Power producers might think that replacing burners in gas turbines is enough, but whether you’re converting an old plant or building a new one there’s far more to H2 readiness. Here are ten basics to consider about H2-ready power plants.
With increasingly more energy coming from renewables, it only follows that the available power supply will go along with the weather. Power demand, however, won’t. Green hydrogen (what you might remember as H2 from your chemistry classes) is widely considered to be the bridge par excellence for balancing out these peaks and lows. How? Electrolyzers running on surplus wind or solar power split water into its basic elements to produce an entirely carbon-free or “green” hydrogen that can be stored in large amounts for long periods of time, then transported, turned into other alternative fuels or burned to produce electricity.
The infrastructure and production for green hydrogen aren’t yet available today, but they’re coming – along with new economic incentives. In the meantime, switching from coal- to gas-fired power plants can cut carbon emissions by two-thirds. Gas-fired plants – or rather, combined cycle power plants (CCPP) – are also capable of swiftly turning up (or down) their power output, making them indispensable for balancing the supply and demand for power at every second – a crucial requirement today in energy systems relying steadily more on intermittent renewables.
So what happens to all these plants when green hydrogen finally goes online and the switch to a decarbonized fuel becomes mandatory? These plants have a typical life-span of 25 to 30 years. Will all these assets be stranded? No, but the key is to make sure they’re H2-ready. Plants will likely be required to convert to burning a blend of hydrogen (up to 100 percent), meaning utilities need to make provisions today for a cost-efficient hydrogen retrofit tomorrow.
For the German energy company EnBW (Energie Baden-Württemberg AG), one of the first to develop a 100 percent hydrogen power plant with Siemens Energy, their main drivers were “climate neutrality and coal phaseout”, says Andreas Pick, the company’s Fuel Switch Project Manager. EnBW is currently building hydrogen-ready gas-fired plants that will be commissioned in 2025 and switched to run on hydrogen by 2030.
“H2 readiness shouldn’t be confused with H2 capability,” says Erik Zindel, Vice-President of Hydrogen Generation Sales at Siemens Energy. “H2 readiness means that a plant is prepared for conversion to hydrogen: Plants are designed today so they can be retrofitted to run on 100 percent hydrogen tomorrow. The idea is that you optimize what you do upfront and what you do later, saving time and costs, and ensuring that your plant is built to quickly make the switch to hydrogen.”
“H2 readiness starts with a basic concept,” says Peter Seyller, Principal Key Expert Modularization at Siemens Energy: “If we’re talking about constructing a new plant, then we have to align the building process to include a future with hydrogen. Each new build will have to be specific to the customer’s requirements.”
H2 readiness goes beyond just being able to exchange burners on gas turbines. Turbines like the SGT-600, 700 or 800 are already capable of burning up to 75 volume percent hydrogen, but you’ll still need to make provisions for the fuel gas supply, additional system space requirements, fire- and explosion-proof concepts, emission control changes as well as how hydrogen will be sourced.
Many of these measures are proven and would be applied during plant construction, like bigger, H2-resistant fuel gas pipes, fire protection and ventilation systems, plus suitable electrical equipment. Later, when green hydrogen supplies are available, a retrofit will include new burners and additional systems like a mixing station, hydrogen detectors, inertization and monitoring systems. “This retrofit,” says Zindel, “can take from a few weeks up to two months and would be done as part of a major overhaul.”
This doesn’t mean there aren’t still uncertainties at play: “We’re in line with the expansion for hydrogen infrastructure in southern Germany, but if it actually comes in this timeline, nobody can say for certain,” says EnBW’s Andreas Pick. “And regulations for operating a full hydrogen power plant aren’t yet in place either. These are things we’ve had to take into account when talking with Siemens Energy.”
Hydrogen and natural gas (which is primarily methane) behave quite differently when stored and transported. Hydrogen also has different combustion characteristics, with flame temperatures nearly 300 °C higher than methane. Its laminar flame speed is more than three times that of methane as well, and it has an autoignition delay time more than three times lower, making it a highly reactive fuel. This all means that controlling the flame to maintain the combustion system’s integrity and control nitrogen oxide (NOx) emissions has been a real challenge for developers.
There are two main categories of combustion technology: Dry Low Emission (DLE) and Non-DLE. In DLE systems, fuel and air are mixed together before combustion, allowing for precise control over combustion, flame temperature and conditions that cause NOx emissions. Non-DLE systems use diffusion flames or partially premixed flames, which require dilution with water or steam to control NOx emissions.
Yes and no. There are mainly three types of hydrogen: grey, blue and green. Grey is the least sustainable form of hydrogen because it’s produced using natural gas and releases carbon emissions into the air. Blue is produced the same way, but carbon emissions are captured and stored separately. Green hydrogen, however, is produced via electrolysis using water and renewable energy – without emitting carbon dioxide. So, while gas burners don’t discriminate between the colors of hydrogen used, green hydrogen is the only truly sustainable solution.
The demand has triggered a rapid development of H2 gas turbines. And already next year, 100 percent hydrogen combustion will be demonstrated in the HYFLEXPOWER project in France, the world’s first integrated power-to-X-to-power hydrogen gas turbine demonstrator using an upgraded SGT-400 turbine. Siemens Energy then expects to have 100 percent H2 gas turbines available commercially in all turbine size ranges by 2030.
Instead of high rates of production hours, H2 power plants will need to be rewarded for providing residual load over longer periods when production of intermittent renewable energy is low – and for supplying important services to power grids that renewables simply can’t deliver: for example, grid inertia, short circuit power, frequency regulation and reactive power. In addition, gas turbine plants built as combined heat and power (CHP) plants will also be able to provide heat for industry and district heating networks in times when the lack of renewable energy prevents them from running heat pumps: “Annual residual power and residual heat periods will be concurrent,” says Erik Zindel.
“We’ll likely be moving away from an energy-only market to a capacity market. The EU is already discussing this, but it still needs clarity for finding investors. In the end, we expect that gas-fired plants will only supplement renewable power and heat generation, but even so, they’ll still provide us with a flexible capacity to our security of supply and need to be compensated – preferably without subsidies.”
Prepped for hydrogen:
Since the market sees it as an insurance fee against stranded assets, H2 readiness is a no-brainer. Siemens Energy’s own R&D investments are a proof of that, as is the German TÜV Süd certification Siemens Energy obtained for its H2-ready power plants. “The certification includes requirements for all areas of a plant,” says Seyller. “Apart from the turbines, which are still being developed to run entirely on hydrogen, our complete plant concept is already certified for 100 percent hydrogen readiness. We don’t know yet how big this will get. But it gives customers the certainty that preinvestment will pay off.”
“In reality,” says EnBW’s Andreas Pick, “like so many utilities, we’re facing a classic dilemma. On the one hand, a new power plant won’t amortize, but on the other if we continue to use natural gas we won’t be able to reach climate neutrality. So, what could be more logical than switching to hydrogen and preparing for that switch today?”
Netherlands-based physicist and author Rolf de Vos has been reporting on global developments in energy and the environment for more than 30 years. Among the first to cover climate change and sustainability, de Vos has also been an acting consultant for organizations such as the Dutch Ministry of Economic Affairs and Climate Policy.
Combined picture and video credits: Siemens Energy