Storing renewable electricity on the grid of the future (updated for 2023)
***I have updated this post to add more technologies. See here:***
I first published this article in September 2022. Since then, I’ve been made aware of new electricity storage technologies such as CO2 batteries and nickel-hydrogen batteries. I’ve also learned a lot from other people, primarily by discussing energy storage on Twitter (you can follow me here).
I therefore decided it was time to update this article with my latest list of energy storage technologies. It’s got even longer, so I’ve created a summary table with high level pros and cons for each technology:
As a reminder, this article aims to lay out the different electricity storage technologies that may get us to a zero-carbon grid. The list is meant to be closer to exhaustive than selective — I’m not trying to predict which technologies will dominate. As a result, many of these technologies will struggle to make it beyond a demonstration project.
- Pumped hydro (roundtrip efficiency = 70–85%)
Pumped hydro systems consist of two reservoirs or lakes, one at the top of a hill, the other at the bottom. When electricity is abundant and cheap, pumps move water from the lower to the upper reservoir. When electricity is needed, water is released from the upper reservoir, flows through a turbine and returns to the lower reservoir. As the water flows through the turbine it generates electricity.
Pumped hydro is cheap and can be deployed at huge scale. It also has the benefit that you can decouple the energy conversion and storage components of the system. If you want more rapid conversion, you can add more pumps and turbines. If you want more storage capacity you can make your reservoirs bigger. The net result is that each additional unit of storage capacity is likely to be cheaper than the last.
At the end of 2021, there was 2.4 GW of pumped hydro capacity on the UK grid, roughly 20% of the capacity of all the UK’s offshore wind. All of this pumped hydro is capable of storing 26 GWh of electricity, enough to power ~3m homes for a single day. This might seem like a lot of storage, but in reality it’s a rounding error when compared to the UK’s gas storage capacity of 16,500 GWh.
Building new pumped hydro is hard because it requires specific geographical / topographical features (i.e. reservoirs at the top and bottom of hills), meaning it can only be deployed in certain locations. The projects are also vast, meaning that huge investment is needed up front to get the project built. That isn’t to say that people aren’t trying to develop new pumped hydro facilities — for example, SSE has proposed a 1.5 GW / 30 GWh pumped hydro system at the brilliantly named ‘Loch Lochy’ in Scotland. But SSE is yet to work out how to finance it.
In its most optimistic scenario, National Grid predicts that the total amount of pumped hydro in the UK could more than treble to 84 GWh by 2050. This is optimistic, and in National Grid’s most pessimistic scenario it only increases by a third to 34 GWh.
Novel forms of pumped hydro are starting to emerge, with the aim of addressing the geographical constraints on traditional pumped hydro. RheEnergise is aiming to deploy modular pumped hydro systems that use two purpose-built tanks instead of lakes. The tanks can be buried, minimising the impact on local land use and allowing deployment close to where energy is used. RheEnergise uses a fluid called R-19 which is 2.5 times denser than water, meaning you can store the same amount of electricity as a traditional pumped hydro system but with 2.5 times less liquid (and therefore 2.5 times less space). Alternatively, RheEnergise’s High Density Hydro system can store the same amount of energy but on a hill that is 2.5 times smaller than the hill that you’d require with a traditional water-driven system.
RheEnergise’s technology is still at the demonstration phase. In November 2022, RheEnergise was awarded £8.2m by the UK Government (as part of BEIS’s Longer Duration Energy Storage Demonstration Programme) to build its first project in Devon. This project will have capacity of 250 kW / 1 MWh and is expected to be completed by mid-2024. If RheEnergise can achieve costs that are similar to traditional pumped hydro, it would be a welcome addition to the energy storage options available.
2. Lithium-ion batteries (roundtrip efficiency >90%)
Lithium-ion batteries need no introduction. They have the benefit of being modular (i.e. to increase the capacity of the battery above, you can just add more containers). They can be deployed just about anywhere and are very quick to turn up and down, meaning they complement variable renewables well. Lithium-ion battery costs are falling rapidly as production and manufacturing capacity scale up to meet the needs of the automotive sector — Bloomberg estimates that costs have fallen by ~80% in the last 10 years (although there was a small increase in 2022 due to increases in material prices).
