November 2022

Heat Transfer

Decarbonizing your fired heaters with hydrogen fuel

Hydrogen has long been considered a high-value product, but not typically as a fuel for fired equipment.

Hydrogen (H2) has long been considered a high-value product, but not typically as a fuel for fired equipment. However, as the world seeks cleaner, more sustainable solutions, H2’s unique property of producing zero carbon dioxide (CO2) when combusted has been gaining attention. H2 may be the “silver bullet” for eliminating CO2 emissions in fired heaters. However, making the switch does come with challenges. FIG. 1 represents the potential to reduce yearly CO2 emissions in a 100-MMBtu/hr (fired duty) heater.

FIG. 1. Yearly CO2 emissions in tpy vs. vol% H2 in fuel for a 100-MMBtu/hr (fired duty) heater. This assumes the balance of fuel is CH4, with 15% excess air.


As a basic building block of life and the most abundant element in the universe,1 H2 is a unique molecule with unique challenges. However, without attachment to carbon, it is a vastly different molecule with distinctive properties when combusted. The following are some of the potential challenges associated with switching to all or partial H2 firing:

  • Higher flame temperature
  • Higher flame speed
  • Flame visibility (or lack thereof)
  • Radiant/convection duty split
  • Impact to radiant heat transfer
  • Corrosion mechanisms
  • Changes to safety and control methods
  • Burner piping and fuel gas skid resizing
  • Stack plume visibility.

High-temperature flame

Increasing the amount of H2 in fuel gas has a significant impact on the flame temperature, as shown in FIG. 2. While FIG. 2 is based on the adiabatic (i.e., theoretical) flame temperature, it highlights that a 100% H2 flame can be hundreds of degrees hotter than a flame from hydrocarbon fuels. The primary issue with this effect is that the formation of thermally generated nitrous oxides (NOx) increases proportionally with flame temperature.2

FIG. 2. Adiabatic flame temperature (AFT) in °F vs. vol% H2 in fuel. This assumes the balance of fuel is CH4, with 15% excess air.

Fortunately, several options can counteract the increase in NOx emissions. Burner design modifications (i.e., retrofit) can be considered first. External flue gas recirculation and/or steam injection may also be implemented to lower the flame temperature. If these methods are insufficient, selective catalytic reduction may be required.

High flame speed

Flame speed—the rate at which a combustion reaction takes place for a given fuel—is a critical variable in fired heater design and operation. To use a simplified scenario, it can be conceptualized as the speed at which a gas will fully combust if the gas was contained in a long tube and ignited at one end. In actual practice, flame speed depends on several factors, including pressure, temperature, fuel composition, excess air, turbulence and surrounding cooling effects.3 However, in an idealized environment consisting of laminar flow at 77°F and 14.7 psia of pressure, a tube filled with H2 and lit at one end will complete the combustion reaction at the opposite end of the tube roughly 7× quicker than a tube filled with methane (FIG. 3).3,4

FIG. 3. Graphic depicting the approximate laminar flame speed of hydrogen vs. CH4 at 77°F and 14.7 psia of pressure.3

To ensure reliable, safe combustion in a process burner, it is vital to control the speed of the un-combusted air/fuel mixture so it is appropriately matched to the speed of combustion or flame speed. If the air/fuel speed is lower than the flame speed, the combustion reaction can travel backward into the burner and upstream equipment (i.e., flashback). Flashback potential is especially important to consider for pre-mix burners.2 Therefore, before switching to H2 fuel from hydrocarbon fuel, it is essential to review the burner design to ensure it can accommodate the air/fuel speeds necessary for safe operation.

Flame visibility

The ability to verify the presence of a stable flame at each burner is paramount to safely operating a fired heater. Usually, this can be done by visual inspection or with conventional flame scanners when firing hydrocarbon fuel gases. However, when 100% H2 is used as a fuel source, the flame becomes virtually invisible. This is demonstrated in FIG. 4A, in which a burner firing 100% H2 can be seen. In contrast, FIG. 4B depicts nearly all H2 combustion with a small percentage of natural gas.5 Clearly, a small quantity of natural gas in the fuel can dramatically enhance the ability to see the flame.

FIG. 4. Picture (A) of a process burner firing 100% H2, and a process burner (B) firing mostly H2 with a small percentage of natural gas.3

In situations where hydrocarbon fuel gas is unavailable or not allowed, alternate methods of detecting the flame, such as specialized ultraviolet flame scanners or sound monitors, may be potential solutions.

