Boilers running on hydrogen: What you need to know

Hydrogen can be introduced to eliminate CO emissions from the system without increasing risk associated with packaged boiler or burner design and operation.

By Gerardo Lara

Environmental pressure has ramped up of late. Many countries have issued targets to reduce or even eliminate the use of traditional fossil fuels in order to reduce the emission of greenhouse gases such as CO2.

As a result, those running packaged boilers can expect at least a partial transition over the next decade from natural gas to hydrogen. This will begin gradually with blends that include a small amount of hydrogen. Over time, the percentage will be increased as supplies of hydrogen become more available.

But how exactly will this impact the boiler? What do boiler operators need to know? How will maintenance practices change?

The first thing to realize is that boilers have been running successfully on hydrogen blends for decades. Operators and boiler manufacturers have plenty of experience in coping with the differences between hydrogen and natural gas. But as the percentage of hydrogen rises, significant adjustments will have to be made.

In this article we will focus on package boilers which are perhaps the easiest type of boiler in which to introduce hydrogen due to their flexibility and straightforward design. Whether the packaged water tube boiler serves as a back-up boiler for a combined heat and power (CHP system), is used for district heat or is producing steam to generate power in a steam turbine, hydrogen can be introduced to eliminate CO emissions from the system without increasing risk associated with packaged boiler or burner design and operation.

Hydrogen has significantly different characteristics than natural gas. It is a much lighter molecule than methane with a lower BTU value per unit of volume. Natural gas has about five times the heating value per unit of volume. Thus far more hydrogen will be needed than natural gas. This will show up in various ways. The piping required for hydrogen and the metering station will typically be larger than what is needed for natural gas.

Due to the higher flame temperature of hydrogen, combustion takes place with a peak flame temperature of about 4,000°F compared to about 3,600°F for natural gas. That leads to inherently more NOx, which has to be mitigated in various ways. The flame temperature, therefore, introduces a slight possibility of overheating. The good news, though, is that most modern furnaces today utilize a membrane wall construction with water-cooled surfaces. This means they are already equipped to deal with higher temperatures without the need for changes.

Further, the conservate design practices of the industry generally lead to furnaces being a little oversized. Thus, adding a little hydrogen rarely means having to make the furnace larger. In a worst-case scenario, the boiler would have to be designed to have a slightly larger furnace. And firing with H2 adds extra volume to the exhaust gas flow compared to firing natural gas.

What about the burners? The burner company typically determines the best size for the fuel injectors. Minor modifications may be needed, depending on the amount of hydrogen. The pressure of the hydrogen could also impact performance. Therefore, it is recommended that a dedicated hydrogen supply system be designed with larger piping to accommodate the higher volume of gas needed and deliver it at the desired pressure and obtain the same BTU input to the boiler.

In some cases, slight redesign and oversizing modifications will be required to compensate for any performance hit. Hydrogen components, in general, are likely to be larger and more expensive.

Some worry about the lightness of hydrogen causing safety issues. One concern, for example, is that unburned hydrogen could collect in pockets at the top of the boiler due to its low molecular weight. Again, the modern design of packaged boilers of the D, O, and A styles leaves very little room for hydrogen to accumulate. As a safety precaution, though, purge cycles may be mandated. This will easily get rid of any unburned hydrogen to eliminate any risk of explosion.

Take the case of a theoretical packaged boiler running at around 600 PSIG and at 750°F that can deal with 100,000 lbs per hour. Efficiency will be lower with hydrogen (less than 80%) at high heating value (HHV) compared to natural gas (84%). But this can be misleading. At a low heating value (LHV), hydrogen efficiency risen to almost 95% whereas natural gas at LHV is only 93%. The important thing is to know whether you are dealing with HHV or LHV numbers. Confusion could lead to misunderstandings and miscalculations.

In the real world, these HHV and LHV differences exert an impact on boiler characteristics and performance. For example, superheated steam from hydrogen in our theoretical boiler example would have a steam temperature of 730°F. The same boiler running only on natural gas would have superheated steam at 750°F. This is all down to the lower mass flow of hydrogen. Minor design tweaks may be needed to add more heating surfaces to the boiler to raise the steam temperature to the design value.

A lot has been said about the impact of hydrogen on NOx levels. Many say that hydrogen will send NOx numbers much higher. But a few experts are questioning this.

For now, let's assume that NOx will indeed be higher as a side effect of the higher flame temperature of hydrogen. This won't be the case if hydrogen is introduced in minute quantities. But above 5% hydrogen will push NOx above what would be experienced with regular natural gas. Mitigation efforts will have to be introduced to compensate.

Flue gas recirculation (FGR) and selective catalytic reduction systems (SCR) are the accepted methods. For FGR, the forced draft fan used in a 100,000 lbs per hour boiler would actually be smaller than for natural gas. The natural gas fan would be about 350 hp while a fan for a gas rich in hydrogen would only need to be about 250 hp.

Why a less powerful fan? Less combustion air is needed in combustion of hydrogen compared to natural gas.

Be aware, however, that water dew point of the flue gas rises when firing hydrogen. Any cold parts of the boiler in contact with flue gas will form higher levels of condensation. Designers should be aware of this phenomenon and ensure that drains and drying measures are implemented aa needed.

Firing boilers with some hydrogen content if far from a new concept. Petrochemical and oil & gas operations have been doing it for decades as their processes often produce hydrogen as a byproduct.

A chemical plant in Texas, for instance, has been running with some hydrogen for more than 15 years. Its 250,000-lb/hr packaged steam generators deliver 1300-psig/950°F steam. The boilers burn natural gas, residual cracker gas, and off-gas that contains varying amounts of hydrogen. The hydrogen content works out at about 8.5% or less. The boiler control system regulates the flow of air and fuel. The SCR is used to assure emissions compliance.

Thus, hydrogen is nothing new in boiler operation. However, as the hydrogen content rises, some changes in design, operation, and maintenance may be needed.

The good news is that current boilers tend to be conservatively designed, so they are probably in a good position to accommodate the burning of higher amounts of hydrogen.

Gerardo Lara is Vice President Fired Boiler Sales at Rentech Boiler Systems, Inc. of Abilene, TX. For more information, visit www.Rentechboilers.com