Downsides to batteries are that the conversion and storage components are closely coupled, meaning that you can’t add additional storage capacity without significantly increasing costs. This means that it will be too expensive to meet our long duration storage needs with lithium-ion batteries. Lithium-ion batteries also degrade as they’re used, meaning they have a limited lifetime of 8–10 years (although this will almost certainly improve over time).
At the end of 2021, the UK had 1.6 GW of batteries that were capable of storing 1.6 GWh of electricity. The vast majority of these batteries were built in the last five years. National Grid expects the total non-EV battery capacity in the UK to increase by 20–40 times to 26–63 GWh by 2050. Whilst a significant increase, this still leaves batteries far short of the 16,500 GWh in gas storage capacity.
3. Sodium-ion batteries (roundtrip efficiency = ~90%)
Perhaps unsurprisingly, sodium-ion batteries use sodium in place of lithium. Sodium is an attractive raw material to use as it’s several hundred times more abundant in the Earth’s crust than lithium is, making it easier and cheaper to source. Additional benefits of sodium-ion batteries are very low degradation meaning they’ll last longer, and good low-temperature performance.
A downside of sodium-ion batteries is that they have low energy density when compared to lithium-ion (160 Wh / kg compared to 200–300 Wh / kg). This means that batteries of a given capacity are bigger and heavier. This isn’t itself a problem for grid storage as the batteries will be stationary, in a field or warehouse somewhere. However, this low energy density may hinder the uptake of sodium-ion batteries in other use cases, such as smartphones or electric cars. And if production volumes don’t scale significantly, prices are unlikely to fall as far as lithium-ion batteries which are benefitting from a huge expansion.
Sodium-ion batteries have been around since the 1970s but haven’t seen anywhere near the same level of investment or development as lithium-ion. This may soon begin to change as CATL plans to start mass production of sodium-ion batteries in 2023. In addition, in February 2023 the first EV with a sodium-ion battery was announced in China. There seems to be a view amongst analysts that sodium-ion could be suitable for all but the longest range EVs in the future.
UK-based LiNa Energy is developing a solid-state sodium battery using a sodium-metal-chloride chemistry. The battery requires no lithium and no cobalt and LiNa claims that its solid ceramic electrolyte enables a doubling of the amount of energy the battery can store when compared to a liquid electrolyte. It’s also safer, as the solid electrolyte can’t catch fire like a liquid one can.
LiNa’s batteries are not available yet but they claim that they’ll be able to manufacture cells for under $50 / kWh, less than half what you’d pay for lithium-ion cells (which was $120 / kWh in 2022, according to BNEF). It’s too early to say much about LiNa’s technology, so for now we’ll have to watch this space.
4. Metal air batteries (roundtrip efficiency = 45–50%)
Metal air batteries react metal with air in order to release energy (technically, metal air batteries use metal as an anode and atmospheric oxygen as a cathode). Several metals are being explored for use in metal air batteries including lithium, sodium, aluminium, zinc and iron. In theory, metal air batteries can store more energy per kilogram than a lithium-ion battery. To date, technical challenges have prevented them from living up to their theoretical potential.
Form Energy is working on developing iron-air batteries for grid storage. Iron is an attractive metal to use as it’s abundant and has well-developed global supply chains. Form’s iron-air battery exposes iron to air, causing it to rust. As the iron rusts it loses electrons, generating an electrical current. When an electrical current is applied to the battery in the opposite direction, it “un-rusts” the iron, adding the electrons back in and returning it to its original state. Form Energy is still developing its first commercial product (this is expected in 2023) but it is aiming to store electricity for over 4 days and claims that it will be able to do so at 10% of the cost of a lithium-ion battery. Form is expecting a roundtrip efficiency of 45–50% (see Form’s 2020 white paper for more detail) — much lower than lithium-ion but in the same ballpark as current efficiencies for hydrogen storage. As with flow batteries, there’s no risk of thermal runaway meaning that Form’s batteries will be safer than lithium-ion. Whilst it’s still in its early stages, there’s been lots of interest in Form Energy and in 2021 they announced an investment of $240m in a round led by steel manufacturer ArcelorMittal.
