Why hydrogen-fired power plants ‘will play a major role in the energy transition’

Deep decarbonisation of the power system will not be possible without burning clean H2 for electricity generation, senior executives at Siemens Energy and Equinor tell Recharge

At first glance, the concept of a clean-hydrogen power plant seems utterly absurd.

Why would anyone use renewable power to make green hydrogen and then burn it to produce electricity? The round-trip efficiency would be less than 40%, so every 10kWh of wind or solar energy would provide less than 4kWh of electricity.

And why would anybody create blue hydrogen from natural gas with carbon capture and storage (CCS) — with all the added expense of methane reforming and compressing/liquefying, transporting and storing the hard-to-handle H₂ — when you could just add CCS to existing gas-fired power plants?

And yet major energy companies such as Siemens Energy, Equinor and SSE believe there is a bright future for hydrogen-fired power plants. Why?

Green-hydrogen power plants

Germany’s Siemens Energy — which was spun off from its parent company Siemens last year — is now offering hydrogen-fired power plant solutions to customers.

“If I have renewable power, convert it to hydrogen and re-electrify it, with a total cycle efficiency of less than 40%, it obviously only makes sense if you’re using hydrogen as long-term storage and compensation for variable renewables,” says Erik Zindel, Siemens Energy’s vice-president of hydrogen generation sales.

“If you really want to [store power] for days, weeks, months, or for seasonal storage — which is using solar power from the summer in winter, or wind power from the autumn to the summer — you need to store electricity in a chemical way.

“You still need [clean] power for the dark doldrums periods in winter, when there’s no sun and no wind blowing for two or three weeks — you need to have a hydrogen supply.”

He tells Recharge that large-scale hydrogen storage will also be useful to reduce curtailment of wind and solar power during windy/sunny periods.

“Once you go into the green hydrogen arena, you can increase the amount of renewables that you want to build in the grid because you can make use of the excess renewable energy [that would otherwise be curtailed because it cannot be sold],” Zindel explains.

“So by having electrolysis [which uses electricity to split water molecules into H₂ and oxygen] and by being able to store that excess energy as hydrogen, you can really allow the electric system to expand renewables by a significant amount. Because if you don’t do that, it will be quickly limited, because there will be too much excess energy that you have to dump.

“But once you can make use of that excess power, then you can really double, triple, quadruple the amount of renewable energy you want to build.”

Blue-hydrogen power plants

Norwegian oil giant Equinor and Scottish utility SSE recently announced a plan to build a brand new 1.8GW hydrogen-fired power station at Keadby in northeast England, as soon as the end of this decade. The companies say it would almost certainly be powered by low-carbon blue hydrogen and used to help back up variable renewable power, probably offshore wind.

So why would a blue-hydrogen power plant be preferable to a natural-gas generator with CCS?

Henrik Solgaard Andersen, Equinor’s vice-president of low-carbon technology, tells Recharge that capturing carbon at the pre-combustion stage is a lot more cost effective than capturing it post-combustion at a gas-fired power plant.

“In the flue gas [at a gas-fired power station], the pressure is very low and the CO₂ concentration is very low… so it’s very difficult,” he explains. “It’s like finding a needle in a haystack. And the more [CO₂] you take out, the smaller the needle gets to find the rest [of the CO₂]. And finally, you can’t get it.

“In a blue hydrogen plant, it’s high-pressure CO₂. So we have many more needles initially, and that’s why you can capture much more CO₂ in a blue hydrogen plant compared to a post-combustion plant, because the pressure is so high — so you can get down to [97-98%].”

It would be even less cost effective to capture CO₂ at a gas-fired power plant that would only be in operation for less than 50% of the time — like the Keadby back-up plant would.

“The post-combustion [ie, natural gas with CCS] plant must be ready to capture 90%-plus [of the CO₂] every time it runs, whether it’s a short or long time,” says Andersen.

“We think that all these starts and stops would mean the capture plant warms up and cools down too much, so it will not be able to capture that amount of CO₂.”

He adds: “Nobody has run a dispatchable power plant with CCS before. Nobody knows really what the energy efficiency will be and the capture rate. So there are some uncertainties there.”

