied gas.
He says the efficiency is determined by “the losses of heat and cold across the system, the pumping of the fluids and gas and the rotating equipment,” and range between 50 and 70 per cent, depending on the exact configuration.
Cavada says, whilst there is a small amount of boil off from liquefied air tanks, this only amounts to 0.08 per cent per day: “That means that after one month you don’t really have any tangible loss. With pumped hydro you have way bigger losses due to the evaporation of water.”
Unlike pumped hydro or CAES, liquid air energy storage is not dependent on geography and can be built anywhere.
Highview opened a 5MW/15MWh demonstration project at Bury in Greater Manchester in 2018. Cavada described it as a “complete success”, proving the commercial viability of the technology. The company is now developing its first commercial plant – a 50MW/250MWh facility – at Carrington on the other side of the city, which it expects to start operating next summer.
Cavada claims LAES is the “best technology at scale” as additional storage can easily be added at a later date by installing more tanks, with a “negligible impact” on overall costs. Whilst doubling the generation capacity of the plant to 100MW would raise the price tag by 40 per cent, doubling the storage capacity to 500MWh would only add 10 to 15 per cent: “The reason is the tanks are the least expensive part of the system.”
He believes LAES offers a much better way of filling long gaps in renewable generation than hydrogen – the other main option being considered: “Hydrogen is a very clean gas, but it is difficult to produce, it’s difficult to manage. It’s the opposite to air. Air is easy to find, air is very easy to store, air is totally inert.”
Importantly, he says it is a technology that is ready today: “For grid stability and grid services we cannot wait those decades that are needed.”
“The competition for liquid air is only the combustion technologies, the hydrocarbons that are very competitive but killing us all,” he warns.
“If hydrogen is the technology to enable renewables, then we will have a lot of the fossil fuel companies celebrating big time over the next 20, 30 years.”
Sensible heat storage
Sensible heat refers to energy that elicits a change in the temperature of a substance.
Although there are other options – for example, using heat pumps to store energy in the ground – the most obvious medium for sensible heat storage is water. In 2015, the local district heating company in the Danish city of Vojens opened the world’s largest thermal storage pit – capable of holding 200,000 cubic metres of water – to provide interseasonal storage of solar energy. In the UK, the Coal Authority has been exploring the possible of storing heat within abandoned mines.
However, small-scale heat storage is already commonplace in the form hot water tanks in homes. David White, business development director at Mixergy, says they are seeking to make this storage more efficient and more useful by making them smarter.
White explains that most hot water tanks have a heat exchanger at the bottom, where the coldest water in the tank sits: “But with that comes some penalties for the end user. One of them is if you only need a small amount of hot water, you can’t generate it. You have to heat everything.
“There’s an implied inefficiency in the fact that you have to heat everything even if you don’t need it. And that’s more of a challenge if you got a larger home – say a four- or five-bedroom house. Your hot water cylinder will be sized for maximum occupancy of that property and if there’s only one or two of you at home, you’re heating all of that hot water everyday even if you’re not using it. So that’s one of the problems we’ve tried to solve.”
He continues: “Another problem we’ve tried to solve is how hot water cylinders don’t tell you how much hot water’s inside of them. One of the problems that families and households have is knowing if there’s enough hot water in the tank to do their evening routine. Often they’ll end up boosting the tank unnecessarily just because they’re worried about running out of hot water.”
Mixergy’s tanks instead have a heat exchanger at the top, allowing just the upper layer of water to be heated. A temperature sensor runs down the full length of the tank and when more needs to be heated, a pump draws cold water from the bottom and injects it at the top. White says this cold water “rapidly obtains the surrounding water temperature, which causes that hot water layer to grow and expand down through the tank, pushing the thermocline down, so it means we can boost the tank from 20 per cent full to 30 per cent full and 40 per cent full, all the way down to 100 per cent.”
“The ability to do top-up heating creates a number of really interesting opportunities,” he adds. “One, heating what you need rather than everything means that we can create hot water faster. The Mixergy tank is able to deliver hot water five times faster than a regular tank because we can heat smaller portions.
“Two, we’re able to define for a customer exactly how much water they’ve got and that’s displayed either on the gauge on the side of the tank or on their app. So, the customer can see, I’ve got 13 per cent of a cylinder, that’s not enough to have a bath, I’m going to give it a boost, which is brilliant.”
This also unlocks headroom to store surplus energy, either locally generated or from the power grid: “There’s a lot of Mixergy tanks connected to solar PV systems, and the benefit of that is the customer can heat exactly what they need in the morning. So, say they only have one shower in the morning so they might heat the tank to 20 per cent full, have a shower which might use 10 or 12 per cent of the cylinder, and then they’ve created 90 per cent of a tank’s, worth of cold water available for sinking solar energy into it.
“You’re creating more headroom for local consumption of solar energy, which with a regular tank you can’t do because it has to heat everything at the start of the day because of the way that it’s designed.”
He says most hot water tanks can store between 120 and 300 litres of water, which equates to 8 to 14kWh of energy storage.
The development of the combi gas boilers means hot water tanks are less widespread than they once were, but this trend is expected to reverse with the rollout of heat pumps.
White says Mixergy’s tanks have been designed with this future in mind: “Each Mixergy tank now is what we call heat pump ready. And what that means is that on the front of each cylinder are two spare bosses – or connections – and we have device which we call the heat transfer module which bolts onto those bosses. And the heat transfer module is a plate heat exchanger and a pump. That plate heat exchanger is what would connect to the heat pump’s primary loop and will transfer the energy from the heat pump into the cylinder.”
This module can either be fitted at the factory or added at a later date.
