The economics of hydrogen

BY EMMANOUIL KAKARAS

Hydrogen – the world’s lightest and most abundant element – has been touted as a solution to radically decarbonize industries and societies. Several countries have included it in their medium and long-term emissions reduction plans, with the likes of Canada, France, Germany, and Japan rolling out strategies specific to hydrogen.

Equipped to support 30% hydrogen co-firing, Mitsubishi Power’s J-Series gas turbines can produce up to 700 MW of electricity while reducing CO2 emissions. (Photo Credit: Mitsubishi Power)

To spur mass adoption of this zero-carbon molecule, a more robust supply chain is necessary. However, cost is a major barrier. Certain methods of hydrogen production, storage, and transport are specialized and expensive, especially when compared to more carbon-intensive alternatives.

One way to make hydrogen more economically viable is to significantly scale demand. The installation of a single 400 MW, 100% hydrogen-fired gas turbine combined cycle power plant, for example, would use the same amount of hydrogen as 2 million hydrogen fuel cell vehicles. Such a shift would generate enough impetus to expand the build-out of hydrogen-related infrastructure.

UPGRADING POWER SYSTEMS TO USE HYDROGEN

Energy sector players need not start from scratch to ramp up hydrogen utilization. They can use existing gas power infrastructure. For decades, the energy sector has already successfully used hydrogen in various proportions within small gas turbines. The next step is to develop larger machines that can safely deploy hydrogen for utility-scale power generation. To date, there has been success in converting large gas turbines with dry low-NOx combustors to run with a 30% hydrogen and 70% natural gas mix. Exclusive hydrogen-firing is projected for 2025.

Conversion of legacy systems to accommodate hydrogen firing can be done with minor structural modifications. Piping and valving sizes must be increased given the greater volume of hydrogen needed. But the compressor, turbines, and other auxiliaries can remain largely the same.

To ensure the safe deployment of hydrogen in large-scale power generation, the combustor design has been reimagined. Most existing large gas turbines can run with up to 20% H. But as its proportion increases, hydrogen’s explosive nature and wide range of flammability must be addressed. One notable effect of the significant rise in temperature with hydrogen combustion is the increase in formation of NOx.

A higher incidence of NOx emission can be mitigated by premixing fuel and air before entering the combustor. However, doing so poses a new challenge. Adding hydrogen raises the combustion speed of the fuel mix. It accelerates flame propagation to the point where it may exceed the fluid velocity of the premixed gases. This increases the risk of flashback – where the flame moves upstream in the fluid and can ignite fuel outside the combustion chamber.

A dry low-NOx combustor with an improved swirler nozzle has been developed to mitigate this challenge. Air is injected from the tip of the nozzle, increasing the velocity at the center of the swirling flow. This design boosted flashback resistance while enabling low-NOx combustion.

THE HYDROGEN VALUE CHAIN

The energy sector can help drive demand for hydrogen, but it cannot act alone. Leaders in both public and private sectors can take steps to stimulate hydrogen demand and supply, while striking a balance between economic feasibility and environmental performance.

The existing hydrogen supply chain is not decarbonized. With the bulk of commercially available hydrogen derived from fossil fuels, the IEA estimates that hydrogen production generates 830 million tons of carbon dioxide annually. This is equivalent to the combined CO2 emissions of the UK and Indonesia.

There are several ways to produce hydrogen that can drastically reduce or eliminate carbon from the process. This includes pyrolysis of hydrocarbons (forming solid carbon as byproduct) as well as using steam reforming systems with carbon capture capabilities. Another option is to generate green hydrogen using renewable power. The rapid growth of renewables in several places has led to oversupply, forcing power producers to curtail renewable power generation or sell excess power at a loss. In theory, this surplus electricity from renewables can be harnessed to power electrolyzers to produce carbon-free hydrogen.

However, to make green hydrogen competitive at scale, capital expenditure and operating expenses need to go down. The European Commission estimates that hydrogen derived from fossil fuels costs about $1.80 per kg, whereas green hydrogen ranges between $3.00 and $6.55 per kg.

To bring hydrogen further down the value chain, suitable transport and storage systems are also needed. Traditionally, hydrogen is stored in tanks at high pressures (350 to 700 bar) and low temperatures (below -252.8°C). These extreme conditions mean that tanks must be specially designed, with large compressors enabling such processes.

Salt caverns, such as those used by the Advanced Clean Energy Storage project in Utah, present a viable alternative for hydrogen storage. When operational, the system will be integrated with existing power grid infrastructure in the Western U.S. and provide up to 1 GW of renewable energy that can be tapped year-round.

Ammonia, which is easier to transport at scale than hydrogen, is also advancing the development of a hydrogen ecosystem. Not only can it be used directly as a fuel in smaller power systems, but it has proven to be an effective hydrogen carrier. In Australia, the Eyre Peninsula Gateway project is set to generate up to 40,000 tons of green ammonia per year and will feature a 75 MW electrolyzer for green hydrogen production.

Mitsubishi Power teamed up with the Los Angeles Department of Water and Power and other partners to work towards at-scale green hydrogen procurement at $1.50 per kg in the Los Angeles Basin by 2030. (Photo Credit: Green Hydrogen Coalition)

A STRONG HYDROGEN ECOSYSTEM

Various parts of the world are at different stages of hydrogen adoption. In Europe, first-generation hydrogen projects are set to come online within the decade. These include the conversion of a 440 MW gas-fired power plant in the Netherlands to 100% hydrogen firing, as well as the development of a green hydrogen cluster in Hamburg. The U.S. has been leading the way in exploring hydrogen for energy storage, with ongoing projects and evaluations in Utah, New York, Virginia, Louisiana, and Texas. In Saudi Arabia, work is underway for a facility that will produce, among others, 650 tons of green hydrogen per day.

In developing markets, limitations to infrastructure and access to capital are more acute. These countries can scale hydrogen adoption with blue or gray hydrogen and pair hydrogen production systems with carbon capture technologies.

At the end of the day, the development of a global ecosystem for affordable hydrogen production, storage, transportation, and utilization will need partnerships across sectors and industries. One example is HyDeal Los Angeles where the local government is working with industry players to drive down the cost of green hydrogen to $1.50 per kg.