Hydrogen firing in gas turbines and its impact on HRSGs

Above: HRSGs in a combined cycle power plant. (Source: NEM Energy)

Global pressure to reduce use of traditional fossil fuels and cut emissions of greenhouse gases such as carbon dioxide is enormous. Consequently, the gas turbine industry is taking action. One of the key focus areas for reducing carbon dioxide emissions from gas turbines is to switch fuel from natural gas (typically CH4) to hydrogen.

The various gas turbine OEMs, as well as utilities and other users of gas turbines, are currently investigating the impact of firing H2 in their machines. A lot less attention is given to the impact of hydrogen firing on equipment complementary to gas turbines, notably heat recovery steam generators (HRSGs), to which a large proportion of the global gas turbine fleet is connected.

Mixing H2 with natural gas will result in an immediate CO2 emission reduction from gas turbines. The graph on p13 shows the non-linear relationship between increasing the hydrogen content (%vol) in a natural gas fuel mixture and the resulting CO2 emissions (%vol). The most significant CO2 savings are gained from replacing the last ~20% (by vol) of natural gas with H2.

But there are potential side effects for HRSGs of increased hydrogen firing that need to be considered. Depending on the gas turbine conditions set by the gas turbine OEM, the following considerations require attention:

• First of all safety aspects, related to potential H2 accumulation in the ‘attic’ of the HRSG in case of a gas turbine or duct burner trip.
• Higher NOx emissions in the incoming gas turbine exhaust gas, impacting the size and cost of the selective catalytic reduction (SCR) system required.
• Possible higher gas turbine exhaust volume flow and exhaust gas inlet temperature.
• Increased water content in the gas turbine exhaust gas, leading to higher risk of water condensation in the cold end. This increase in water dew point is however minimal up to 50% vol hydrogen content.
• Impact on HRSG performance and gas side pressure drop.
• Burner system related challenges for HRSGs employing supplementary H2 co-firing.

Safety aspects

Safety concerns relating to hydrogen firing and HRSGs specifically arise in the event of gas turbine or duct burner trip. Potential accumulation of hydrogen in the ‘attic’ of an HRSG in such circumstances is a particular consideration for horizontal-exhaust-flow HRSGs. Design evaluation of the HRSG casing and attic and additional measures for optimal venting, can be applied as risk mitigation actions in accordance with NFPA and other applicable guidelines of local authorities.

Higher NOx emissions in the GT exhaust gas

During combustion, the local flame temperature and flame speed of hydrogen are contributing factors to NOx formation. Higher flame temperatures favour NOx production. Combustion of H2 may lead to higher flame temperatures than natural gas due to the higher heat of combustion of H2. Current tests show that gas turbines running on 100% hydrogen will produce significantly more NOx than those running on natural gas.

The higher NOx emissions directly affect the sizing of the SCR system. Any SCR adaptations after installation will be challenging due to space constraints. Thus, in anticipation of future H2 burning, a larger spool duct needs to be considered in the design of any new build installations. Furthermore, many existing power plants have supplementary firing systems installed either in the inlet duct of the HRSG or between the high-pressure superheater modules. Increasing H2 ratios in the combustion fuel of such burners will also likely increase the NOx emissions and impact SCR performance.

Higher exhaust volume flow and increased exhaust gas inlet temperature

Firing hydrogen can potentially also add extra volume to the exhaust gas flow compared to firing natural gas, depending on the gas turbine conditions.

CH4 has an LHV of 49 895 kJ/kg = 798.3 kJ/mol and H2 has an LHV of 120 087 kJ/kg = 240.2 kJ/mol. Hydrogen has a higher energy density per unit mass but a much lower energy density per mol. Since the compressor of the GT will suck in the same volume flow of air, practically independent of the type of fuel that is fired, and the same amount of energy needs to be added, it means that 3.324 times the amount of CH4 (in mols) need to be added in the form of H2 in case of 100% H2 firing. Typically, for a modern GT, about 4% of the molar flow of air is added as CH4. This will then increase to 13.3% in case of 100% H2 firing. The molar mass of the flue gas drops from 28.3 g/mol (100% CH4 firing, 60% RH @ ISO) to 27.2 g/mol (100% H2 firing, 60% RH @ ISO). A curious phenomenon now occurs: switching from 100% CH4 firing to 100% H2 firing, the mass flow of flue gas decreases by 1.3% while the volume flow of flue gas increases by 2.5%.

