by Ray Kamada
As the northernmost county on the U.S. West Coast, Whatcom land is low-lying, not very windy, often cloud-shrouded, and expensive, all of which renders it ill-suited for utility scale solar and wind farms. Indeed, our sunniest acreage just east of Sandy Point got flooded recently. Fierce winds blow across Lummi Island’s southern ridge, but four turbines there wouldn’t be a major wind farm. Winds also blow hard across many inland ridges, but building on them is expensive and may be unsightly. (1)
So, besides electric vehicles, heat pumps and general electrification, how can Whatcom start greening in a major way? Well, once electrification is complete, we may be consuming as much as a gigawatt of juice per hour. (1) Therefore, we do need some reserve power for outages as well as source leveling. Meanwhile, lithium batteries don’t take up much space, can tie into the grid from almost anywhere, (2) and may even couple nicely with industrial co-generation at Cherry Point.
But gigawatt-size power plants might take five or ten years to complete. By then, would Li-Ion batteries be our best bet for both long- (exceeding eight hours) and short-term energy storage? That is, several other plausible candidates exist, such as: “green” hydrogen, iron-air batteries, geothermal drilling, liquified air, supercritical CO2, and heat pit storage. Since we must narrow this field, let’s start by reviewing hydrogen.
“Green” hydrogen has captured the attention of many as a possible replacement in pipelines for natural gas (~98 percent methane), and as a way to fuel cars, trucks, and larger vehicles. But what is “green” hydrogen? What do we know about it? Here, we review some key features.
“Green” hydrogen is made in an electrolyzer (reverse battery) by using electrons (e-) from renewable electricity (e.g., from wind turbines and solar panels) to split water (H2O) into molecules of hydrogen (H2) and oxygen (O2):
• At Anode: 2 H2O ⇒ O2 + 4H+ 4e-
• At Cathode: 4H+ + 4e- ⇒ 2H2
Transportable, provides higher energy density than batteries, doesn’t produce CO2 or other (net) greenhouse gases (GHGs) when burned or used in fuel cells.
Highly flammable; when piped, leaks through the tiniest cracks; diffuses through plastic pipes; is a strong, indirect GHG. Weight, complexity, and storage costs often negate much or all of its high-energy density advantage, except perhaps at oceanic shipping or utility scales. For energy storage, hydrogen is currently expensive, with low round-trip energy efficiency (RTE — from and back to electricity).
However, the last named disadvantage may soon be overcome. So, let’s assess what that might imply.
One Potentially Large Technical Advance
For example, a recent article in the respected, peer-reviewed journal Nature Communications claims at least 95 percent energy efficiency for its capillary-based electrolyzer. That is, one basic problem with electrolyzers is bubbling that impedes access to the electrodes. But, with this new process, “… water is supplied to hydrogen- and oxygen-evolving electrodes via capillary-induced transport along a porous inter-electrode separator, leading to inherently bubble-free operation at the electrodes.” (3)
If so, as the initial, well-informed commenter put it, this would be the most significant technical advance in electrolytic hydrogen in the past century. Yet, the same commenter also wondered whether this improved process requires less voltage only because KOH (potassium hydroxide), rather than H2O, is being stripped of hydrogen. Thus confirming studies and longer-term data are needed to show that the proposed chemistry is correct and that such laboratory results are scalable to gigawatts over a 30- to 40-year plant life cycle. Such data should be forthcoming from a pilot plant study.
Still, if we assume the process works as claimed and is scalable, and also assume (via more advanced waste heat recovery methods) an 80 percent efficient hydrogen fuel cell with ~10 percent piping losses, then a 95 percent efficient, hydrogen electrolyzer might potentially yield 68 percent RTE (0.8 x (1.0 – 0.1) x 0.95 = 0.68), as opposed to the current maximum RTE for hydrogen energy storage of ~46 percent. (4)
If so, this may cut the levelized cost of storage (LCOS) by more than a third. Yet, such a significant advance might still leave hydrogen storage more costly than liquified air energy storage (LAES) is now, let alone in the foreseeable future. I.e., it seems a tall order, but some forecasters claim, to compete with “blue” hydrogen from fossil fuels, that the cost of “green” hydrogen as a combustible fuel should drop by three times to $2 per kilogram ($0.06 per kilowatt hour (Kwh). (5, 6) Yet, to compare that with LAES, we must also add the cost of converting the “green” hydrogen back to electricity, i.e., $0.06/(0.8 x 0.9) = $0.082/Kwh + levelized fuel cell cost.
However, as of mid-2022, no such advanced (coupled electrolyzer/fuel cell) system exists at utility (>100 Mwh) or even laboratory scales. Utility scale LAES is about to deploy at ~60 percent RTE, while energy storage with supercritical CO2 as the working fluid is slated for pilot plant testing in 2023 at an RTE of 75 to 80 percent, both projecting levelized storage costs of ~$0.05 to $0.06 per Kwh by 2030. (7, 8) Given the above, “green” hydrogen storage might not ever match such values.
