1 Hydrogen as a Gas Turbine Fuel
TABLE OF CONTENTS
ABSTRACT 2
INTRODUCTION 3
HYDROGEN BASICS 4
Color Types 5
Comparison to Natural Gas 5
Supply & Infrastructure 7
CONSIDERATIONS FOR HYDROGEN IN GAS TURBINES 8
Enclosure Considerations 9
Combustion Considerations 10
Compressor Considerations 16
Hot Gas Path Considerations 16
CURRENT OEM EXPERIENCE 17
Ansaldo Energia 17
General Electric 20
Mitsubishi Hitachi Power Systems (MHPS) 23
Siemens 25
SUMMARY 27
REFERENCES 28
2 Hydrogen as a Gas Turbine Fuel
ABSTRACT
While natural gas is the cleanest large scale combustion fuel in use today, utilizing it as a fuel
for power generation purposes is responsible for approximately 15% of all CO2 emissions in the
US. Gas turbines are responsible for a large fraction of these emissions. Renewable energy
sources are continuing to make inroads into the global energy ecosystem, but gas turbines
remain a key piece of the ecosystem as their flexibility complements renewables and their
fluctuations in output well. Hydrogen, and its derivatives, are receiving much attention as a
possible fuel to displace natural gas and provide CO2 free combustion in gas turbines and
beyond.
Hydrogen is the most abundant element on earth but does not naturally occur on its own and is
therefore known as an energy carrier rather than an energy source. It needs to be extracted
from other compounds which poses production and scalability challenges. Additionally,
hydrogen’s physical properties differ greatly from those of methane or natural gas, creating
unique challenges to storage, transportation, and combustion.
There is much momentum for technology programs that are working to overcome these
challenges, including the use of hydrogen as a fuel in gas turbines. Hydrogen gas is being
considered as a fuel in turbines both blended with natural gas and on its own. According to
numerous industry publications, blends with low percentage hydrogen by volume (~20% or less)
can be used safely in many gas turbines today with minimal or no modifications. For blends with
larger percentages of hydrogen, turbine modification is necessary. These modifications largely
focus on the turbine combustion system with additional controls and plant level considerations.
Combustion system type and design drive a turbine’s hydrogen burning ability and emission
levels (NOx, CO2), which results in varying hydrogen capabilities across engines and OEMs.
Original equipment manufacturers (OEMs) including Ansaldo Energia, General Electric,
Mitsubishi Hitachi Power Systems, Siemens, and others have multiple offerings with hydrogen
burning capabilities. Offerings using diffusion type combustors can burn larger percent
hydrogen by volume blends but require significant dilution to manage NOx at the expense of
plant efficiency and output. The OEMs recognize that lean premixed combustors (dry low
emissions combustors) will continue to be the combustors of the future due to their ability to
manage emissions and maintain high efficiency levels. They have dedicated considerable
resources to designing hydrogen enabled combustors, many of which are currently being tested
in lab environments and are just starting to be put to work in fielded engine demonstrations.
3 Hydrogen as a Gas Turbine Fuel
INTRODUCTION
Burning natural gas in turbines is the cleanest large-scale fossil-based energy production
source on the planet today. According to the US Energy Information Administration (EIA),
natural gas produces approximately half of the carbon dioxide (CO2) emissions as compared to
coal at 116 pounds per million Btu versus 211 pounds per million Btu (U.S. Energy Information
Administration). In 2021, natural gas accounted for 32% of all US power generation and 40% of
the power generation CO2 emissions (U.S. Energy Information Administration). This equates to
just under 15% of all the CO2 emissions in the US.
Figure 1: Power Sector Fuel and Emission Sources (U.S. Energy Information Administration)
As the demand for green energy has continued to grow and carbon reduction efforts have
gained momentum, gas turbines remain a major part of both the US and international power
grids. A major driver for this is a gas turbines’ ability to quickly respond to intermittent and
fluctuating energy production levels from renewable sources, such as wind and solar, and to
stabilize the energy grid. Assuming the continued build-out of variable intermittent renewable
resources on the electricity grid, it is a good assumption that moving forward gas turbines will
continue to be prevalent. Addressing their CO2 emissions will be an important step towards
achieving a carbon-free energy network.
