If you operate a fire-tube or water-tube boiler on natural gas, LPG or diesel, this page covers what a plant engineer needs to know before evaluating hydrogen: what changes in the combustion, what has to be modified, and when substitution can be total rather than partial.
The honest starting point: hydrogen is not a drop-in fuel. It changes the physics of the flame, and that has concrete consequences for the burner, for flame detection and for NOx emissions. All of them have known solutions, but ignoring them is what makes conversion projects fail.
What actually changes in the combustion
| Property | Natural gas | Hydrogen | Practical consequence |
|---|---|---|---|
| Adiabatic flame temperature | ~1,960 °C | ~2,100 °C | More thermal NOx unless the burner is redesigned |
| Laminar flame speed | ~0.4 m/s | ~2.9 m/s | Flashback risk with premix burners |
| Energy per volume | ~35.8 MJ/Nm³ | ~10.8 MJ/Nm³ | ~3× volumetric flow for the same power |
| Flame luminosity | Visible, blue-orange | Nearly invisible | Requires ultraviolet flame detection |
| Combustion products | CO₂ + water vapour | Water vapour only | Zero point-of-use carbon emissions |
The flame you cannot see
This is the most important safety point and the one least often mentioned in sales material. Hydrogen produces no soot, and without incandescent particles the flame emits very little visible light: in daylight it can be effectively invisible.
Conversion therefore requires replacing visible-light or ionisation flame detectors with ultraviolet or combined UV/IR sensors, and revalidating the complete burner safety interlock chain. This is a requirement, not an accessory.
Partial or total substitution
- Up to ~20% by volume. Most industrial natural gas boilers accept this blend without burner modification. Lowest-investment entry point.
- Between 20% and 60%. Injection orifices, air-fuel ratio and almost always flame detection need revision. The boiler itself is unchanged.
- 100% hydrogen. Requires a burner designed or converted for hydrogen. The boiler shell, furnace and steam circuit are normally retained.
In practice, serious industrial projects start with a blend and scale. It validates equipment behaviour at low cost before committing capital to full conversion.
What gets modified and what does not
| Component | Changes? | Detail |
|---|---|---|
| Boiler shell | No | Heat transfer surfaces and steam circuit retained |
| Burner | Depends on blend | Unchanged to ~20%; redesign or replacement for 100% |
| Flame detection | Yes | Migrate to UV or UV/IR |
| Fuel lines | Yes | Resize for higher volumetric flow; hydrogen-rated sealing |
| NOx control | Evaluate | Staged combustion or FGR depending on local limits |
| Leak detection | Yes | Hydrogen sensors at high points; it rises, it does not pool |
On cost, without spin. Compared purely on cost per unit of energy at today's prices, on-site produced hydrogen does not beat coal or LPG. Anyone claiming otherwise is showing you an incomplete calculation.
What changes is what your fuel cost depends on. Producing hydrogen on site with electricity moves your fuel from an imported commodity priced in dollars to your own local electricity tariff. The case is built on total cost and price stability over a ten-year horizon, not on this month's price per MMBtu.
Frequently asked questions
Can a natural gas boiler burn hydrogen without modification?
Partially. Most industrial gas boilers tolerate blends of up to roughly 20% hydrogen by volume without touching the burner, because the resulting Wobbe index stays inside the design envelope. Above that, the burner, injection orifices and flame detection need work. Running on 100% hydrogen requires a burner designed or converted for it.
Why is an invisible flame a safety problem?
Hydrogen burns without soot, so it emits almost no visible radiation and the flame can be effectively invisible in daylight. An operator can walk into a burning leak without seeing it. Conversion therefore requires replacing visible-light or ionisation flame detectors with ultraviolet or combined UV/IR sensors, and revalidating the burner safety interlocks.
Does hydrogen produce more NOx than natural gas?
It can, and that has to be stated plainly. Hydrogen's adiabatic flame temperature is around 2,100 °C against roughly 1,960 °C for methane, and thermal NOx rises exponentially with temperature. It is controlled with staged combustion, flue gas recirculation or lean premix burners. It is a known burner design problem, not a blocker.
Does the boiler produce the same amount of steam?
Yes, provided the burner is correctly sized. Heat output depends on the mass flow of fuel and its calorific value, not on which fuel it is. What changes is volumetric flow: hydrogen carries about 10.8 MJ per normal cubic metre against roughly 35.8 for natural gas, so about three times the volume must be moved for the same power. That is why fuel lines and orifices are resized.
Does existing plant pipework need replacing?
It depends on material and pressure. Hydrogen can embrittle certain high strength steels at elevated pressure, but at the low distribution pressures typical of burner supply lines, ordinary carbon steel and stainless steel perform well. What always changes is the sealing philosophy: the molecule is far smaller, requiring specific seals, gaskets and leak detection protocols.
Talk to the engineers who build it
We manufacture the equipment in Medellín, Colombia, and we size it against your actual thermal load — not a generic brochure figure.
Contact the team