Hydrogen Leakage Issues
Now, we need to assess “hydrogen leakage.” Being the lightest and tiniest of molecules, hydrogen leaks and diffuses extremely rapidly. (9) Such leakage is a serious concern because it’s become clear lately that hydrogen is indirectly a very powerful greenhouse gas.
I.e., the main greenhouse mechanism is that, as hydrogen leaks, it hangs around for a few years while soil bacteria and diffusion remove ~70 to 80 percent of it. The rest gets oxidized by naturally occurring hydroxyl radical (OH). But, reacting methane with OH to form CO2 and H2O is nature’s primary way of removing methane. So, OH reacting with hydrogen instead of methane leads to more methane, which is a direct GHG. Another set of reactions involving hydrogen yields ozone, yet another GHG. (10)
Measuring a few large hydrogen leaks is straightforward. But, recall that hydrogen diffuses through plastic piping. However, the industrial community lacks the equipment to measure cumulatively large leakage from millions of tiny leaks. The result has been sparse data. (10, 11) Nonetheless, the Columbia University Policy Center tried to estimate a leakage rate for all potential “green” hydrogen uses: piped combustion, road, air, and oceanic transport, utility and smaller scale fuel cells, to provide 25 percent of a renewable energy economy by the year 2050. Thus, they arrived at an overall hydrogen leakage rate estimate of just 2 to 4 percent, depending on leakiness of installed infrastructure. (11) Yet, the authors also stress low confidence in this estimate, due to the above-mentioned data sparsity.
Assessing Leakage Indirectly
Then again, one might reasonably assess hydrogen leakage indirectly by first noting that a) the Environmental Defense Fund’s 2018 synthesis of 16 studies suggests a mean methane leakage rate of 2.3 percent. It also claims that the rate at which methane provides no mitigating benefit over burning coal is ~3.0 percent. (12) Indeed, a 2020 estimate suggests a methane leakage rate of ~7 percent for U.S. pipelines. (13)
Next, b) whether piped to and burned in homes and businesses or deployed in fuel cells, hydrogen seems to leak ~3 to 5 times faster than methane, depending on whether steel or plastic piping is used. (14) In fact, a recent UK government-commissioned study claimed with high certainty that ~9.2 percent of “green” hydrogen would likely escape from pipelines to the atmosphere, a value that happens to match the median hydrogen leakage rate from above, i.e., ~4 times greater than methane (9.2%/2.3% = 4). (15)
And, c) recently revised estimates of global warming potential (GWP) for methane and hydrogen at 20 years are 86 and 33, respectively. (GWP for CO2 is unity by definition.) (16, 17) So, this suggests an effective 20-year warming value for leaked methane of, 86 x 0.023 leakage + (1 – 0.023) = 2.96. However, the corresponding hydrogen figure is actually slightly higher, 33 x 0.092 leakage = 3.04. (Recall that burning a methane molecule yields a molecule of CO2, but burning hydrogen creates no CO2.) The 100-year GWPs do decline by ~3 times. But, much damage will have occurred long beforehand. Moreover, the above neglects any emissions used to create a hydrogen infrastructure. So, for perhaps far longer than the first 20 years, replacing methane with hydrogen might not mitigate any global warming at all.
Blending “Green” Hydrogen and Methane
In more detail, if a blend of “green” hydrogen and methane were distributed to homes and businesses, a 5 percent blend may be the maximum allowable, as higher percentages enhance steel pipe embrittlement and explosive potential, as well as leakage. (18) Nonetheless, other proposals claim that a 20 percent blend is safe enough, with U.S. and Europe projects proceeding on that basis. (19, 20, 21) Indeed, the Ukraine invasion has provided more impetus to build tens of thousands of kilometers of hydrogen piping throughout Europe, in lieu of low loss, high voltage, direct current transmission lines. (22)
With 9.2 percent leakage as an upper bound, we can then compare a 90 percent green, 25 percent hydrogen economy by year 2050, with our current global emissions rate of ~50 gigatons of CO2 equivalent GHGs per year, (23) that ultimately yields ~20 terawatts of heat, or ~175,000 terawatt hours per year. (24) The energy content of hydrogen is 33.3 Kwh per kilogram. (3)
So, if we assume (despite more people) no increase in global energy production, then the amount of hydrogen needed to replace 25 percent of 90 percent of that production would be (0.25)(0.9)(175 x 1012 Kwh)/(33.3 Kwh/Kg) = ~1.2 gigatons, which at a GWP20 of 33 and 9.2 percent leakage rate, amounts to 3.6 gigatons of CO2 equivalent GHGs per year or 7.2 percent of current emissions via hydrogen leakage, plus the emissions required to build a 25 percent hydrogen infrastructure. In that case, “green” hydrogen would de facto be far less than 71 percent green. And, thereby achieving 90 percent clean energy would also require the other 75 percent of renewable energy sources to yield less than 2.8 percent of current GHG emissions, i.e., be far greener than 96 percent over its whole life cycle from construction through demolition, an implausible task.