Zinc8 Energy is working on a zinc-air battery. Zinc-air batteries have been used for years in hearing aids. But until recently they’ve been single-use — i.e. they haven’t been rechargeable. Zinc8’s solution uses a tank of electrolyte that contains zinc. When power is required, the zinc is reacted with oxygen and water to create a substance called zincate (hence the company’s name). In the process, the zinc gives up its electrons creating a current. The system is charged again by using electricity from the grid to split zincate back into zinc, water and oxygen and storing that zinc in the storage tank until electricity is needed again. In early 2022, Zinc8 announced a project to deploy 0.1 MW / 1.5 MWh of its batteries in a community apartment building in New York. This project will allow storage and overnight use of electricity that has been generated by solar panels on the building.
5. Nickel hydrogen batteries (roundtrip efficiency = ~85%)
Nickel hydrogen batteries are like a cross between a battery and a hydrogen fuel cell. As the battery is charged, hydrogen is produced and stored in pressure vessels. As the battery is discharged the hydrogen is consumed, reacting with the nickel.
Nickel hydrogen batteries were originally developed by NASA for use in space (e.g. in the Hubble Telescope and Int’l Space Station). They’re suitable for this application as they have a long lifespan with minimal degradation, require little to no maintenance, cope well in harsh environments (i.e. very high or low temperatures) and have no risk of thermal runaway and fire. The challenge until recently has been that they’ve been very expensive.
This has changed thanks to the work of a team at Stanford, now a spin-out called EnerVenue. EnerVenue has reduced the cost of nickel hydrogen batteries by replacing the platinum electrode and ceramic separator in the original NASA-developed batteries with lower cost components. Even at this lower cost, EnerVenue claims that their nickel hydrogen batteries have a 30-year / 30,000-cycle life with no degradation, no fire risk and no temperature limits. Newer systems also have roundtrip efficiencies of 85%, not far off lithium-ion.
Whilst still early stage, EnerVenue has attracted $100m in funding from big players in the energy industry including oil and gas giant Saudi Aramco and oilfield services company Schlumberger. EnerVenue plans to build a gigafactory in the US which it hopes will enable it to bring battery costs down to $100 / kWh (there’s even talk that they might be able to get costs down to $30 / kWh but this feels like a stretch).
The question will be whether EnerVenue can secure initial orders that drive sufficient volume and allow it to start moving down its learning / cost curve. Early signs are promising: in May 2022 EnerVenue announced an agreement to supply 2.4 GWh of storage systems for Pine Gate Renewables in the US. And in September 2022, it announced an agreement to supply 250 MWh of its storage solution to Green Energy Renewable Solutions between 2023 and 2025.
6. Liquid metal batteries (roundtrip efficiency = ~80%)
The technology behind liquid metal batteries was initially developed at MIT and involved using molten metals of different densities, meaning that they naturally separate on either side of a liquid electrolyte (see image below where metal A is less dense, metal B more dense).
As the battery charges and discharges, metal ions flow through the electrolyte from one electrode to the other. Charging the battery causes the negative electrode to get thicker, while the positive electrode gets thinner. When the battery discharges the reverse happens. Everything being liquid is a benefit as the changes in size aren’t a problem. The battery components continue to take the shape of the container.
The benefits of this technology are primarily linked to the fact that all the key components are liquid.
- Manufacture is simple— the right materials can in theory just be added to the container and heated to the operating temperature. The densities of the materials will mean they separate out into 3 distinct layers, no separators or membranes required.
- Degradation is very low — the liquids take the form of the container, meaning there are no physical stresses on the system.
- Storage can be decoupled from conversion — to increase storage you just need a bigger container and more metal for each electrode.
The key downside of this technology, is that to keep the metals liquid, the cells have to be maintained at ~400–700 C. This uses up some of the energy stored in the battery, reducing its efficiency and limiting the duration that energy can be stored for.
In 2010, a company called Ambri spun out of MIT to continue developing this technology. Ambri’s first commercial battery cell uses a negative electrode of liquid calcium alloy and a molten salt electrolyte. Ambri has done away with the liquid positive electrode, instead using solid antimony (a shiny silver metal, produced primarily in China). When the battery is discharged, the calcium alloy negative electrode is consumed entirely and then regenerated when the battery is charged.
Ambri’s battery systems are modular, deployed in containers with capacity of up to 1 MWh. The systems contain heaters and require a full charge and discharge every two days to maintain their operating temperature of 500 C.
The choice of electrode materials is partially cost-motivated — Ambri claims that their electrode materials cost roughly one third of the materials required for a typical NMC (nickel, manganese, cobalt) lithium-ion battery. In addition, they state that “the manufacturing of Ambri cells is far simpler and requires 1/3 to 1/2 the capital expense per MWh of production than lithium-ion”. Finally, Ambri claims that their cells are safer than lithium-ion as there’s no risk of thermal runaway, combustion or explosion.