4 Hydrogen as a Gas Turbine Fuel
CO2 reduction in gas turbines can be addressed through both a front-end approach, using
carbon free fuels, and a back-end approach, with carbon capture. While carbon capture will
have its role in the carbon-free effort, this paper will focus on fuels with carbon free byproducts,
specifically hydrogen. The main byproduct of combusting hydrogen is H2O, or water, making it a
truly CO2 emission free fuel. Over the past couple years, hydrogen has received a lot of
attention and funding from US based and international organizations, including national
governments, to tackle production and infrastructure challenges. Additionally, large gas turbine
OEM such as GE, Siemens, Mitsubishi Hitachi Power Systems (MHPS), and others are actively
working to build out hydrogen fuel capability and are betting on hydrogen being a major piece of
their businesses moving forward.
HYDROGEN BASICS
Hydrogen does not naturally exist on its own and must be produced from compounds that
contain it. Therefore, it is known as an energy carrier rather than an energy source (Office of
Energy Efficiency & Renewable Energy). Hydrogen is produced by extracting it from fossil fuels,
biomass, or water. There are numerous different hydrogen production technologies used today
in varying technology readiness levels. Three of the most well-known technologies are steam
methane reforming, coal gasification, and electrolysis. Steam methane reforming and coal
gasification are thermochemical processes, while electrolysis is an electrolytic process. The
chemical reactions associated with steam methane reforming and electrolysis are good
illustrations of the differences between a thermochemical and an electrolytic process.
The steam methane reforming process utilizes methane or natural gas and combines it with
steam and a catalyst to create a reaction that separates hydrogen from the methane.
Byproducts from steam methane reforming (SMR) are carbon monoxide and smaller amounts of
carbon dioxide.
Figure 2: Basic Steam Methane Reforming Equation
A follow up water-gas shift reaction takes place to convert the CO to CO2 and complete the
reforming process. This reaction generates one extra hydrogen molecule.
Figure 3: Water Gas Shift Reaction Used with SMR Reaction
Electrolysis utilizes electricity in an electrolyzer to split water into hydrogen and oxygen. Since
the process requires electricity its contributions to carbon emissions are dependent on the origin
of the utilized electricity.
Figure 4: Basic Electrolysis Equation
5 Hydrogen as a Gas Turbine Fuel
Color Types
Hydrogen is referred to throughout the industry by different color types which indicate with what
or how it was produced. The most common color types are listed below, but the list is not
exhaustive as different colors are frequently being assigned.
• Grey: Hydrogen reformed from natural gas that does not utilize carbon capture.
• Black/Brown: Hydrogen created through gasification of coal.
• Blue: Typically, grey hydrogen that uses carbon capture and storage (CCS) or carbon
capture and utilization (CCU).
• Green: Hydrogen produced through electrolysis using renewable energy.
• Pink: Electrolysis using nuclear power.
• Turquoise: Hydrogen from low emission methane pyrolysis (splitting of methane into
hydrogen and solid carbon).
• White: Biomass gasification or similar process.
• Yellow: Hydrogen produced using the photolytic process (light energy used to split
water). Also, has been used for grid-based electrolysis.
Comparison to Natural Gas
The long-term goal is to be able to burn 100% green hydrogen in gas turbines, replacing natural
gas and driving CO2 emissions to near zero. In the shorter term, hydrogen can be blended with
natural gas and burned in gas turbines for a fractional reduction of CO2 emissions. The figure
below shows the percentage emissions reduction versus the percentage of hydrogen blending.
Note that the relationship between hydrogen percent by volume and CO2 reduction is not linear
due to methane’s volumetric energy density is close to 3x that of hydrogen. Near a 75% blend
of hydrogen is required to reduce CO2 emissions by 50%.
Figure 5: CO2 Emissions vs. Volume Percentage of Hydrogen Blended with Natural Gas (General Electric GasPower)
6 Hydrogen as a Gas Turbine Fuel
A 100% hydrogen blend requires 208% of additional volumetric flow, or roughly three times the
volumetric flow, as compared to methane.
