The need to solve the problem of intermittency when it comes to wind and solar electricity generation has led to a boom in battery-based energy storage that has continued unabated through the COVID-19 pandemic. But a different means of harvesting these kilowatts for later use has begun attracting its own growing attention. Thanks to falling prices, renewably produced hydrogen could have a strong future as a possible alternative to lithium-ion batteries for specific applications, on its own and as a supplement to natural gas.
Of course, hydrogen has been used for decades in petrochemical and other industrial applications. But in those cases, it’s manufactured primarily from natural gas, a fuel source we’ll have to move away from if we’re going to address climate change threats. However, hydrogen also can be produced by isolating it from water—it is, after all the “H” in H2O.
What now attracts green-energy fans’ hopes is falling prices for electrolyzers, the equipment used to separate hydrogen from oxygen, its molecular mate, in water using electricity as an energy source. Once separated, the hydrogen can be used as a fuel on its own or stored in fuel cells for future electricity production, and no greenhouse gas emissions are directly created in the process.
The hydrogen rainbow
Any conversation about hydrogen and how it could fit into more renewably sourced energy supplies typically begins with describing the various colors used to characterize its production.
- Green hydrogen, as described above, is produced through electrolysis with oxygen as its only emission. When the electricity comes from wind, solar or hydropower resources, the resulting hydrogen is described as “green.” On occasion, solar-produced hydrogen is called “yellow,” and, when nuclear power is the energy source, “pink” can be the descriptive term of choice.
- Blue hydrogen is produced through a process called steam methane reformation, using natural gas or coal gas as a feedstock. The gas is mixed with superheated steam in the presence of a catalyst, which splits it into hydrogen and carbon monoxide (CO). Adding water changes the CO to carbon dioxide (CO2) and creates additional hydrogen. The CO2 is captured for storage, so no greenhouse gas emissions are released during these reactions. However, producing and transporting the natural gas is known to be a greenhouse-gas intensive process.
- Turquoise hydrogen uses a process called methane pyrolysis that splits methane from natural gas into hydrogen and solid carbon (also known as carbon black). As with green hydrogen, the natural gas in this process is only used as a feedstock, and electricity supplies all the energy used to heat and split the methane. If that electricity is renewably sourced, no further greenhouse gas emissions are created.
- Gray hydrogen is essentially blue hydrogen with no carbon capture or storage. The related CO2 is simply vented into the environment. This is how about 99% of hydrogen is produced today. It’s also very CO2-intensive.
Gray hydrogen is, by far, the least expensive of these options, with production costs running under $1/kilogram (kg), according to Platts Analytics; blue comes in at approximately $1.40/kg. Shifting to the water-based electrolysis process, however, ups the price to $4.42/kg, making green hydrogen a very expensive product. In June, the U.S. Department of Energy (DOE) announced plans to support the research needed to lower that cost to $1/kg in a decade. This is the first effort in the DOE’s Energy Earthshots initiative to accelerate breakthroughs in clean-energy development. They’ve dubbed it the “Hydrogen Shot.”
Renewable-energy advocates see a strong future for green hydrogen in applications ranging from transportation to grid-scale energy storage and electricity generation. Today’s hydrogen users, regardless of production method, are primarily industrial.
The United States currently produces about 10 million metric tons of gray hydrogen, according to Mark Ruth, group manager for the National Renewable Energy Laboratory’s Industrial Systems and Fuels Group. Half is used in petroleum refining and petrochemicals, while the other half is primarily used to produce ammonia for fertilizers. Much smaller users include warehouses, where hydrogen fuel cells can power forklifts and other such vehicles to eliminate the danger of emissions in interior spaces.
“Hydrogen is the preferred approach, first, when it’s used for its chemical value, so in hydrocracking or ammonia,” he said. “The next situation is when the use requires long-term operation and quick refueling—you don’t want to wait two to eight hours to recharge a forklift” as you would with a battery. Similar opportunities exist with long-distance trucks, he added.
Hydrogen also can be combined with CO2 to produce synthetic versions of a broad range of petroleum-based fuels, including gasoline, kerosene, diesel and bunker fuel. Capturing the CO2 from the air or industrial processes and using renewable energy to produce the hydrogen would result in an 85% reduction in carbon emissions, compared to those of traditional petroleum products, according to the German automaker Porsche, which is developing a pilot synthetic fuel production plant in Chile that is expected to begin operations in 2022.
