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May-2022

Flue gas analysers for safe combustion of high hydrogen fuels

Proper flue gas monitoring is critical to ensure safe combustion control, fuel efficiency, and reduced emissions, especially when firing high hydrogen fuels

Tim Tallon
AMETEK Process Instruments

Viewed : 1642


Article Summary

Amidst the global transition to decarbonised assets, combustion remains an important heating source across many industries, including power and steam generation, oil, gas and cement production. While many companies have shifted to using natural gas in their burners to reduce their emissions to air, there is still the opportunity to decarbonise further by using hydrogen as a zero-carbon fuel — either by spiking it into the natural gas header or by using pure hydrogen as the primary fuel source. In the transition to high hydrogen fuels, it will become increasingly important to monitor the stack gas and flue gas to ensure plant safety and efficient combustion control. 

Challenges decarbonising combustion and trends driving use of high hydrogen fuels 
Now more than ever, end users are confronted with the challenges of retrofitting their plants to meet evolving environmental and regulatory targets. Operators of combustion equipment have many options available to meet their long-term decarbonisation targets, including: - Carbon capture to directly remove carbon emissions from the combustion process
- Electrification to generate heat in place of combustion
- Hydrogen fuels to generate heat without carbon emissions
While deciding how to decarbonise is circumstantial, investment costs play an inherently large role in the screening process, especially for very well-established plants. Operators considering carbon capture are faced with justifying the up-front investment and securing adequate plot space for the equipment. In many cases, centralised processes that generate high carbon emissions are primed for carbon capture technology. However, operators face much more of a challenge if they are looking to remove carbon emissions from multiple decentralised combustion sources. In the case of a refinery, there would be considerable difficulty in the logistics of isolating stack gases from multiple fired heaters and then redirecting them to a single carbon removal system. Carbon capture is one option to decarbonise combustion processes, but it also poses a challenge with existing plants that have numerous small and decentralised stack emissions. 

In addition, while many operators may consider electrification to reduce their carbon emissions, it might not be feasible or practical in all cases. For new greenfield projects, electrification presents a viable option for many low-temperature applications, although this approach still depends on an outside mechanism to generate and supply sufficient renewable electricity. However, the real challenge with electrification enters when applying it at a larger scale across the wider installed base of existing plants and equipment. It may not be economical to buy all new electric equipment, especially if multiple combustion processes provide heat, power, and steam to the entire plant. Electrification provides a window to remove emission sources entirely, but it also presents a challenge with existing plants that have many combustion processes (especially processes with very high temperature) or limited availability of external power sources. 

As indicated, the challenges of decarbonisation often arise when the combustion processes are small, decentralised, and scattered across many point sources and when large amounts of energy are consumed for high-temperature process heating. For this reason, many operators are considering the use of hydrogen fuels to reduce the carbon emissions from their combustion processes. In many cases, hydrogen fuels are more often readily implementable for existing equipment and more affordable to decarbonise than other options. Operators may consider firing pure hydrogen or blending the hydrogen with their natural gas to achieve their near-term and long-term emission targets. Some plants may still need to modify their burners or upgrade their piping material to handle high hydrogen fuels. However, with these modifications, operators can continue to use their existing assets and leverage the hydrogen fuel to offset their carbon emissions directly to atmosphere. 
Risks of firing hydrogen and high hydrogen blends vs methane only

Any time an operator changes fuel sources, the implication on process safety is an important consideration. This is especially true when switching to pure hydrogen and high hydrogen fuels. In particular, hydrogen has several physical and combustion properties that differ significantly from methane and other hydrocarbon-based fuels, as shown in Table 1. While some of these differences may impact the burner directly, others can be monitored using flue gas analysis to ensure safe and efficient combustion control.

From the standpoint of physical properties, hydrogen is a very light and fast diffusing gas. Compared with methane, diatomic hydrogen is a very small molecule with 8X less mass than methane, which contributes proportionally to its 8X lower density. Because of its low molecular weight, hydrogen also exhibits very fast molecular speeds that are almost 3X faster than methane at the same temperature, meaning that hydrogen diffuses nearly 3X faster than methane. Altogether, these properties depict the inherent nature of hydrogen to move very quickly in a confined space, such as a combustion chamber. From a safety perspective, unburnt or leaked hydrogen would move much faster in the firebox than methane in the event of a fuel leak or loss of flame, and flue gas analysis is one option to detect and respond to these unsafe conditions. 

From the view of combustion properties, hydrogen is a very reactive and fast-burning gas. Notably, hydrogen displays extremely fast flame speeds that are 10X faster than the flame speed of methane, partly driven by its very fast molecular speeds. Hydrogen flames are also much shorter and hotter burning than methane, which could increase NOx emissions and impact any metal parts used within the burner throat. Hydrogen also has an extremely low minimum pre-ignition energy threshold, which poses a risk of flashback if run at high enough concentrations, especially in premix burners. 

From an operational standpoint, high hydrogen fuels have several implications at the burner and in the combustion control system. In particular, the fuel flow rate of hydrogen fuel will change considerably if measuring the flow rate by mass or volume. If the plant measures flow rate by volume, 3X more hydrogen (by volume) is needed to achieve the same heat release as methane at the same pressure. If the plant measures flow rate by mass, then the hydrogen mass flow rate will be 3X less than the mass flow of methane for the same heat release (at the same pressure) because of the differences in heating value. Piping and burner nozzles sizes should be evaluated to ensure they can handle the required change in fuel flow and to avoid material embrittlement and unexpected pressure changes. In addition, hydrogen requires 20% less combustion air than methane to achieve the same heat release. While burner adjustments can be fixed when permanently switching to a new fuel, these differences in heating value and combustion air requirements have implications if the hydrogen content of the fuel varies over time and/or if the burner switches from natural gas to a high hydrogen fuel, which may be the case in using natural gas during light-off and switching to hydrogen fuels during normal operation. For this reason, it is vital that operators monitor the combustion process and ensure the burner always has adequate combustion air, and flue gas analysis is one approach to safe monitoring of these burner-related parameters.


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