Lack of Existing Infrastructure
Then again, using the 2 percent leakage figure above as a lower bound would add just ~0.7 gigatons of CO2 equivalent GHGs via leaked hydrogen. Yet, it would cost far more in dollars and GHG emissions to build and maintain such low-leakage infrastructure. That is, fuel cell powered cars and trucks are 2 to 3 times less energy efficient than batteries, due to their more complex energy cycle, (25, 26) but the lack of existing, suitable infrastructure may present an even bigger barrier to wide adoption of piped hydrogen as well as roadway vehicles.
In summary, electrolyzed hydrogen/fuel cell storage seems at least a decade from commercial viability as a utility scale, energy storage option. And hydrogen/natural gas blends, piped for tens to thousands of miles, to be burned in homes and businesses, may not yield cleaner transition fuels for decades, due to hydrogen’s rapid leakage rate, its nature as a strong, indirect, greenhouse gas, and the emissions from, as well as the “lost opportunity” cost of, building a massive hydrogen infrastructure, rather than something greener. Ergo, it seems prudent for now to retain quotation marks around the “green” hydrogen label, while we review other potential energy storage and transport options for Whatcom County.
1) Why, How, and Who Can Pay to Totally Decarbonize Whatcom County, WA, USA — a Case Study, R. Kamada, researchgate.net, March 22, 2020. https://www.researchgate.net/publication/340094910_Why_How_and_Who_Can_Pay_to_Totally_Decarbonize_Whatcom_County_WA_USA_-_a_Case_Study
2) Utility Scale Battery Storage, National Renewable Energy Laboratory. https://atb.nrel.gov/electricity/2021/utility-scale_battery_storage
3) A high-performance capillary-fed electrolysis cell promises more cost-competitive renewable hydrogen, A. Hodges, A. L. Hoang, G. Tsekouras, et al., Nature Comm.,V13, 1304, Mar. 15, 2022. https://www.nature.com/articles/s41467-022-28953-x
4) Hydrogen technology faces efficiency disadvantage in power storage race, T. DiChristopher, June 24, 2021, S&P Global Market Intelligence. https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/hydrogen-technology-faces-efficiency-disadvantage-in-power-storage-race-65162028
5) Advantages and Disadvantages of Hydrogen, Hydrogen in the Energy Sector, Zittel, Werner & Wurster, Reinhold & Bolkow, Ludwig, Systemtechnik Gmbitt. 1996. https://hypertextbook.com/facts/2005/MichelleFung.shtml
6) Energy is on the cusp of a new era, M. Alvera, Financial Times, July 13, 2021. https://www.ft.com/content/c112cf4b-f19b-4892-9c02-465ec695bc66
7) A Novel Energy Storage System Based on Carbon Dioxide Unique Thermodynamic Properties, M. Astolfi, D. Rizzi, E. Macchi, and C. Spadacini, J. Eng. Gas Turbines Power. Aug 2022, 144(8): 081012 No: GTP-22-1172. https://doi.org/10.1115/1.4054750
8) Liquid-air storage offers cheapest route to 24-hour wind and solar, L. Collins, Recharge News, Sept. 16, 2019. https://www.rechargenews.com/transition/liquid-air-storage-offers-cheapest-route-to-24-hour-wind-and-solar/2-1-635666
9) Cost effective poly(urethane-imide)-POSS membranes for environmental and energy-related processes, D. Gnanasekaran and B. S. R. Reddy, Clean Technologies and Environmental Policy V15, pp. 383–389, 2013. https://www.researchgate.net/publication/235762644_Cost_effective_polyurethane-imide-POSS_membranes_for_environmental_and_energy-_related_processes
10) Climate consequences of hydrogen leakage, I. B. Ocko and S. P. Hamburg, Atmos. Chem. & Phys. Discussions, V22, 14, Atmos. Chem. Phys., 22, 9349–9368, July 20, 2022. https://doi.org/10.5194/acp-22-9349-2022, https://acp.copernicus.org/articles/22/9349/2022/acp-22-9349-2022-discussion.html
11) Hydrogen Leakage: A Potential Risk for the Hydrogen Economy, Z Fan, H Sheerazi, A Bhardwaj, et al., Center on Energy Policy, Columbia.edu, July 5, 2022. https://www.energypolicy.columbia.edu/research/commentary/hydrogen-leakage-potential-risk-hydrogen-economy
12) Assessment of methane emissions from the U.S. oil and gas supply chain, R. A. Alvarez, D. Saval-Araiza, D. R. Lyon, et al., Science,V361, 6398, pp. 186-1, Jun 21, 2018. https://www.science.org/doi/full/10.1126/science.aar7204
13) The US natural gas industry is leaking way more methane than previously thought, A. J. Marchese, D. Zimmerle, July 2, 2018.