Radiant/convection duty split

As represented in FIG. 5, increasing H2 content in the fuel can significantly decrease the quantity of flue gas generated.

FIG. 5. Flue gas flowrate vs. vol% H2 in the fuel for a 100-MMBtu/hr (fired duty) heater. This assumes the balance of fuel is CH4, with 15% excess air.

For an existing heater being revamped to run on H2 fuel, this reduction in thermal mass traveling through the convection section decreases the heat absorbed. In a single service heater (i.e., the same service in the convection and radiant section), this may be counteracted by increasing the heat absorbed in the radiant section, with careful attention paid to the increased radiant flux, bridgewall temperature and tube metal temperatures. However, if there is a second, independent service in the convection section, the convection coil must be reconfigured to maintain the original heat absorbed. The effects on draft and fan operation, as applicable, should also be considered. Excess air may be increased to generate more thermal mass; however, this will also increase NOx emissions and reduce efficiency.

Impact to radiant heat transfer in the firebox

In the firebox (radiant section), heat is transferred to the process tubes by three main methods of radiation:2

  • Direct radiant from the flame (i.e., flame burst)
  • Reradiation from flue gases
  • Reradiation from refractory surfaces.

The radiation from the flame is related to its luminosity and may impact heat transfer. Luminous radiation is the radiation from solid particles suspended in the flame.6 For example, an oil flame has three to four times more flame radiation due to increased luminosity created by soot content.2 For a flame from pure H2, luminosity is reduced to virtually zero, which may decrease the radiant heat transfer slightly.

However, contribution from direct flame radiation is typically low vs. other forms of radiation in the firebox, as evidenced by combination oil and gas burners that have been in operation with little change in performance noted between fuels fired.2

Reradiation from flue gases occurs primarily from CO2, H2O and sulfur dioxide (SO2) molecules.7 Symmetrical molecules [nitrogen (N2), O2 and carbon monoxide (CO)] are considered “transparent” and do not reradiate heat.7 An all-H2 flame produces significantly more H2O, which has higher emissivity than CO2. Since CO2 is eliminated entirely from the flue gas and is essentially replaced with H2O, this will have the tendency to increase radiant heat transfer.

As mentioned previously, a H2 flame has a higher temperature than a methane (CH4) flame, which may increase the surface temperature of the refractory that is in close proximity to the flame. This may also increase heat transfer in the radiant section. While a reduction in luminosity may reduce direct radiation from the flame, increased emissivity of flue gas molecules and increased refractory temperatures will likely offset this effect, suggesting that current methods for radiant heat transfer calculation are adequate for H2 firing. The authors’ company recently performed a study of a petrochemical heater designed for and operating with up to 90 vol% H2 fuel. The study found that the predicted firebox temperature and the field measured temperature matched very closely (within 5°F).

Potential corrosion mechanisms

The industry standard for corrosion mechanisms (API 571: “Damage mechanisms affecting fixed equipment in the refining industry”) mentions the three major corrosion mechanisms involving H2:8

  • H2 embrittlement (HE)
  • H2 stress cracking from exposure to hydrofluoric acid (HSCHF)
  • High-temperature H2 attack (HTHA).

HSCHF can be ruled out under the assumption that no hydrofluoric acid is involved in this application. That leaves HTHA and HE: HTHA typically occurs at high temperature and pressure (refer to API 941 for temperature and pressure limits for various materials); while HE typically occurs at lower temperatures (< 300°F) and pressures at or near atmospheric.

In both mechanisms, atomic H2 (as opposed to molecular H2) forms and diffuses into steel. Once inside the steel, it can react with the carbon to form CH4, which can create pressure and cracking.8

Fuel gas delivery systems typically do not operate at high enough pressure for HTHA to be a concern. High-strength steels with high hardness numbers can be susceptible to HE. According to API 571, the effect is pronounced at temperatures from ambient to about 300°F, corresponding to the range of most fuel gas systems.8 While the softer carbon-steel piping typically used is generally not susceptible to HE, welds, bolted connections and burner internals comprised of high-strength steel may be areas of concern. Careful review of the fuel gas delivery system should be performed before switching to H2 fuel.

Safety and controls

H2 has a wide range of flammability in air, approximately 4 vol%–75 vol%.9 These properties give H2 the National Fire Protection Association’s (NFPA’s) highest flammability rating of 4.9 While CH4 also has a flammability rating of 4, it requires more energy to ignite and is easier to detect.

