Transitioning the U.S. natural gas grid into a system capable of transporting zero-carbon hydrogen will present both tremendous opportunities and significant challenges.
A panel of academics and industry representatives hosted by Columbia University's Center on Global Energy Policy on Feb. 24 explored pathways to making and using hydrogen. The event included a wide-ranging discussion on the role that gas transportation and distribution systems could play in the early phases of the hydrogen economy.
The first challenge — not just for the gas industry, but for all sectors — is the cost premium of zero-carbon hydrogen, according to Julio Friedmann, a senior research scholar at the Center on Global Energy Policy. Blue hydrogen, which captures and sequesters carbon emissions during production, costs 30%-80% more than standard hydrogen, he noted. Green hydrogen, made by using renewable power to split water into oxygen and hydrogen, is 100%-600% more expensive, he said.
The market needs policies like production and investment tax credits to lower those costs, Friedmann said.
Compounding that challenge, hydrogen has one-third of the heat content of natural gas, so utilities would require significantly higher volumes of hydrogen to provide the same amount of energy, said another of the center's senior research scholars, Erin Blanton.
This second challenge is rooted in infrastructure, Friedmann said. Depending on the vintage and make of pipelines, operators can run hydrogen at anywhere from 5% to 20% of the gas stream, he noted. Beyond that blend limit, they will have to invest in new infrastructure or modifications to existing lines and equipment.
Scaling up the use of green hydrogen for heating would also require sizable investments in the electric grid. "Just the heat load in the state of New York is three times what the grid can run," Friedmann said. "We would need to triple the capacity of the grid to make hydrogen for heat."
Plenty of potential, but more research needed
The benefits of hydrogen are worth the costs, according to Jack Brouwer, director of the University of California Irvine's National Fuel Cell Research Center and Advanced Power and Energy Program. For one, hydrogen provides the potential to store massive amounts of energy over long periods of time, which will become increasingly necessary as the U.S. introduces intermittent renewable power onto the grid, he said.
In Brouwer's view, the recent energy crisis in Texas and the public safety power shutoffs in California underscore the importance of energy system resilience. "The delivery of renewable energy content underground in pipes is much more reliable than the delivery of electricity via wires, and so many jurisdictions, I think, will settle upon a solution that includes renewable hydrogen for resilience reasons," he said.
Since new infrastructure is expensive and ratepayers have already invested in a vast gas grid, it makes sense to adapt existing transmission and distribution systems, according to Kristine Wiley, executive director of the Gas Technology Institute's Hydrogen Technology Center. The U.S. can draw lessons from Europe, where hydrogen research and development is more advanced, but Wiley stressed that the U.S. and European systems do not look alike. Even within the U.S., gas grids are not uniform.
"The distribution pipelines in the Northeast are very different from those in the Southwest, and so it's important to account for those varying pipeline characteristics like age, material type, operating condition, geographic and environmental considerations when we're assessing the impact of hydrogen on a system," Wiley said.
This means the industry needs to work with the research and development community to conduct pilots at multiple scales to determine the limits of integrating hydrogen into the gas grid, Wiley said. This will entail developing a sound approach to evaluating the impact of both low-hydrogen blends and 100% hydrogen streams on pipelines, compressors, underground storage, metering and regulation stations, and customer meters. It also will require revisiting leak detection practices and codes and standards, as well as considering the impact on end-use appliances, since hydrogen burns hotter and has a wider flammability range, she said.
Distribution systems and storage in focus
The R&D work is getting underway through programs like the U.S. Department of Energy-backed HyBlend program, Wiley said. One participant, National Grid plc, estimated that it can blend up to 20% hydrogen in the U.K. before requiring residents to upgrade appliances.
Increased knowledge about the blending limits of National Grid's U.S. gas grid could help the company understand the cost implications for consumers, according to Sheri Givens, National Grid's vice president of U.S. regulatory and customer strategy. "If we only are going to go up to a 20% blend, maybe that won't require the customers to switch out their end-use appliances," she said.
Brouwer acknowledged that there are "probably a couple hundred issues" that require thorough evaluation as operators adapt the gas grid for hydrogen. However, parts of the system are already quite compatible, such as the plastic pipe that utilities have installed as part of safety-oriented infrastructure replacement programs, he said. Concerns about hydrogen's potential to embrittle pipe chiefly revolve around high-pressure steel lines.
Research by Brouwer's team found that hydrogen escapes at the same rate as methane in existing low-pressure infrastructure, but may escape faster in cases where there is a large leak. Brouwer noted that there are low-cost solutions like hydrogen leak detectors to accommodate the transition.
One last research area that will require more investment is hydrogen storage, Wiley said. While hydrogen leakage from salt caverns is negligible, other underground storage types — such as depleted oil and gas wells — have not yet been adequately studied, according to Brouwer.
Friedmann said there is salt cavern storage capacity in many parts of the U.S. To offer a sense of the potential benefit to the energy system, he noted that a single salt dome storage facility linked to a Utah green hydrogen project has an energy capacity of 150 times that of all the batteries in the country.
"It is a massive, massive volume," Friedmann said. "And something like the strategic petroleum reserves, which are salt caverns — storage for oil today — could potentially be reconfigured or retrofit to store hydrogen in the future."