Figure 6: Additional Required Volumetric Flow vs. Methane
With the knowledge that hydrogen is intended to be used in conjunction with natural gas or as a
full replacement, it is important to understand how the two fuels differ. It is their differences that
makes immediate plug and play use of hydrogen in gas turbines difficult. The table below
summarizes many of the physical differences between hydrogen and natural gas.
Table 1: Comparison of Natural Gas and Hydrogen
Natural Gas Hydrogen
Composition
90% CH4 (methane), C2H6
(ethane), C3H8 (propane),
C4H10 (butane), CO2, O2, N2
(nitrogen), H2S (hydrogen
sulfide)
H2
Main Byproduct(s) CO2, NOx (Nitrogen Oxide) H2O, NOx (nitrogen oxide)
Vapor Density at STP
(lbm/ft3
) 0.05 0.0056
Kinetic Diameter (pm) 380 289
Lower Heating Value
(Btu/ft3
) 983 290
Flammability Limit (%
LL/UL) 7/20 4/75
Autoignition Temperature
(°F) 1003 1085
Adiabatic Flame
Temperature (°F, 1 atm
pressure)
3565 4009
0% 3% 7% 11% 16% 20% 25% 31% 37% 44% 51% 59% 68% 78% 90%103%117%135%155%
179%
208%
0%
50%
100%
150%
200%
250%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
40.0%
45.0%
50.0%
55.0%
60.0%
65.0%
70.0%
75.0%
80.0%
85.0%
90.0%
95.0%
100.0%
% Hydrogen in Blend
Additional Delivery Volume Percentage Relative to
Methane
7 Hydrogen as a Gas Turbine Fuel
Flame Speed (ft/s) 1.0-1.3 6.6-9.8
Main Production
Method(s) Drilling (natural gas wells)
Steam Methane Reforming
(SMR), Gasification,
Electrolysis
Compressed Liquid Temp
(°F) -163 -423
Cost (2022, $/MMBtu) 9.00 15.00-52.50
References: (Engineering ToolBox), (Wikipedia), (U.S. Energy Information Administration), (Escola Europea)
Supply & Infrastructure
As touched upon previously, there are numerous ways to produce hydrogen, many of which do
so with no or low emissions. However, these low emission methods have not yet been scaled.
As of 2021, 98% of the worlds hydrogen was produced using fossil fuels with no emissions
control, with methane being the overwhelming source at 76%, followed by coal at 22%
(Columbia Center of Global Energy Policy). The total hydrogen demand in 2020 was 90
megatons and is expected to nearly triple in the next thirty years (International Energy Agency).
The International Energy Agency predicts that to support net zero emissions by 2050, the
hydrogen production would have to grow to an excess of 500 megatons, of which approximately
one-fifth would be consumed by the power industry (International Energy Agency). To meet this
demand, production will have to scale significantly.
In addition to scaling production, infrastructure for transportation of hydrogen will have to be
built out. Hydrogen can be transported in three different forms: gas, liquid, or in a carrier such
as ammonia or a liquid organic hydrogen carrier (LOHC). To transport hydrogen in gas form, a
dedicated pipeline would have to be established. This would require building of a new pipeline
or retrofitting existing natural gas pipelines. Modern pipelines today made from polyethylene or
fiber-reinforced polymers are generally considered compatible for low level blends of hydrogen.
However, pipeline valve, seal, and compressor upgrades are likely required to deal with the
smaller hydrogen molecules that have a propensity to leak, and to provide more compression
capability required for the lower density and energy content of hydrogen. Numerous research
programs and consortia are actively investigating the maximum percentage of hydrogen
(blended with natural gas) that existing infrastructure can transport with minimal modifications.
Like natural gas, hydrogen can be cooled and transported in liquid form. It does require
specifically designed transport vehicles (trucks, ships) and supporting equipment. For example,
storage insulation requirements are greater for hydrogen since the liquid hydrogen temperature
is about 250°F cooler than that of liquid natural gas.
Attaching hydrogen with a carrier such as ammonia or a LOHC can allow the hydrogen to be
transported with a greater density per volume than on its own. However, this does require a
chemical conversion to separate out the hydrogen once the usage point is reached. In the case
of the LOHC, either a bidirectional pipeline or a second pipeline to return the dehydrogenated
organic carrier is required. The graphic below is a good illustration of the main production,
transportation, and consumption methods of hydrogen in use today. In the near term, a good
option to avoiding transportation challenges and costs is to collocate production and
consumption facilities, such as power plants.
