Introducing hydrogen into refinery boilers, turbines, and HRSGs (TIA)
Refineries and petrochemical facilities are under environmental pressure on all fronts. They are being asked to reduce their carbon footprints and aim for a net-zero carbon target over the next couple of decades. One proposal to achieve such targets is to replace or augment natural gas combustion with hydrogen in refinery boilers and power generation units.
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Why? Natural gas generation blended with 30% hydrogen by volume delivers an 11% reduction in CO2. Thus, hydrogen is seen by some as a quick way to reduce greenhouse gas emissions (GHG).
Refineries are often in a good position to institute such measures as they often possess excess hydrogen as a byproduct of other processes. Hydrogen, after all, is nothing new in packaged boilers and heat recovery steam generators (HRSGs) used in combined cycle power units. They have successfully operated for many years on hydrogen blends.
For example, Valero’s Port Arthur refinery in Texas produces over 100 million ft3/d of high-purity hydrogen. It uses it in a blend with natural gas to fuel a combined cycle plant using a GE Frame 7EA 80 MW gas turbine. It has an HRSG designed for supplemental duct firing of up to 550,000 lb/hr and a ramp rate of up to 60,000 lb/hr per minute. A steam methane reformer (SMR) hydrogen plant is integrated into the facility to provide additional steam. Exhaust from the gas turbines is used by the HRSG and the SMR. A 20 MW auto-extraction/back pressure steam turbine produces power and exports steam at two different pressures.
Further examples include a plant fired by refinery gas where the hydrogen in the fuel can range from ~30% to 80% but is typically about 50%. The HRSG is coupled to a 22 MW gas turbine. There are many similar examples across the industry.
In the coming months, more petrochemical facilities will consider harnessing hydrogen to improve their environmental credentials. Those planning to do so should consider several factors:
Hydrogen is different Hydrogen is quite different to natural gas in many ways. It has a higher flame temperature, is far lighter, and produces more condensation as part of the combustion process. As a result, the water dew point of the flue gas increases when firing hydrogen. Operators should also be aware that colder parts of the HRSG in contact with flue gas will suffer from high levels of condensation. Further, hydrogen combustion requires a higher volume of exhaust gas flow than natural gas.
Emissions Those burning hydrogen with natural gas can expect to see a spike in NOx emissions. This is due to the higher flame temperature of hydrogen compared to natural gas. NOx level changes will be negligible if the hydrogen content by volume stays at 5% or less of the fuel blend. Beyond that point, mitigation steps such as flue gas recirculation (FGR) and selective catalytic reduction systems (SCR) will be needed. Once hot gases have moved through the HRSG and converted water to steam, they need to be mixed with ammonia before being released into the atmosphere.
The peak flame temperature of hydrogen is also higher. It is about 4,000°F compared to about 3,600°F for natural gas. Thus, more NOx is generated. This is not a factor with tiny quantities of hydrogen. However, beyond roughly 5% hydrogen by volume, emissions mitigation measures will be needed, such as FGR and SCR.
Condensation The water dew point of flue gas rises when hydrogen is fired. As a result, cold parts of the boiler or HRSG in contact with flue gas may be susceptible to higher levels of condensation. Drains and drying measures should take this factor into account.
Safety Hydrogen introduces additional safety concerns that must be dealt with. There is a greater risk of explosion and leakage. With hydrogen being such a light molecule, valves, pipes, and systems, in general, will have to be designed to prevent and detect leakage and minimise the risk of explosion.
Auxiliaries Hydrogen supply lines require bigger pipes, larger metering stations, and other minor modifications than natural gas ones. Supply system designs must accommodate a higher volume of gas needed at the desired pressure to obtain the necessary BTU input for the boiler or HRSG.
Burner changes Burner companies should be consulted to determine what modifications, if any, might be needed to fuel injectors. The presence of hydrogen and the amount of hydrogen being added to the gas mixture may require some changes.
Retrofit or replace There are plenty of ageing boilers and HRSGs out there. If the amount of hydrogen being introduced is small, there might be little or no need for any modifications. However, once the percentage of hydrogen rises, modifications are inevitable.
There may come a point when the facility should consider whether it is best to retrofit the boiler or HRSG or replace it entirely with one designed to cope with a high percentage of hydrogen. Bear in mind that the more enthusiastic elements of the environmental lobby are pushing for 100% hydrogen. This is unlikely to happen for quite some time. However, refineries are probably in a strong position to achieve high amounts of hydrogen compared to the many others who lack access to it.
In those cases were extensive and expensive modifications are required to operate on the desired amount of hydrogen, it may be easier and cheaper in the long run to replace the old HRSG or boiler with one designed for hydrogen combustion. Bear in mind that retrofits that require adding an SCR to an HRSG are extremely challenging.
This short case study originally appeared in PTQ's Technology In Action Feature - Q1 2023 Issue.
For more information: KSlepicka@rentechboilers.com
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