Utilities want to extend their infrastructure’s useful life. But the evidence suggests the risks and costs far outweigh the negligible emissions-reduction impact.
By Jeff St. John, 29 March 2022
Green hydrogen could be a vital tool to limit greenhouse gas emissions from hard-to-decarbonize sectors like steelmaking, shipping and chemicals manufacturing.
But trying to use it as a substitute for natural gas to heat buildings, or even to fuel power plants, could be a pipe dream that wastes precious time and money that would be better directed to more realistic and cost-effective options to reduce carbon.
That’s the key takeaway from a new report by San Francisco–based think tank Energy Innovation that lays out the latest critique of U.S. utility plans to use hydrogen as a substitute for fossil gas in their pipelines.
In the past two years, such utility efforts have been expanding, and they now include at least 26 separate pilot projects, many of them aimed at injecting hydrogen into existing gas pipelines. These range from individual utilities testing new hydrogen production and storage technologies to the Department of Energy’s HyBlend project, which involves multiple utilities and federal research labs.
Many of the pilot projects aim to repurpose existing fossil gas pipeline networks to use hydrogen that is manufactured using methods that don’t increase greenhouse gas emissions. But Energy Innovation’s report pulls together a growing body of research that indicates that these plans are severely limited by engineering and environmental challenges, casting serious doubt on their future viability.
State utility regulators are “kind of scratching their heads a bit on understanding the implications and risks of going down certain hydrogen pathways,” Sara Baldwin, Energy Innovation’s director of electrification policy and report co-author, said in a Monday interview. “Regulators need to be asking tough questions right now, and not assuming that these investments are prudent.”
“Green” hydrogen, which is made by electrolyzing water with carbon-free electricity, can have a role to play in powering the “hardest-to-decarbonize” sectors, Baldwin said. It can also replace the more than 70 million metric tons of hydrogen now produced globally each year for use in oil refining, fertilizer manufacturing and other industrial activities, almost all of which is made from methane via a process that emits significant amounts of greenhouse gases.
But uses that involve gas utilities charging their customers for “entirely new infrastructure and massive capital investments” in existing pipeline networks need to be subjected to much more stringent scrutiny, she said. Utility regulators must weigh the risk of extending the use of fossil fuel infrastructure that may be incompatible with broader decarbonization goals. They should be asking, “What is the future of gas writ large?” she said.
Blending hydrogen with fossil gas: A non-starter for buildings
Energy Innovation’s report critically analyzes a number of different potential uses of green hydrogen. But the clearest findings are those that undercut the viability of blending hydrogen with fossil gas in pipelines that supply buildings with gas for heating, cooking and other indoor uses. This prospect is being explored by utilities including CenterPoint Energy, Dominion Energy, National Grid, Puget Sound Energy, Southern Company Gas and Southwest Gas Holdings.
Utility holding company Sempra Energy is a strong proponent of this concept, with a dozen hydrogen-related projects underway, many of them being conducted by its Southern California Gas subsidiary. These include projects testing hydrogen fuel cells for stationary and vehicle power as well as a hydrogen pipeline injection pilot with its San Diego Gas & Electric subsidiary.
Neil Navin, vice president of clean energy innovation at Southern California Gas, cited the potential for hydrogen blending to “decarbonize the natural gas system today,” using an infrastructure that’s already providing energy across a state that’s set aggressive decarbonization targets.
“Many appliances today may run just fine on the existing natural gas system if there’s a blend,” he said — a premise the utility has been testing in experimental settings. While current data indicates that existing pipelines and appliances can only handle a mix containing up to about 20 percent hydrogen before requiring major upgrades, Southern California Gas wants to find out if that proportion could be increased. “We and others, including the DOE, are very interested in learning what those limits are.”
But there’s significant doubt about whether hydrogen can be safely blended into existing pipelines at proportions high enough to make a dent in overall greenhouse gas emissions, according to Energy Innovation’s Baldwin.
Hydrogen is a very different molecule from methane, which makes up the majority of fossil gas. It’s composed of the smallest molecule in existence, which makes it more difficult to contain in pipelines, increasing the risk of leaks. It’s also known to weaken the strength of steel used for large-scale gas pipelines, and it can be ignited far more easily than methane can.
All of this means that any widespread use of hydrogen would have to be accompanied by lengthy and costly safety studies, and it could require major retrofits and replacements of existing pipelines or entirely new appliances.
At the same time, hydrogen carries only about one-third as much energy per unit of volume as does methane, which means that a 20 percent blend of hydrogen will only reduce the emissions impact of its use by 6 to 7 percent. Most utilities are blending at much lower levels than that right now, essentially eliminating the emissions impact altogether.
These drawbacks make hydrogen a far less effective decarbonization option than replacing gas-fired heaters, stoves and other appliances with all-electric models, said Energy Innovation policy analyst Hadley Tallackson. “Just sending that renewable electricity through the grid” is far more efficient than using it to make hydrogen, she said.
That view is echoed by independent studies, including the International Energy Agency’s 2021 Net Zero by 2050 report, which found that hydrogen-based heating would likely make only a minuscule contribution to decarbonizing building heating through 2050. Energy efficiency and electrification via heat pumps are projected to be far more valuable tools in this effort, IEA’s analysis states.
Hydrogen for powering the grid: The jury’s still out
Energy Innovation’s report also takes aim at the idea of blending hydrogen into gas pipelines to provide the vital backup generation capacity to support a fully renewable-powered grid — a use case that’s gotten quite a bit more support from some in the industry.
Southern California Gas has cited this need in support of a proposal to build a 100 percent hydrogen pipeline system across its service territory, designed to supply the gas to multiple delivery points within the Los Angeles basin.