As well as providing benefits on an individual level, White says the smart controls also allow Mixergy coordinate the actions of numerous cylinders and operate them as a “virtual distributed battery”.
“At a macro scale, we do that today,” he remarks. “We offer frequency services through Centrica Business Solutions, which is amazing. I think we’re the only hot water product on the market at the moment, which has National Grid approval to do frequency response.”
Latent heat storage
In contrast to sensible heat, Latent heat refers to energy that is absorbed or released by substance during a change in its state of matter – or phase – without changing its temperature.
Andrew Bissell, chief executive of Sunamp, says that whilst heating up a kilogram of water by one degree Celsius requires approximately one watt-hour of energy, melting ice into water, going from minus one degree Celsius to plus one, requires 80 watt-hours – or 40 times as much per degree.
The heat batteries developed by Sunamp leverage this phenomenon to store large amounts of energy in a small volume using specially designed phase-change materials: “If you think about it that way, that phase change is storing a great deal of energy. And what’s really interesting is when you go the other way – you resolidify the material – you get all the energy back. The only energy you lose is any that went out through the walls of the vessel you’re storing the phase change material in.”
He says people have been trying to do this for a long time, the most notable being the Hungarian-American scientist Maria Telkes, who earned the nickname the Sun Queen through her efforts to, among other things, create an entirely solar powered house in the 1940s using molten salt to store energy: “For three years that worked really well with heat batteries storing heat from the summer sun into the autumn and winter but in the third year the chemistry of the system she was using stopped working.”
The heat batteries developed by Sunamp are primarily composed of the sodium trihydrate acetate – a salt that was already used in chemical handwarmers.
These handwarmers utilise another phenomenon known as sub-cooling, where a substance cools to below its usual freezing point whilst remaining a liquid. This happens because the salt is contained within a smooth plastic bag that offers no seed for the formation of crystals. The bag also contains a small, domed metal disk, which when “clicked” introduces such a seed. The salt rapidly solidifies, releasing heat from the phase change and raising its temperature to its freezing point.
But Bissell says this salt and the other phase change materials available when Sunamp set out to develop a heat battery still suffered from degradation due to the way they crystallized: “They would degrade over a number of cycles from being good on cycle one to not so good on cycle ten to being completely spent on 20 or so and that’s no good. You can’t build a long-lived product when it will only cycle 10 or 20 times.”
To solve the problem, Sunamp enlisted the help of the University of Edinburgh’s School of Chemistry, including Professor Colin Pulham, an expert on crystallization.
Pulham and his colleagues developed a “chemical nucleator” that is “the same shape in crystallographic terms as the sodium acetate trihydrate but which has a higher melting point” and performs an equivalent function to the “clicky disk” in handwarmers. They also developed a polymer solution that acts as a “chemical habit modifier” that ensures the substance crystalizes as the desired salt hydrate and not the anhydrous salt that is responsible for degradation.
He says testing has shown the material can be cycled over 40,000 times, whilst retaining 95 per cent of its original capacity: “And just to put that into context, that’s about 50 years of a two-cycles-a-day hot water application.”
By using phase change materials, Bissell says these heat batteries can provide the same amount of storage as a 210-litre hot water cylinder in something around two thirds smaller: “We can pack 40kWh of storage into an airing cupboard and deliver time shifted space heating”.
He says the cuboid shape of the batteries additionally enables them to use flat vacuum insulated panels, reducing thermal losses.
Sunamp began selling the batteries in 2018 and shipped its 10,000th unit last year. It is aiming to sell another 20,000 to 50,000 over the next year and quickly get to millions by licensing its technology to other manufacturers.
The substance previously described melts at a temperature of 58 degrees Celsius, making it ideal for homes, but Bissell says the company has developed other phase materials with different melting points, ranging from minus 30 to plus 113, for use in other applications: “Our ambition is to work all the way up to the temperatures required for steel, cement and glass so we can address industrial processes as well. Today we’re probably working without about 20 different materials in our portfolio.”
Sunamp is also exploring the possibility of utilising sub-cooling to provide long-duration heat storage. Although this doesn’t make sense over short periods as heat is lost as the material initially cools, once it reaches ambient temperature the losses cease.
Bissell acknowledges that this may never be economically viable for interseasonal storage: “You’ve got a store that gets one cycle a year, so every kilowatt hour in that store has got to be really, really cheap – way cheaper than even the lowest cost I can reasonably project our phase change materials getting to. And then you’ve still got to have a heat exchanger in there and a tank to contain.
“The only examples of interseasonal storage we see in the world are water in either man made ponds or natural caverns. They accept relatively high heat losses of the course of a year because they get a really cheap storage medium – water.
“That said, I think there’s probably an intermediate point where we will see it happen and that’s in the domain of storing between a week and a month and we may need a lot of that because of this thing I think the German call the ‘Dunkelflaute’ – the high pressure in winter when the skies are leaden and the wind doesn’t blow, and we had that this year for example.
“And there you don’t need interseasonal. You need to be able to have a store that you can discharge for a week or two weeks and then recharge when the conditions get better again.”
With this in mind, Bissell says Sunamp is also exploring thermo-chemical storage, which uses reversible chemical reactions to store and release heat energy: “You always want to be able to obsolete yourself and if thermo-chemistry is going to come through and become big, we want to be on the right side of that.”
One thing that becomes clear when looking at energy storage is that, whilst there will be competition within different segments and some may ultimately be unable to carve out a niche, no single technology will be able to fulfil all of our needs. They all have limitations, whether it be efficiency, durability or costs at different scales and durations.
Only in combination will they be able to knit together renewables into an affordable zero-carbon energy system that provides the same reliability as one based around fossil fuels. Exactly what that combination is will emerge over the coming decades.