Storing renewable electricity on the grid of the future
Batteries are going to need some help
***I have updated this post to add more technologies. See here:***
This article follows on from a previous post that explains how we store electricity on the grid today. That article focused on pumped hydro and lithium-ion batteries (along with a brief nod to fossil gas). Pumped hydro and lithium-ion batteries are well suited for storing energy for short periods, up to 8 hours. But neither of them is likely to reach the scale that we’ll need in a power system that is 100% renewable and where energy must be stored for days or even weeks at a time — pumped hydro because it can only be deployed in specific locations (i.e. where there are hills and ideally also lakes), and batteries because they’re too expensive.
Fortunately, a number of new electricity storage technologies are emerging, which can store energy for longer periods. These technologies still need to demonstrate that they can be deployed at scale and at reasonable cost. But as you’ll see below, there are companies working to do just that.
I’ve chosen to focus on technologies that can store energy for at least a few hours. For this reason I don’t consider technologies such as flywheels and super-capacitors. But please let me know in the comments if there’s anything I’ve missed!
Flow batteries (roundtrip efficiency = 65–85%)
A flow battery is a cross between a battery and a fuel cell. Unlike a lithium ion battery, which stores energy within the battery cells by moving lithium ions around, 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.
Other non-lithium batteries
In addition to flow batteries, several other non-lithium ion battery chemistries are being developed. These batteries either have preferable operational characteristics to lithium ion (at least for some use cases) or use cheaper raw materials.
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.
There are several other battery chemistries that are being developed with grid electricity storage in mind. I haven’t had time to research them all, but they include high temperature sodium sulphur batteries (e.g. from NGK) and advanced lead acid batteries (e.g. from GS Yuasa).
Given these emerging battery chemistries are still in their early stages of development, we’ll have to wait for demonstration projects and early commercial deployments to see what might be possible. It’s unlikely that any of them will see meaningful deployment unless they can out-compete lithium-ion on cost. This is a big ask, but might be possible in specific use cases that require the storage of vast amounts of electricity for long periods of time (i.e. weeks or months).
Compressed air (roundtrip efficiency = 50–75%)
Imagine blowing up a balloon. It takes some work on the part of your lungs, but once the balloon is inflated and you let go of it, the balloon will go flying around the room. Compressed air electricity storage (CAES) works like this, but instead of the stored energy powering a balloon, it’s used to generate electricity. The 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 released and used to drive a turbine that generates electricity.
Compressed air electricity storage hasn’t been tested at meaningful scale 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, CAES allows truly long duration storage — once a salt cavern is ‘charged’ full of air at high pressure, it can effectively be sealed shut until electricity is needed.
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’s utility scale facilities have planned charge / discharge capacities of up to 500 MW and can deliver power for up to 8 hours.
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 or sequestering carbon dioxide? And if there aren’t enough salt caverns available, is it possible to store compressed air in tanks at sufficient scale?
Liquid air (roundtrip efficiency = 50–75%)
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 has a similar round trip efficiency to CAES and also uses off the shelf components. It 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.
Hydrogen (roundtrip efficiency = 40–66%)
Electricity can be converted to hydrogen using an electrolyser. Hydrogen can then be stored for long periods, either in large tanks or in salt caverns. When electricity is required, hydrogen can be burned in an adapted gas turbine or can be used in a fuel cell — in both cases the end result is electricity and some heat. I covered hydrogen storage in a previous article, so I’m not going to go into detail here.
In hydrogen storage systems, the energy conversion and storage steps are decoupled — to store more energy you need bigger tanks or salt caverns. 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.
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.
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 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 but if it can achieve costs that are similar to traditional pumped hydro, it would be a welcome addition to the energy storage options available to us.
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, 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. In fact, a recent announcement from Energy Vault makes me wonder whether they’re giving up on gravity storage and are instead focusing on good old lithium-ion batteries.
Thermal storage
Thermal storage involves converting electricity to heat and then holding onto that heat until it is needed. In theory, the heat could be used to generate steam to drive a turbine and generate electricity. In reality, thermal storage is likely to provide heat 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 by shifting electricity use for heat 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 both electricity and heating depending on what is needed at the time?
Alternatives to energy storage
As I said in a previous article on managing renewable intermittency, storage isn’t the only answer when it comes to keeping the lights on in a zero-carbon electricity system. Other options do exist.