Ambri expanded its manufacturing facility in June 2022, increasing its manufacturing capacity to 200,000 cells a year. In September 2022, Ambri announced that it had commissioned one of its battery systems at a Microsoft data center.
7. Flow batteries (roundtrip efficiency = 65–85%)
A flow battery can also be thought of as a cross between a battery and a fuel cell. Unlike a lithium-ion battery, which stores energy by moving lithium ions around within the battery cell, a flow battery stores energy in two separate liquid electrolytes which are themselves stored in tanks. When a current is applied to these electrolytes they are ‘charged’ — one electrolyte passes electrons to the other. And when these electrolytes are pumped through the battery cell on different sides of a special membrane, the electrons are passed back, generating an electrical current.
Flow batteries that are commercially available today typically use a vanadium chemistry. New chemistries that use more abundant materials are being developed in order to reduce capital costs — for example, ESS Inc. is developing an iron flow battery.
A key benefit of flow batteries is that the conversion and storage components are decoupled — you can expand the amount of energy that you can store simply by making the tanks of electrolyte bigger. This means you can deploy flow batteries initially with a small storage capacity, and then expand their total storage capacity at low cost as they demonstrate their usefulness (ESS Inc. estimates the cost of incremental storage capacity at less than $20 / kWh).
Flow batteries don’t suffer from degradation in the same way lithium-ion batteries do, meaning they have a longer life (Invinity claims zero degradation after 25 years and unlimited cycling). They also see minimal ‘standby’ losses — e.g. loss in charge level when not in use. Flow batteries are safer than lithium-ion — they’re non-toxic, can operate in a wider range of temperatures and don’t suffer from thermal runaway, meaning they won’t cause the types of fires that have been seen with lithium-ion batteries (although these are rapidly reducing in frequency).
The key downside of flow batteries is their lower round trip efficiency — for every 100 units of electricity put into a flow battery, you’ll only get 65–85 back out again, compared to ~90 for lithium-ion.
Estimates suggest that in 2021, 1.1 GW of flow batteries had been deployed globally (source). This is lower than the 1.6 GW of lithium-ion batteries deployed in the UK alone and it’s unlikely that flow batteries will ever surpass lithium-ion as the dominant form of electrochemical storage. But if scalability and cost effectiveness can be demonstrated, then we may see significant growth in their deployment, especially in use cases requiring multiple charges and discharges each day.
In the UK, a 5 MWh flow battery (big enough to power ~600 homes for a single day) has been deployed as part of the Oxford Energy Superhub, alongside a 50 MWh lithium-ion battery. According to a press release, “since the flow battery does not degrade with use and can cycle indefinitely, it performs much of the ‘heavy-lifting’ required from the system while reducing wear on the lithium-ion battery”. What this means in practice, is that the flow battery will respond to smaller power fluctuations and charge or discharge all its power before the lithium-ion battery is called upon.
8. Compressed air energy storage (roundtrip efficiency = 60-70%)
CAES uses high pressure air to store energy. A CAES system is ‘charged’ by compressing air and pumping it into a large tank or, where you can find one, an underground salt cavern. When electricity is needed, the high pressure air is slowly released and used to drive a turbine. It’s a bit like blowing up a balloon and then using that comes rushing out again to generate electricity.
Compressed air electricity storage hasn’t been tested at meaningful scale yet, but the expectation is that if you can get access to a suitable salt cavern, it’ll be cheap. This is largely down to its simplicity and the fact that, apart from the salt cavern, it uses off the shelf components (e.g. compressors, pumps and turbines). It also benefits from the fact that the conversion and storage components of the system are decoupled (although the total storage capacity will be dictated by the size and maximum pressure of the salt cavern). Finally, the lifetime of a CAES project could be as long as 50 years — spreading capital costs over a period this long could allow a very low levelised cost of storage.
A key concern for CAES is safety — storing anything at extremely high pressure is always a risk, and even more so at the scale that CAES will operate at. A weakness or fracture in a tank or salt cavern could lead to a rupture which could be explosive. Tanks and salt caverns will need to be inspected and tested on an ongoing basis to ensure this doesn’t happen.