14) A National Estimate of Methane Leakage from Pipeline Mains in Natural Gas Local Distribution Systems, Z. D. Weller, S. P. Hamburg,and J. C. von Fischer, Environ. Sci. Technol. 2020, 54, 14, 8958–8967, June 10, 2020. https://doi.org/10.1021/acs.est.0c00437
15) Fugitive Hydrogen Emissions in a Future Hydrogen Economy, Gov. UK Department for Business, Energy & Industrial Strategy, April 8, 2022. https://www.gov.uk/government/publications/fugitive-hydrogen-emissions-in-a-future-hydrogen-economy
16) How Bad of a Greenhouse Gas Is Methane? G. Vaidyanathan, ClimateWire, Dec. 22, 2015. https://www.scientificamerican.com/article/how-bad-of-a-greenhouse-gas-is-methane/
17) Atmospheric Implications of Increased Hydrogen Use, N. Warwick, P. Gri ffiths, J. Keeble, et al. Technical report, UK Department for Business, Energy & Industrial Strategy, 2022. https://www.rechargenews.com/energy-transition/hydrogen-twice-as-powerful-a-greenhouse-gas-as-previously-thought-uk-government-study/2-1-1200115
18) Hydrogen Blending Impacts Study, A. S. K. Raju, A. Martinez-Morales, O. Lever. https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-issues-independent-study-on-injecting-hydrogen-into-natural-gas-systems
19) Gas Utilities Are Promoting Hydrogen, But It Could Be A Dead End For Consumers And The Climate, D. Esposito, Forbes Magazine, Mar. 29, 2022. https://www.forbes.com/sites/energyinnovation/2022/03/29/gas-utility-hydrogen-proposals-ignore-a-superior-decarbonization-pathway-electrification/?sh=151df6a976a1
20) UK’s gas grid ready for 20% hydrogen blend from 2023: network companies, J. Burgess, S&P Global Commodity Insights, Jan. 14, 2022. https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/electric-power/011422-uks-gas-grid-ready-for-20-hydrogen-blend-from-2023-network-companies
21) Southern Co. Gas-Fired Demonstration Validates 20% Hydrogen Fuel Blend, S. Patel, Power Magazine, June 16, 2022. https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/
22) EHB targets 28,000km of hydrogen pipelines by 2030, K. Staines, April 5, 2022, Argusmedia.com. https://www.argusmedia.com/en/news/2318957-ehb-targets-28000km-of-hydrogen-pipelines-by-2030
23) CO₂ and Greenhouse Gas Emissions, H. Ritchie, M. Roser and P. Rosado, 2022, OurWorldInData.org. https://ourworldindata.org/greenhouse-gas-emissions
24) Testify! Ars Answers a Federal Judge’s Questions about Climate Change, S. K. Johnson, Mar. 19, 2018. https://arstechnica.com/science/2018/03/here-are-answers-to-a-federal-judges-queries-about-climate-science/
25) Study confirms what common sense has made clear for years: Hydrogen fuel cells cannot catch up to battery-electric vehicles, F. Lambert, Feb. 15, 2022, Electrek.com. https://electrek.co/2022/02/15/study-hydrogen-fuel-cells-cannot-catch-up-battery-electric-vehicles/
26) Hydrogen or battery, a clear case until further notice, © Volkswagen AG 2022. https://www.volkswagenag.com/en/news/stories/2019/08/hydrogen-or-battery–that-is-the-question.html
Ray Kamada, received a Ph.D. in Atmospheric Science, from the U. California, Davis, in 1985. He has been a peer reviewer for Solar Energy Journal, 1981- 1986; was a National Research Council Postdoc, 1986-87; Adjunct Assistant Professor and Environmental Physics Group Leader, U.S. Naval Postgraduate School, 1988-1993; and a private consultant for the U.S. Dept. of Defense, 1993-2008, specializing in air pollution theory, atmospheric mesoscale modeling and field research. He was a visiting scientist at the RISOE National Laboratory of Denmark/ Danish Technical University, 1986-2014; editor/peer reviewer for the Journal of Renewable and Sustainable Energy, 2010- 2015, and for Kamada Science & Design, 1993-2022. He is also a member of the Whatcom County Climate Impact Advisory Committee, which has neither endorsed, nor whose views may be reflected in, this article.