High costs

While Equinor and SSE are planning to build a brand new hydrogen power plant, Siemens Energy is basing its business model around the conversion of existing fossil-gas power plants, as well as the construction of new “hydrogen-ready” combined-cycle gas-fired facilities.

Yet even though converting a gas power plant to run on H₂ would be “fairly inexpensive”, using clean hydrogen to generate electricity today “is not something that makes sense economically”, says Zindel.

Natural gas is simply a lot cheaper than green, blue and even unabated grey hydrogen, he explains.

The cost of green H₂ is estimated to be in the range of $2.50-6/kg today, with blue hydrogen at somewhere between $1.50-4/kg.

If clean H₂ was available at €2 ($2.35) per kg, to make it cost-competitive with fossil gas “would require a CO₂ price of something between €200-250 per tonne, so it’s still far away”, says Zindel. The EU carbon price was about €53 per tonne at time of publication.

Zindel believes that clean hydrogen will not be used for large-scale electricity production until 2035 — partly because it would be more cost-effective to use that H₂ in other sectors such as transport and heavy industry.

“We expect hydrogen electrification will occur in 2035 or the 2040s on a large scale — when we really have to go into a deep decarbonisation of the power sector,” he says.

Equinor has stated that its Keadby Hydrogen facility would only go ahead “with appropriate policy mechanisms in place”. In other words, if it is heavily subsidised.

“We have a market failure,” Andersen tells Recharge. “So we’re working on a business model that is probably more tailored towards some kind of producer Contract for Difference. So the offtakers would pay a price for the natural gas, and those producing blue hydrogen would get some kind of subsidy to cover [the extra cost].”

Why now?

If Siemens Energy does not believe the power sector will generate electricity from H₂ for another 15-20 years, why is it marketing hydrogen-fired power solutions today?

“For various reasons,” says Zindel. “The first one is, we know it’s the future, so we have to begin work now, and our plan is to get to 100% H₂ capability by the end of the decade — so it will already be available when we get the first real commercial projects.

“We expect that combined-cycle power plants will be the main technology of choice for providing the residual load in a fully decarbonised power scenario, with these combined cycles running only 20-30% of the time — not more, because you will have sufficient wind and solar in the system.”

He continues: “The second — and much more important point — is that our customers need to build power plants today for natural gas. So if you have a natural-gas power plant being built today, with commercial operation in, let’s say, 2023-24, the typical lifetime expectancy [means]… these power plants will still be operational in the 2050s, when we’re supposed to be completely decarbonised.

“That means every new [gas-fired] power plant to be built from now on will have to very likely be retrofitted to burn hydrogen in the future. So it’s very important that we prepare the plants today to do that. That’s what we call the ‘hydrogen-ready concept’. [So] we make sure that we have the right materials, the right electrical equipment selected, [and] we have sufficient space for additional systems [that will be needed when the plant is converted to run on H₂].

“We see, at least in Europe, nearly every customer is talking about hydrogen readiness for their new power plants. But other regions of the world are now getting very aggressive [about carbon reduction] as well. So it’s a very important topic in our industry.

“They have seen nuclear power plants being taken out of operation long before their commercial and technical lifetime ends — they’re now seeing coal-fired stations being taken off the grid as well… they’re getting a little bit fed up with [having] stranded assets, so they want to make sure the combined cycles built today are future-proof.”

How do you convert a gas-fired power plant to hydrogen?

Hydrogen has different properties to natural gas — for instance, it is a smaller molecule, has a lower energy density and leads to steel embrittlement — so various changes will need to be made to enable a gas-fired power plant to run on H₂.

“Lower volumetric density has mainly an effect on all the upstream equipment — the gas turbine, the fuel gas system, you would need fuel pipes with an increased diameter,” explains Zindel.

“So if you know the power plant will have to run on hydrogen in the future, you can build higher diameter pipes [in the first place] using the right materials. If you want to retrofit, you might not have the space [for wider pipes].”

He explains that if the turbine needs its central axis lifted to accommodate wider pipes “that immediately questions the economic viability of a retrofit”.

Other changes that might be needed include new electrical and gas-detection systems, and — depending on the regulatory requirements — the addition of a selective catalytic reduction (SCR) system in order to reduce nitrous oxide (NOx) emissions (greenhouse gases that are created when hydrogen is burned in nitrogen-rich air).