For new HRSG units, design parameters such as the sizing of the duct and casing, heating surfaces, internal gas flow distribution within the HRSG and acoustic provisions need to be analysed when designing the unit for H2 firing.

Increased water content in the exhaust gas flow

A combined cycle power plant running on natural gas produces a gas turbine exhaust gas with a water dew point of around 47-50°C. Mixing hydrogen with the natural gas results in increased water content in the exhaust gas (and consequently increased water dew point). While the increase in water dew point is minimal with an H2 content below about 50%, it becomes significant moving towards 100% hydrogen firing.

When adapting an HRSG installation for H2 cofiring, the condensate recirculation system needs to take into account the higher minimum water temperature, which is a function of the water dew point. Adaptation of heating surfaces at the cold end might also be considered, although this is only possible to a limited extent (or not at all) for existing installations.

Effects on HRSG performance and gas side pressure drop

Converting an existing combined cycle power plant fired with natural gas to hydrogen firing, with additional constraints such as maintaining the same GT back pressure, design temperature and HRSG pressures, can be expected to result in a slight decrease in bottoming cycle performance. This can be attributed to the decrease in mass flow and change in specific heat of the flue gas. For a given heating surface, this implies a decrease in heat transfer and consequently less steam production. However, the reduction of steam production is small, of the order of 1-2%.

The increased exhaust water dew point could also have a negative impact on performance, as additional thermal energy  needs to be used to recirculate the condensate to a higher temperature.

For new installations, in case of a larger volume flow of flue gas, the gas side pressure drop in H2 fired plants will be slightly higher than for natural gas units, resulting in a slightly lower gas turbine output.

HRSG burner design for H2 firing

The conversion of an existing NG-fired supplementary HRSG burner system into an H2- ready system capable of accommodating various blends of NG and H2 presents several challenges. These include, but are not limited to: change in properties and supply pressure of H2; increased flame radiation of H2; higher combustion velocity of H2; and increase in NOx emissions.

Overall, the design adaptations required to transition from an NG-fired supplementary burner system to an H2-ready system must be carefully studied on a case-by-case basis to ensure optimal operation and performance of the system.

For new build power plants, it is, in principle, feasible to design a supplementary firing system capable of firing H2 and NG blends in any ratio ranging from 0%-100%. However the aforementioned challenges with respect to the combustion properties of H2 and NG need to be considered.

Hydrogen readiness certification

‘H2 readiness’ for a combined cycle power plant has already been clearly defined and a TU¨V SU¨D certification guideline is available.

The impact of H2 firing on a combined cycle plant is split into focus areas such as fuel gas supply, gas turbine, HRSG, explosion protection, etc.

The certification process is carried out for three phases of a power plant project: H2- Readiness Concept Certificate; H2-Readiness Project Certificate; and H2-Readiness Transition Certificate.

NEM Energy Group is already in receipt of the H2-Readiness Concept Certificate from TU¨V SU¨D, the first HRSG OEM globally to obtain such certification.

Components complementary to the HRSG, such as the exhaust gas bypass system, transition piece to inlet duct, burner system for supplementary firing, SCR and CO catalysts, are also included in the certification. The H2 readiness certification for a specific plant in the realisation phase will confirm that the plant (initially running on natural gas) has been built according to the H2 readiness concept of the bidding phase.

Navigating the hydrogen roadmap

All in all, the HRSG is impacted by firing hydrogen in the gas turbine and there are various challenges to be considered. However, as of today, HRSGs can be made hydrogen-ready in the design phase to minimise impacts when shifting to hydrogen at a later stage. NEM Energy offers heat recovery products behind GTs to support the hydrogen roadmap for both existing and new build applications.

Authors: Gayathri Hariharan, Pin-Hsuan Lee, Peter Rop, Sebastiaan Ruijgrok, Francesco Perrone, NEM Energy