Now in its earliest planning stages, this Angeles Link proposal could tie into a multifaceted green hydrogen plan dubbed HyDeal LA, being promoted by the city of Los Angeles and its municipal utility, the Los Angeles Department of Water and Power (LADWP). It’s part of a plan to help eliminate greenhouse gas emissions in the city over the coming decades.
Hydrogen hubs such as the one being planned in L.A. could serve as a valuable source of carbon-neutral fuel for industrial processes, chemicals manufacturing and transport for heavy trucks, ships and planes, Southern California Gas’ Navin said — those aforementioned hard-to-decarbonize sectors. But it could also fuel the region’s fossil-gas-fired power plants to provide what he called “multi-seasonal energy storage” for a state grid that’s mandated to reach net-zero emissions by 2045.
Many utilities are looking to hydrogen as a fuel of last resort to fill the gaps left when solar and wind power can’t meet grid demand over long periods of time. Lithium-ion batteries can store solar and wind power for hours at a time, but they and other currently commercially viable forms of energy storage are considered to be prohibitively expensive for storing power for weeks or months at a time.
A National Renewable Energy Laboratory study on behalf of LADWP found that green hydrogen was the most cost-effective pathway for the region to fully decarbonize its grid by 2035. LADWP is already planning to convert its Intermountain Power Plant in Utah, which provides about one-fifth of its total electricity, from burning coal to using turbines that can run on a blend of 70 percent methane and 30 percent hydrogen. It’s one of several utilities with plans to use hydrogen to replace fossil gas for power generation, including Gulf Coast utility Entergy and Southeastern utility Duke Energy.
But Energy Innovation policy analyst Dan Esposito cited some serious concerns about mixing hydrogen with natural gas as a way of testing the viability of hydrogen-fueled power plants. It’s quite possible that the turbines, power plants and supporting infrastructure designed to run on fossil gas may end up being poorly suited to being converted to run on increasingly hydrogen-heavy mixes of fuel, he said, which opens the risk of investments in that infrastructure leading to a dead end.
Turbine manufacturers including Mitsubishi, Siemens and General Electric are developing turbines designed to run on hydrogen, but they aren’t yet commercially available. In order to handle higher and higher mixes of hydrogen, manufacturers will have to devise turbine designs that differ significantly from today’s gas-fired turbines.
“If the end goal is to get a peaker plant that can run on pure hydrogen to get that last 10 percent” of grid power, “you can test that without blending into today’s turbines,” Esposito said. Focusing on 100 percent hydrogen-fueled systems “helps you learn a lot more about the specific turbine designs you need to burn hydrogen and manage all of hydrogen’s unique properties,” such as the fact that it ignites and burns much more rapidly than methane does.
Esposito also pointed out that while hydrogen doesn’t emit fossil gas when it burns, it does cause higher emissions of nitrogen oxides, a pollutant tied to the formation of smog and to negative health impacts. Utility regulators should think through the implications of increasing emissions of nitrogen oxides in disadvantaged communities, where many power plants are located, as part of utility proposals to convert power plants to run on hydrogen, he said.
Regulators must also consider the relatively low efficiency of using electricity to generate green hydrogen that’s then burned to generate electricity. That process involves energy conversion losses of 50 to 80 percent, a round-trip efficiency that may well be outmatched by other technologies that can provide power at times when carbon-free grids need it.
Utilities and their regulators should seek out and test a variety of resources that could stand in for hydrogen-fueled generators, Energy Innovation’s report states. The think tank found previously that the U.S. power grid could reach 80 to 90 percent clean electricity without long-duration energy storage or “clean firm” resources to maintain stable and reliable electricity supplies, so there’s time to assess other options for supplying that final 10 to 20 percent.
Energy Innovation’s view on how much variable wind and solar power can be absorbed by grids, and what mixes of resources are best suited to provide the remaining portions of power to keep them running in a reliable fashion, does not represent the overwhelming consensus in the industry. There’s broad and persistent disagreement on just how far and how fast power grids can shift to wind and solar energy while maintaining reliable electricity supplies.
But if hydrogen is to play a role as one of the “clean firm” technologies that will eventually be needed, the cost of producing carbon-free hydrogen will need to decline dramatically. That will require significant technology improvements and scale-up in electrolyzers, continued growth and cost reductions in clean electricity to power them, and a growing market demand for green hydrogen to pay for it all.
Clean energy industry analyst Michael Liebreich, chair of Liebreich Associates and founder of BloombergNEF, has developed a scale with which to assess and prioritize the best and most effective end uses of green hydrogen. Replacing today’s carbon-emitting hydrogen supplies ranks at the top of his “clean hydrogen ladder” scale. “Long-term storage” of energy for the power grid is on his second rung, along with shipping and heavy industry such as steel production.
Here’s how Liebreich explained his thinking in an August 2021 post:
The economy of the future, which is going to be vastly more deeply electrified than today, needs long-term storage. It’s not just about providing back-up for when there is no wind or sun, it is also going to be about providing deep resilience in the case of weather disasters, cyber or physical attacks, neighbouring countries shutting off interconnectors and the like. Hydrogen can be stored in salt caverns, depleted gas fields or as compressed gas or liquified at various strategic points. It can be converted back into electricity centrally at 60% or more electrical efficiency via fuel cells…providing as high a level of grid resilience as you want to pay for.
Blending hydrogen into gas networks, in contrast, doesn’t even make it onto the lowest rung of Liebreich’s ladder. He declared it to be “pointless,” based on the same inefficiency problems that are highlighted in the Energy Innovation report. “And for what? To burn it in power stations regenerating power? Puh-lease.”
(Sources: Canary Media)
Đăng nhận xét