Hydrogen networks should ultimately be supplied by renewables

Hydrogen networks should ultimately be supplied using electrolysis powered by renewables, the head of engineering at National Grid Gas Transmission has argued.

Anthony Green was speaking at the Network Asset Performance Conference in Birmingham yesterday (25 September).

Green said the government’s new net-zero target will require both the widespread electrification of heat and the decarbonisation of gas networks through conversion to hydrogen: “Net zero really forces us to go for both. We haven’t really got that much choice. We’ve got to use all of the tools that we’ve got in our arsenal.”

The plans for hydrogen conversion being developed by the gas networks in Great Britain call for the fuel to initially be produced by extracting it from methane, using either steam methane reformation (SMR) or auto-thermal reformation (ATR), and then capturing and storing the resulting carbon dioxide emissions.

In its H21 North of England report, setting out proposals to create a hydrogen gas grid in a number of cities across the region, Northern Gas Networks said this would be a better option than producing the hydrogen using electrolysis – partly because of difficulties in scaling up renewable output and electrolyser capacity, but primarily because it would be significantly less expensive.

Green accepted that extracting hydrogen from methane may be the only way to produce enough fuel to keep hydrogen networks stocked to begin with: “If we need to transition to net zero by 2050, we’ve got an awful lot of gas we’ve got to be producing very quickly. And we’ve got to start that in the 2030s.

“I don’t think we’re going to be at a scale where electrolysis can do that straight away.”

But he said extracting hydrogen from methane should only be seen as a stop-gap measure and kept to a minimum: “I just have this concern that it’s storing up problems for a later generation if we’re capturing the carbon. I would prefer to go green completely”.

He said a hydrogen network fuelled by renewables was the “green future we want to get to”.

In contrast to NGN’s findings, Green said he expected the plummeting cost of renewables to make electrolysis cost-competitive with methane reformation and carbon capture and storage by 2030.

He said one option to minimise costs would be to produce hydrogen in Africa using electrolysis powered by solar farms and then liquefy the gas and ship it to the UK: “There are already LNG vessels being developed in Japan to pick up hydrogen produced through electrolysis in the Australian deserts and carry that hydrogen up to Japan.

“Could we do that from the African nations that have lots and lots of sun?”

Green also suggested that blending and then de-blending gases on the transmission network could help smooth the transition to hydrogen: “Leeds is the city that is looking like it will be first to a hydrogen future. They’re going to need 100 per cent hydrogen.

“If we can carry 20 per cent hydrogen on the NTS [national transmission system] and then we de-blend it and pull off that 100 per cent hydrogen stream, it allows us to convert to hydrogen very quickly and very easily, whilst sustaining the rest of the country.”

This process could even be used to supply multiple gases to a particular user: “Take methane on, take LNG on, take biogas on, take hydrogen on, mix it all up and then de-blend it and issue to whatever asset needs it the mix of gas they want.

“So if you’re 100 per cent hydrogen, you can have that. If you’re 20 per cent hydrogen and 80 per cent methane because you haven’t converted all of the boilers in your town at that point, you can have that.

“If you’re a power station and you need 100 per cent methane, you can have that as well.”

“The good news”, he added, “is there is capability out there in the industrial world to do this already. Now it’s a case of could we scale that at the right quality and the right cost to make it feasible to roll that capability out.”

Green said blending and then de-blending could additionally provide a temporary solution to the issue of embrittlement, whereby steel pipes become weaker as hydrogen molecules are absorbed into the metal. Methane could be used as a medium to transport hydrogen around the transmission network.

However, he said the problem could also be almost entirely mitigated by injecting small amounts of oxygen into the network: “By small amount, I mean 500 parts per million.”

Earlier this year, the gas networks began testing a sample of steel pipes from around the UK to assess whether they could continue to be used safely as part of a hydrogen grid. One of the aims of the programme is to establish the extent to which the pipes might be affected by embrittlement.

Given the current uncertainty over the future of gas networks, Green said National Grid’s aim for the upcoming RIIO T-2 price control would be to ensure they have “no regrets” and avoid making any “big investment in any assets that will not be needed in the future”.

“We want to make sure that any money we’re spending, which is consumers’ money, is really well focused,” he explained.  “Our investment will focus first of all on maintaining the health of our assets.”

He continued: “We’ll only do new build to maintain resilience. A number of our compressors are very, very old now. We need those compression units to maintain the ability to move gas around the UK. And we’ll also focus on serving new customers.”

Graham Cooley, the chief executive of electrolyser manufacturer ITM Power, told Utility Week recently that the falling costs of renewables, as demonstrated by the record-low strike price in the latest Contracts for Difference auction, will “open up the opportunity” to produce affordable low-carbon hydrogen using electrolysis.