But the most prominent change would be adapting the gas turbine to burn H₂, which would require changes to the combustion chamber and new burners.

“Hydrogen as a fuel has a much higher reactivity and a much higher flame velocity compared with natural gas,” says Zindel. “And that means the flame gets much closer to the burner itself and you have the risk that the flame ‘eats’ into the burner and then damages it. So you need a new burner design that is flashback-proof. And at the same time, you have to have a slightly higher flame temperature, which means that the NOx emissions would increase.

“And then it’s all about… how do you start or shut down a unit without damaging the burner when you already have a low flow of air through the combustion chamber?

“And that’s more or less the R&D challenge that we have — to design a burner that is stable and safe to combust hydrogen, while at the same time keeping NOx emissions under control.

“You can’t eliminate them completely, but you can reduce them significantly.”

Zindel says that a holistic view of all greenhouse gases is required. So it is not only about reducing CO₂ and NOx, but also methane — a powerful greenhouse gas — which can be emitted upstream when using natural gas for blue H₂.

Why not use fuel cells?

If burning hydrogen will always produce some NOx greenhouse gases, why not convert the hydrogen to electricity by using emissions-free fuel cells?

“The fuel cell is a competitive technology compared with combined-cycle with a gas turbine — but in the end… it’s really about economics,” says Zindel.

“If you look at efficiencies, today’s combined-cycle technologies… [have] efficiency levels of 63-64%. So that’s already higher than a typical fuel cell, which is usually limited to 60%.

“Then investments costs for a combined cycle power plant are also much cheaper than for [similar-sized] fuel cells. It will take many, many years until [fuel cells] get close to the LCOEs [levelised cost of energy] of combined-cycle, if at all”

He continues: “And then you need to look at the much higher fuel flexibility of gas turbines and the possibility to retrofit existing natural-gas combined cycles to burn hydrogen, which would reduce the required investment even further.

“All that speaks for combined cycles as the main technology for future re-electrification of hydrogen. Fuel cells, despite being a very attractive technology with a significant improvement potential, will see its main application areas in mobility and in small island grids, where a combined cycle is not feasible.”

Pilot plants

Zindel explains that Siemens Energy is currently constructing and commissioning three pilot power plants that will either burn 100% hydrogen or a hydrogen-rich mixture of gases.

Two new commercial cogeneration plants — a 500MW facility in western Russia and an 80MW project in São Paulo state, Brazil — will both use by-product hydrogen from refineries to provide power and heat back to those refineries, at concentrations of 27% and 60% respectively. Both plants are currently being commissioned.

But arguably, the most important of Siemens Energy’s pilots will be the 12MW Hyflexpower project in France, which will use 100% green hydrogen at an existing gas-fired cogeneration plant that provides power and heat to a paper mill in west-central France.

“It’s a nice demonstration project for our new burner technologies, which are capable [of combusing] any combination of fuels between natural gas and hydrogen, and we expect to get to 100% hydrogen with low NOx emissions by 2023,” says Zindel. “And that would be our first real demonstration project in the field.”

The existing facility will be converted to hydrogen by a consortium that includes Engie Solutions, the German Aerospace Centre and four European universities, and is being funded by the European Commission’s Horizon 2020 programme.

‘A very, very big but’

Zindel says that while Siemens Energy does not expect hydrogen power plants to be built at large scale before 2035, there’s “a very, very big but”.

“Legislation needs to embrace a decarbonisation route — and rather quickly,” he explains. “Countries will need to enforce decarbonisation. And it’s easier to enforce decarbonisation targets on 50 large companies than on 30 million voters who will give an opinion at the next election about your performance in the previous four or five years.

“So the risk for power plant operators is that they might be getting quicker decarbonisation targets [than they expect].”

The German adds: “The important thing to understand is that regulation will lead the change, because none of these technologies are currently cheaper than the existing ones. No company is going to switch to hydrogen because it’s a more sexy, fancy thing to do.

“It’s really the regulation that will enforce the switch, whether it’s through subsidies or CO₂ taxes, or higher CO₂ certificate prices, or by limiting emissions or whatever. It will come sooner or later.

“And then it’s up to the industry to perform.”(Copyright)

Source: rechargenews