One option is to overbuild renewables so that even when it’s not particularly windy or sunny we still generate lots of electricity and therefore don’t need to store as much. It will certainly make sense to build more renewables than we need, especially as the costs of wind and solar continue to fall. But this approach will hit diminishing returns, and so it will be cheaper to deploy some storage. A similar argument can be made about deploying zero emission baseload technologies (e.g. nuclear, geothermal, hydro) — we’ll take what we can get here but these technologies are expensive and therefore at some point it will be cheaper to deploy renewables and storage as well.
The most serious alternative in my mind is long distance transmission lines and subsea interconnectors. The ability to move electricity between regions (or even between continents) would allow us to reach a zero emission electricity grid whilst deploying less renewables and storage capacity globally. The big challenge with new transmission and distribution networks is that they’re expensive, slow and unpopular to build. You need to get local buy-in, acquire the land or access and then build the thing. Research by McKinsey found that “the complexity and permitting requirements of transmission grid projects cause nearly 20 percent of all projects to be delayed or cancelled”. Large scale long duration energy storage will allow us to avoid, or at least defer, building new transmission lines or upgrading existing ones — this will allow us to decarbonise our electricity system faster and at lower cost.
Picking winners
Picking winning technologies when looking 10 or 20 years into the future is a fool’s game. But that won’t stop me, or other people, from trying.
There won’t be one technology that dominates. Multiple technologies will play a role, filling different niches within the electricity system. Some technologies will provide rapid response, delivering bursts of power for short periods of time (e.g. flywheels, certain types of battery). Other technologies will store electricity generated by solar, so that it can be used overnight (e.g. lithium-ion batteries, pumped hydro). And other technologies will store electricity for use during week long periods when the wind stops blowing and the skies are cloudy (e.g. compressed air, liquid air, hydrogen).
A 2019 study predicts the storage technologies that will be cheapest for different use cases in the future. The chart below provides a view of 2035 and predicts that lithium-ion will dominate, supported by pumped hydro, CAES and hydrogen for longer storage durations. Flywheels will dominate where energy is stored for short periods. (Note that PHES refers to pumped hydro energy storage and VRFB refers to vanadium redox flow batteries; liquid air doesn’t feature in this analysis. You can see an animated version of this chart here)
The study also predicts which technologies would be cheapest when the specific geographic features enabling pumped hydro (hills and lakes) and CAES (salt caverns) aren’t present. In short, you end up with even more lithium-ion batteries and a bit more hydrogen.
Highview Power has also developed a view on the costs of different types of energy storage technology. Unsurprisingly LAES, the technology under development by Highview Power, comes out looking good. Although not quite as good as pumped hydro or CAES.
What about my view?
I’m confident that we’ll end up with lots of lithium-ion batteries on the grid. It’s hard to compete with something being manufactured in such huge (and growing) volumes for a whole range of use cases, and therefore is seeing dramatic falls in cost (an ~80% reduction between 2013 and 2021).
I also see hydrogen playing a role for longer term storage. As I argued in this article, hydrogen will be required for many use cases beyond energy storage, such as fertiliser, shipping and industrial heat. Therefore, as with lithium-ion batteries, we can expect to see significant cost declines in the equipment required to manufacture hydrogen, store it and then convert it back into electricity.
In between lithium-ion batteries and hydrogen, I can see liquid air storage playing a role given its low expected cost, its ability to store electricity for days at a time, and the fact that it can be deployed anywhere. It also doesn’t rely on any scarce and/or expensive raw materials.
I don’t expect to see much compressed air storage, not in the UK at least. The requirement for specific geological features is too limiting and there’ll be competition for their use, e.g. for hydrogen storage or carbon sequestration. I also don’t see gravity storage taking off given it can’t store large amounts of energy. Maybe instead it will compete with flywheels to provide short bursts of power to help balance the grid.
Finally, I can see thermal storage playing a role, but in individual homes (see the solutions from Sunamp and Tepeo), in commercial settings or in district heat networks (if they’re ever deployed at any meaningful scale in the UK) where heat is used directly rather than being converted back into electricity.
Updates
Since writing the article I’ve discovered the CO2 battery, an emerging technology that uses compressed CO2 rather than air to store electricity. I’ve written a short article about CO2 batteries here.
Further Reading
- Ingenia: A new contender for energy storage [deep dive into LAES]
- McKinsey: Long duration energy storage for a renewable grid
- Rusty metal could be the battery the energy grid needs [deep dive into metal air batteries]
- David Cebon: Technology for large scale electricity storage
- Projecting the Future Levelized Cost of Electricity Storage Technologies
- Form Energy: Solving the Clean Energy and Climate Justice Puzzle