Due to its low molecular size, H2 may be susceptible to leakage in fuel gas piping designed for hydrocarbon fuels. H2 gas is colorless and odorless. Due to its high diffusion rate in air, H2 does not blend well with the comparatively heavier mercaptans that are added to CH4 to give it an odor. Therefore, H2 leak detection instruments may need to be added to a fuel gas system before switching to 100% H2 firing.

H2 fuel also requires significantly less air to combust stoichiometrically vs. CH4. This is a key point to remember, especially if switching between H2 and CH4 fuels while the heater is in operation. When firing H2, the heater controls should be adjusted to reduce the combustion air. However, if a switch back to CH4 fuel is made quickly, without sufficient adjustments to increase combustion air, the CH4 will not fully combust and creates a potentially unsafe, fuel-rich environment. A fuel gas system that accurately measures the fuel gas composition and controls the combustion air accordingly is critical.

Burner piping and fuel gas skid sizing

For a given heat release, 100% H2 fuel requires significantly less mass flowrate than CH4. However, the volumetric flowrate required is more than three times as high, as displayed in FIG. 6.

FIG. 6. Mass and volumetric fuel gas flowrate with increasing vol% H2. This assumes a 100-MMBtu/hr (fired duty) heater, the balance of fuel is CH4, with 15% excess air. As such, the fuel gas skid and burner piping leading to the heater should be carefully reviewed to ensure proper pipe sizing for acceptable hydraulics.

Stack plume

The key variable contributing to the visibility of flue gas exiting a stack is its water and content.10 After exiting the fired heater, hot flue gas cools and the water in the flue gas condenses, often creating a visible white fog. Although not necessarily harmful, this visible water plume may become a nuisance to neighboring communities and act as a transport medium for other pollutants in the gas. This poses a potential challenge as combusting higher quantities of H2 yields higher quantities of water in the flue gas. As demonstrated in FIGS. 7A and 7B, with 100% H2 fuel, the water content in the flue gas increases to approximately one third of the flue gas volumetrically.

FIG. 7. Chart A shows vol% flue gas composition with 100% CH4 fuel and 15% excess air, and Chart B shows vol% flue gas composition with 100% H2 fuel and 15% excess air.

The water content may be reduced by burning less H2 in the fuel. If this is not an option, the end user may consider a system to reduce the water content in the flue gas. This could be accomplished by diluting or reheating the gas before it exits the heater. Alternatively, methods to condense and collect the water may be considered.

Making fired heaters H2-ready

Clearly, many unique challenges are associated with designing and converting fired heaters to H2 fuel firing. However, the potential to reduce CO2 emissions in a fired heater is unlimited if 100% H2 fuel is utilized. Furthermore, the challenges are not new to the authors’ company, which has been designing fired heaters with high H2 fuel content for decades. A partial list of recent relevant experience is provided in TABLE 1.

Making the switch to H2 fuel is an exciting, yet challenging endeavor. Teaming up with experienced fired heater experts is a vital step in the development of safe, effective solutions to the many challenges involved. HP


  1. Silberberg, M., Principles of General Chemistry, 1st Ed., McGraw Hill, New York, 2007.
  2. Baukal, C. E., The John Zink Combustion Handbook, CRC Press, Boca Raton Florida, 2001.
  3. Reed, R. J., North American combustion handbook: A basic reference on the air and science of industrial process heating with gaseous and liquid fuels, Vol. 1, 3rd Ed., Fives North American Combustion Inc., 2001.
  4. Glassman, I. and R. A. Yetter, Combustion, 4th Ed., Academic Press, Cambridge Massachusetts, 2008.
  5. Guarco, J., B. Langstine and M. Turner, “Practical considerations for firing hydrogen versus natural gas,” Zeeco.
  6. Sherman, R., “Radiation from luminous and non-luminous natural gas flames,” PhD thesis, Transactions of the America Society of Mechanical Engineers, 1934.
  7. Mekler and Fairall, “Evaluation of radiant heat absorption rates in tubular heaters,” Petroleum Refiner, 1952.
  8. American Petroleum Institute (API), Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, 2nd Ed., API 571, April 2011.
  9. Rivkin, C., R. Burgess and W. Buttner, “Hydrogen technologies safety guide,” National Renewable Energy Laboratory (NREL), 2015.
  10. Herssens, Y. and S. Safariyeganeh, “Supressing the steam plume,” Digital Refining, 2021.

The Authors

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