Longer term, similar approaches could make synfuel (also called e-fuel) a suitable replacement for the kerosene used to power jets. A recently formed Norwegian consortium, Norsk e-Fuel, is developing a plant to produce 10 million liters of this product annually by 2023 and 100 million liters by 2026. Electrifying jets using batteries isn’t possible at this point because weight and space requirements make it financially and physically impractical. So, synfuel based on renewably generated hydrogen is seen as one way to clean up aviation emissions.
What’s unlikely in the near term is directly replacing natural gas for utility-scale power generation. There are projects in the works to supplement natural gas with 5%–30% green hydrogen in these applications, but pushing that to 100% poses several problems.
“You can design and build a turbine that can burn anything from all natural gas to all hydrogen. But hydrogen is very reactive, so it will embrittle materials it comes in contact with” in large amounts, including pipeline transportation networks, Ruth said.
This is why utilities’ pilot efforts are restricting the percentage of hydrogen injected into their systems.
“We know how to do it, we just need to modify the natural gas infrastructure we have now for hydrogen,” he said.
Two notable efforts are underway to test the limits of hydrogen introduction into generating plants. New York state is investing $8.5 million in the New York Power Authority’s Brentwood power plant on Long Island. This natural gas plant will be retrofitted to include a system to blend natural gas with green hydrogen produced using hydropower. Starting this month, operators will test concentrations of hydrogen, ranging from 5%–30%, stopping the turbine periodically to study emissions and turbine performance as the amount of hydrogen is ramped up.
In Utah, a plan is underway to develop a new generating station designed to eventually run on 100% green hydrogen. The Intermountain Power Plant in the small city of Delta has generated power for decades with coal-fired turbines. Those units will be replaced by two Mitsubishi Hitachi Power Systems units purpose-built to run on hydrogen and gas. Initially, operators will run the units on a 30/70 mix of hydrogen and natural gas, with plans to switch to entirely renewable fuel within a decade. The hydrogen will be produced at an adjacent site using a mix of grid-supplied wind and solar power and stored in underground salt domes unique to the location. Electricity from the station will serve Utah and customers of the Los Angeles Department of Water and Power.
It’s this style of larger project—for utility-scale generation, industrial processes such as steel manufacturing and long-haul commercial transportation—where green hydrogen has a chance to make inroads. An opinion piece from energy research firm Wood Mackenzie outlines its belief that renewably produced hydrogen is at a “tipping point,” and that the gas will “emerge as a key element of the energy transition.”
Financial investment is certainly picking up, according to Wood Mackenzie’s data. Between August 2019 and August 2020, the capacity of projects under development more than quadrupled to 15 gigawatts (GW) from 3.2 GW. The firm’s analysts have tracked at least $4.5 billion in new investments in the first quarter of 2021, with 55 projects announced during that period. By 2050, the firm predicts green hydrogen could supply approximately 7% of global energy demand.
Wood Mackenzie sees Europe as the primary driver for this growth. Costs for fossil fuels there are high, so price will be less of a barrier for the carbon-free power source. In the United States, NREL’s Ruth is less dramatically optimistic. Ruth says his group sees the amount of green hydrogen growing by two to four times current supplies over the next five to 10 years. Traditional uses, such as biofuels and metal refining, will be the primary applications over that time, he said.
A reduction in the cost of electrolyzers, a key contributor to green hydrogen’s current price premium, could be a more important shift. Ruth noted that this would make the fuel more competitive with other technologies.
This will also be a period to address questions of infrastructure, such as whether production should be centralized with delivery pipelines like those used today for natural gas, or if smaller electrolyzers make localized production a better choice.
So, it appears there remain a number of questions to be answered when it comes to this carbon-free fuel. In the short term, cost and distribution are still hurdles to scaling it up to a level where it competes with, say, lithium-ion batteries as an energy-storage option. But going forward, its flexibility makes it a strong option for numerous use cases. Over the long term, it seems likely green hydrogen will prove itself to be more than just a lot of hot air.