A key player in CAES is Hydrostor, who commissioned a demonstration project in Toronto in 2015. This project stores air in storage vessels 180 feet below the surface of Lake Ontario and demonstrates that off the shelf components can be used in a CAES system. Hydrostor’s Goderich project in Ontario claims to be the world’s first commercial CAES facility and is capable of storing 10 MWh of electricity (enough to power 1,200 UK homes for a single day). The project is storing electricity from the grid and providing peaking capacity and ancillary services to Ontario’s electricity system operator. Hydrostor has several utility scale projects in development globally, including one in Cheshire which is being developed in partnership with EDF and with funding from the UK government. This project will store compressed air in a decommissioned gas storage site. Hydrostor also announced in January 2023 that it had signed an offtake agreement for a 500 MW / 4,000 MWh project in California. This project is expected to be online by 2028.
China is also deploying CAES. A 100 MW / 400 MWh project started operating in October 2022 — this is not only the largest CAES facility in the world today, but also the most efficient, with a claimed roundtrip efficiency of 70%. In total, China has 9 CAES plants either in operation or under construction. Two of these plants store compressed air in salt caverns, the rest store it in tanks. In addition, China has 19 CAES sites in planning, with a combined capacity of 5.4 GW.
There are also longer duration projects in the works — Apex CAES is developing a facility in Texas that will be able to supply power for 48 hours. This facility will have a capacity of 324 MW / 16,000 MWh and is expected to go live in late 2025. Apex CAES is aiming to “enable time-shifting of renewable energy production from low-demand to high-demand periods” (Texas has ~30 GW of wind power capacity).
CAES’s low projected cost and its ability to store electricity for long periods of time mean that it could be an interesting part of the storage mix in the future electricity system. The big question is the total achievable scale. Given the salt caverns that are required are, by their nature, limited in number, will we have enough suitable salt caverns that wouldn’t be more productively used for other purposes, e.g. storing hydrogen? And if there aren’t enough salt caverns available, is it possible to store compressed air in tanks at sufficient scale?
9. Liquid air energy storage (roundtrip efficiency = 40–70%)
Liquid air, or cryogenic, electricity storage (LAES) is similar to compressed air electricity storage in that it involves compressing air. LAES uses electricity to cool air down to temperatures below -200°C, so that it turns into a liquid. This liquid is then stored in a double-walled tank — basically a giant thermos flask that contains cold air, rather than hot tea. Because LAES involves chilling the air in order to reduce its volume, high pressures aren’t required. To extract electricity from a LAES system, the liquid air is heated so that it becomes a gas again and the pressure that is created is used to drive a turbine.
LAES likely won’t be as cheap as CAES but it is projected to be cheaper than lithium-ion batteries for longer duration storage (although this analysis was done by Highview Power who you’ll hear more about below). A key additional benefit of LAES is that, similar to a battery, it can be deployed anywhere that there’s a grid connection — no salt caverns or mountain lakes required.
Highview Power’s demonstration site in Pilsworth, near Manchester, entered operation in 2018 after receiving £8m in funding from the UK government. The site is able to store 15 MWh of electricity as liquid air and can participate in wholesale markets as well as providing frequency regulation services to the grid. Highview has two commercial projects in development in the UK — the larger of the two is a 200 MW facility located in Yorkshire that is capable of storing 2.5 GWh of electricity, enough to power more than 300,000 homes for a single day. Highview has plans to deploy 18 sites across the UK, located to take advantage of existing electricity grid infrastructure.
Roundtrip efficiency remains an open question for LAES. Highview Power claimed that efficiencies of 60–70% would be possible in a 2017 paper; however, I’ve been unable to find any mention of actual data from their demonstration plant (and I assume they’d be shouting about it if it was impressive) and a 2021 paper suggested a theoretical efficiency of 40–47%.
10. CO2 battery (roundtrip efficiency = ~75%)
A CO2 battery uses carbon dioxide to store energy in a way that seems to meld elements of liquid air energy storage (LAES) and compressed air energy storage (CAES). Instead of air, it uses carbon dioxide.
CO2 battery technology is being developed by Italian company Energy Dome. When electricity is abundant, it is used to power pumps and compressors that take gaseous CO2 from a low pressure tank (or dome) and store it in a second tank as a liquid at very high pressure. In this way, the system is “charged”. When electricity is needed again, the CO2 is evaporated and expanded. The pressure created is used to drive a turbine that generates electricity.
