Utility Week

12 | JUNE 2021 | UTILITY WEEK Speical report on storage they are massively oversized and cost a lot or have very poor lifetimes". Chemical Energy Storage Hydrogen One of the biggest unanswered questions for the energy sector going forward is how to store energy in su cient 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." While most batteries currently being installed can be € lled 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," he says. "That's why all 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." Cooley says ITM Power's electrolysers have an e - ciency of around 70 per cent in terms of the power con- sumed 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 e ciency to 86 per'cent. At the beginning of this year, ITM Power christened a new factory in She eld that Cooley says is the "world's largest", with a production capacity of 1,000MW of elec- trolysers per year. "The UK government has been trying to put together a plan so it can € nd a way of funding and encouraging a company to build a battery gigafactory and what it doesn't realise is it already has an electro- lyser gigafactory," he says. ITM has also been scaling up the electrolysers itself. When if € rst started a decade ago, it was producing 10kW systems. Now they come in 5MW modules, pack- aged together in 20MW systems. This has helped bring down costs signi€ cantly. Three or four years ago, they were selling at €1,600/kW. Now they are going for €800/kW and ITM is aiming to get to €500/kW by the mid-2020s. Cooley notes that these costs cover the entirety of the system across engineering, pro- curement and construction. Another company producing PEM electrolysers is Sie- mens Energy. The company launched its € rst lab-scale electrolyser in 2011 and its € rst 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 that while the technologies all have their advantages, Siemens chose to focus on PEM electrolysers because they ultimately expect them to be the most cost-eŸ ective. He says PEM electrolysers are a "fairly young tech- nology," with signi€ cant potential for cost reductions: "We're still making the big jumps. The alkaline technol- ogy has 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 signi€ cant enough to actually overtake all the other technologies." Siemens Energy is looking to directly integrate its electrolysers into oŸ shore wind turbines alongside its sis- ter 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 his company's 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 is expensive and not easy to install; all of that electrical infrastructure falls away and you replace it the infra- structure of a piping network which is also di cult but not as complicated," he explains. He adds: "When you go oŸ shore there's a lot more space than 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." Of course, using hydrogen to store power also requires conversion back into electricity, for which there are two options. The € rst 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 e ciency 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 Analysis continued from previous page "All 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." Graham Cooley, chief executive, ITM Power

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