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Fix the driver behind crashes, sound loss and screen glitchesFind Drivers →Repair Windows errors before they cause bigger problemsFix Now →Scan for outdated or missing drivers - takes under a minuteDriver Scan →Steam methane reforming (SMR) makes hydrogen by reacting methane with high-temperature steam, then converting carbon monoxide into additional hydrogen. Biogas can potentially supply some of the methane-rich gas, but it is not automatically interchangeable with pipeline natural gas: composition, contaminants, cleanup, and the existing plant’s design all matter. Nor does a biogenic feedstock label, by itself, establish low lifecycle emissions.
How does steam methane reforming produce hydrogen?
In a reformer, methane reacts with steam over a catalyst. The U.S. Department of Energy (DOE) gives a representative operating range of 700–1,000°C and 3–25 bar for natural-gas reforming. The main reaction is endothermic, so heat must be supplied:
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CH₄ + H₂O + heat → CO + 3H₂
The reaction produces carbon monoxide as well as hydrogen. A second stage, the water-gas shift reaction, uses more steam to convert some of that carbon monoxide into carbon dioxide and additional hydrogen:
CO + H₂O → CO₂ + H₂ + a small amount of heat
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Finally, pressure-swing adsorption (PSA) separates hydrogen from carbon dioxide and other impurities, yielding essentially pure hydrogen. The reaction sequence and operating range are described in DOE’s natural-gas reforming explainer.
Can biogas be used to make hydrogen?
Potentially. Biogas contains methane derived from organic material, so its methane can be considered as a source of reformer feed or fuel. The underlying reforming chemistry is not tied to whether methane is fossil or biogenic. The practical question is whether a particular gas stream, after any needed treatment, can meet the needs of a particular plant.
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Biogas composition varies with its source and processing, unlike a consistent pipeline gas specification. The International Energy Agency (IEA) identifies sustainable biogas feedstocks such as crop residues, manure, biowaste, and woody biomass in its Outlook for Biogas and Biomethane. DOE also includes anaerobic digester gas among hydrogen pathway categories in its hydrogen production pathways overview. These sources support biogas as a recognized potential input category; they do not show that untreated biogas can be fed directly into any existing SMR unit.
What a process-modeling study found
A 2023 NREL-authored process-modeling study examined biogenic gases in existing steam-reforming processes. For the CO- and CO₂-rich gas compositions modeled, it found that replacing natural gas in the reformer fuel train, followed by partial replacement in the feed train, may be feasible. The study modeled up to 25 mol% biogenic gas in the feed train using allowances in existing designs or small modifications while maintaining similar hydrogen output. That is a result for the study’s assumed gas compositions and design conditions—not a universal blend limit, operating recipe, or performance guarantee. See the 2023 study hosted by NREL.
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What a plant would need to evaluate
Before integrating biogas, an operator would need plant-specific engineering review of the gas composition and contaminants, cleanup requirements, process configuration, catalyst, and operating controls. The cited sources do not establish a universal gas-quality specification or guarantee that a given plant can use a particular biogas stream.
What determines hydrogen’s climate impact?
Feedstock origin and emissions intensity are separate questions. The same basic reforming chemistry can use methane from fossil natural gas or biogenic gas, but the lifecycle result depends on factors including methane leakage, process heat, carbon capture coverage, and the accounting boundary.
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The IEA’s Global Hydrogen Review 2024 estimates that global hydrogen production emitted 920 Mt CO₂ in 2023. It reports that nearly two-thirds of production came from unabated natural gas, with emissions of 10–12 kg CO₂-equivalent per kg H₂. These are IEA estimates for the stated year and production context, not the footprint of every SMR plant. The IEA says 75–95% of emissions occur directly at production and can be reduced through carbon capture, while upstream and midstream emissions also need attention. See IEA’s emissions discussion in the Global Hydrogen Review 2024.
Carbon capture can reduce emissions, but does not settle the full accounting
For SMR, the IEA estimates abatement costs of USD 60–85 per tonne of CO₂ at capture rates of 55–70%, and USD 85–110 per tonne of CO₂ for capture rates above 90%. These are report estimates under the IEA’s assumptions, not quotes for a specific project. A capture rate also does not, on its own, say which emissions streams are covered or account for upstream methane and other emissions.
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DOE documented an earlier proposed Port Arthur demonstration to capture and sequester CO₂ from SMR process gas at two hydrogen production plants. It shows that process-gas capture has been pursued at industrial scale; it does not establish that every emissions stream is captured or provide evidence of the project’s current operating status. See DOE’s Port Arthur demonstration environmental assessment.
Biogas systems can also emit methane
Biogenic origin does not guarantee negligible emissions. The IEA’s 2025 biogas outlook estimates methane emissions from biogas and biomethane plants at 2–5.5% of output. It identifies closed digestate storage, combustion of upgrading off-gases, and leak detection and repair as important mitigation practices. The estimate concerns biogas and biomethane plants, not a universal leakage rate for every facility. See the IEA Outlook for Biogas and Biomethane.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.What to conclude about biogas and SMR
SMR’s established chemistry is methane plus steam, followed by a shift reaction and hydrogen purification. Biogas may be usable as a biogenic gas source or partial substitute in suitable configurations, but compatibility depends on the gas and the plant. The 25 mol% result applies only to the compositions and design conditions modeled in the 2023 study. To assess climate performance, evaluate the full chain—including gas production and leakage, process heat, and the scope of any carbon capture—rather than relying on the feedstock label alone.
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