Energy Dome argues that CO2 is a better medium than air for storing electricity. The CO2 battery “has the same benefits of LAES and CAES (high energy density and storing energy at ambient temperature, respectively) but without their associated drawbacks relating to efficiency, cost and site dependency”.
Energy Dome’s CO2 battery uses off-the-shelf components that can be sourced through well-established supply chains. The technology doesn’t rely on elements like lithium and cobalt, nor does it suffer from degradation like a lithium-ion battery. Energy Dome claims a roundtrip efficiency of “above 75%”.
Energy Dome’s CO2 battery is still in its early stages. In June 2022, the company announced the launch of a demonstration project in Sardinia. This 2.5 MW facility is capable of storing 4 MWh of electricity (enough to power 500 homes for a single day). In partnership with Italian energy company A2A, Energy Dome is working on a 20 MW / 100 MWh project to be deployed on the Italian grid. Energy Dome expects to have completed this plant by the end of 2023. More recently, Energy Dome announced that it is working with Danish renewables giant Ørsted to assess the feasibility of a 20 MW / 200 MWh project. This project would be delivered in continental Europe with construction starting in late 2024. Assuming this first project is delivered successfully, Ørsted and Energy Dome have left open the possibility of deploying multiple facilities across Europe.
11. Hydrogen (roundtrip efficiency = 40–66%)
Hydrogen is one of the topics in energy with the most hype surrounding it, some of it definitely misplaced (e.g. in the case of hydrogen cars or hydrogen for heating). Could it prove to be helpful in long duration storage though?
When electricity is abundant, it can be used to run an electrolyser and split water into hydrogen and oxygen. The hydrogen can be stored for long periods, either in large tanks or in underground salt caverns. When electricity is required, hydrogen can be burned in an adapted gas turbine (in the Netherlands Mitsubishi is working to convert a gas plant to run on hydrogen) or can be used in a fuel cell — in both cases the end result is electricity and some heat.
In hydrogen storage systems, the energy conversion and storage steps are decoupled — to store more energy you need bigger tanks or salt caverns. And once created, hydrogen can be stored for long periods of time. However, lots of energy is lost during the conversion steps — i.e. during electrolysis and in a fuel cell — meaning that today hydrogen storage has a low roundtrip efficiency, making it an expensive option.
The key question is whether electrolyser and fuel cell efficiencies can improve enough, and equipment costs fall enough, to make hydrogen competitive. I‘m optimistic for both of these — hydrogen will be required for many other use cases (e.g. fertiliser, shipping, maybe even aviation) and therefore it should achieve the scale needed to drive real innovation and bring down costs.
For a deeper dive into hydrogen storage, see this article:
12. Gravity storage (roundtrip efficiency = 80–85%)
Pumped hydro is a form of gravity storage. You move water up a hill so that its gravitational potential energy increases. When you need electricity again, you allow that water to run downhill, converting its gravitational potential energy into electricity in the process.
More generally, gravity storage systems are ‘charged’ by using electricity to lift a heavy object and then ‘discharged’ by allowing that object to drop and generate electricity as it falls.
Other forms of gravity storage involve raising and suspending heavy objects using cranes. When electricity is abundant, you can run motors to raise a heavy object (e.g. a concrete block) increasing its gravitational potential energy. When electricity is required, you can lower this concrete block and drive a generator in the process. Two notable companies working in this space are Gravitricity, who is suspending weights within decommissioned mine shafts, and Energy Vault, who is building cranes that raise concrete blocks from the ground.
Whilst these have the appearance simple, neat solutions, and have roundtrip efficiencies of 80% (according to Energy Vault), I’m not convinced that they’ll ever be able to store meaningful amounts of electricity and therefore will be limited to applications that require bursts of power for short periods only.
Only time will tell. In September 2022, Energy Vault announced plans to build 5 storage projects in China with total capacity of 2 GWh — a lot of storage. However, another announcement in the same month makes me wonder whether they’re giving up on gravity storage and are instead focusing on good old lithium-ion batteries.
13. Flywheels (roundtrip efficiency = ~90%)
Flywheels are heavy, spinning disks. When electricity is abundant, a motor accelerates the flywheel to a high speed. The weight of the flywheel means there’s momentum to keep it spinning. When electricity is needed, the flywheel is used to drive a turbine.
Flywheels are a simple solution and therefore don’t require any expensive or scarce raw materials, nor do they degrade over time. They also have roundtrip efficiencies of up to 90%. However, flywheels are incapable of storing large amounts of electricity, instead they’re only able to soak up / deliver short bursts of power.
The world’s largest flywheel energy storage system is located in New York state and is made up of 200 individual flywheels. It has theoretical capacity of 20 MW capacity but more typically will deliver less power than that for an extended period of time — e.g. 1 MW of power for 15 minutes.
14. Supercapacitors and ultracapacitors (roundtrip efficiency = 85–98%)
Supercapacitors and ultracapacitors are similar to batteries in that they contain electrodes and an electrolyte. However, they make use static electricity rather than electrochemistry to store energy.
Supercapacitors and ultracapacitors are proven technologies that have an almost infinite cycle life with no degradation and requiring no maintenance. They’re also able to respond very quickly and deliver high powered output.
The downsides are similar to flywheels — supercapacitors and ultracapacitors are not able to store large amounts of energy (a typical cell can store less than 10 Wh, although they can be stacked up to allow storage of more energy). This means supercapacitors and ultracapacitors are likely to be used in applications that require them to soak up / deliver very short bursts of power (maybe as short as seconds). They will potentially be used in hybrid solutions — the supercapacitor or ultracapacitor provides the rapid response but only for a very short duration, while a battery provides the sustained response.
15. Thermal storage (roundtrip efficiency TBC)
Thermal storage involves making something very hot or cold and keeping it that way until heat or cooling is required. Stored heat could, in theory, be used to create steam to drive a turbine. In reality, thermal storage is likely to provide heat or cooling directly as an output. Whilst this isn’t ‘electricity storage’ as I’ve been defining it (i.e. electricity in and electricity out) it would support decarbonisation of heating or cooling by shifting electricity use to periods when there’s excess renewable energy. Think of it as a modern day storage heater but with the ability to work at an industrial scale, as well as in the home.
Heat can be generated in a thermal storage system using a resistive heater (like the element in a kettle), using a high temperature heat pump or by concentrating sunlight using curved mirrors. Different technologies use different materials to store the heat, including molten salts, concrete, metals, sand or rock. These materials will be insulated to ensure that the heat is retained for as long as possible.
A recently deployed example of thermal storage is the ‘sand battery’ that was developed by Polar Night Energy that went live in Finland over the summer. This sand battery uses resistive heating and stores heat at 500°C for months at a time. The heat is used as needed in a local district heating system. It’s unclear at this point whether the sand battery is a research project or whether we’ll see more of them deployed commercially.
At the scale of the individual home, thermal storage can be as simple as using an immersion heater to heat water in a tank when renewable electricity is abundant and cheap. This hot water can then be used for as long as it stays warm. Companies such as Sunamp and Tepeo are trying to make heat storage smarter. Both offer ‘heat batteries’ that store heat in proprietary materials. These heat batteries require less space than a boiler and water tank and are able to provide heat for space heating as well as hot water.
It’s unclear whether this sort of technology will take off. Why would you store heat that can only be used efficiently for heating , when you could store electricity that could be used for whatever is needed at the time?
On the cooling side of things, ice storage can be used to store ‘coldness’. When electricity is cheap — e.g. overnight —chillers are run and a working fluid is cooled to below freezing. In the daytime when temperatures rise, and when demand on the grid causes electricity prices to spike, the chilled fluid can be used to create cold air for air conditioning. In the simplest case, the working fluid could be water, with ice created and stored until cooling is needed. In more advanced systems, fluids such as glycol (antifreeze) are used to allow the working fluid to remain a liquid even at temperatures below freezing. Waste heat (i.e. the heat taken out of the working fluid as it is cooled) can be captured and used for hot water or heat requird in industrial processes.
Further Reading
- The original article [contains a brief attempt to pick winners]
- McKinsey: Long duration energy storage for a renewable grid
- David Cebon: Technology for large scale electricity storage
- Projecting the Future Levelized Cost of Electricity Storage Technologies
- EnerVenue raises $100M to accelerate clean energy using nickel-hydrogen batteries
- Ingenia: A new contender for energy storage [deep dive into LAES]
- Rusty metal could be the battery the energy grid needs [deep dive into metal air batteries]
- Form Energy: Solving the Clean Energy and Climate Justice Puzzle