8 Hydrogen as a Gas Turbine Fuel
Figure 7: Production, Transportation, and Consumption of Hydrogen (Siemens Energy)
CONSIDERATIONS FOR HYDROGEN IN
GAS TURBINES
It is important to recognize that all gas turbines are not created equal. There can be large
differences between industrial gas turbines (IGT) and smaller aeroderivative engines, as well as
across equipment manufacturers. The point is that every gas turbine design needs to be
evaluated on an individual basis to determine its hydrogen burning ability and what level of
retrofit or design change is required to improve this ability.
Required design changes can be highly dependent on the percent volume of hydrogen desired
to be burned. Reviewing literature published by the gas turbine OEMs, hydrogen burning can be
segmented into low, medium, and high percentage blend groups. A turbine operating on a low
percentage blend of hydrogen (5-10%) may not require any design or material changes as the
fuel burn characteristics are generally similar to a 100% natural gas fuel stream. For medium
percentage blends (10-50%), design changes to existing equipment are necessary. For
example, modifications will be made to combustor materials, fuel nozzles, and control systems.
However, the scope of the changes will be on a medium level and the combustor and overall
turbine architecture will be mostly unchanged. For higher blends of hydrogen, more than 50%,
more major modifications must be made to the turbines. Complete retrofit of the combustion
system is likely required. Many of the OEMs are currently working on new combustion systems
to be able to handle high hydrogen blend levels.
9 Hydrogen as a Gas Turbine Fuel
Again, it should be stressed that the percent ranges used above, as well as the rough
modification scope for the applicable high, medium, and low blend ranges, are very much
dependent on the turbine design. The following sections will discuss turbine considerations to
help provide an understanding of why this is so. These sections will look at the gas turbine from
the enclosure on in and discuss challenges, potential design changes, and impacts of burning
hydrogen.
Enclosure Considerations
The gas turbine enclosure is the packaging or housing that encloses the gas turbine for safety
purposes and operating environment control. It contains piping for fuels and diluents, safety
systems for gas detection and fire protection, and a ventilation system. Additionally, enclosures
are typically explosion proof.
Fuel system piping and valves in the enclosure that are intended to flow hydrogen must be
made compatible with it. Hydrogens’ small molecules are able to permeate materials and cause
embrittlement, as well as escape through seals, where almost all other gases cannot due to
larger molecule size. These concerns are the same for transportation piping and the fuel system
outside of the enclosure. This means materials need to be selected to function in a hydrogen
environment and engineering safety factors must be included into the design. Moreover,
hydrogen-tight seals need to be capable of containing the small hydrogen gas molecules. Piping
and valves may have to be enlarged to handle the higher volumetric flow that hydrogen requires
depending on the intended blending percentage to be used (see Figure 5).
Safety systems for gas detection and fire protection will have to be modified too. Gas detection
specifically for hydrogen will have to be installed. Fire protection systems will also have to be
made capable of suppressing fires started with the more volatile hydrogen fuel. Similarly,
explosion proofing will have to be made capable of containing larger explosions. Along with
these systems, ventilation will have to be considered. Ventilation is setup to help keep
enclosure internal temperature cool and to keep the enclosure free of any gas that may be
leaking into the air. There is a balance, to ensure the enclosure is properly vented, but also not
over vented. Over venting of the enclosure can lead to cold casing temperatures that may
cause the casing to pinch the rotor, resulting in hard rubbing.
10 Hydrogen as a Gas Turbine Fuel
Combustion Considerations
A turbine’s ability to burn hydrogen is almost solely dependent on the combustion system. The
larger the hydrogen percentage in the fuel, the more challenged an unmodified combustion
system becomes. To add to the difficulties, for the foreseeable future, combustion systems will
have to maintain fuel flexibility and the ability to burn natural gas. The combustion system is
challenged by the following factors:
• Hydrogen is 1/9th the density of natural gas and is the smallest known molecule, which
creates transportation and sealing challenges. Fuel tight sealing joints that prevent
natural gas from leaking, for example, may not be suitable for hydrogen. Smaller
molecules also allow for hydrogen to permeate certain materials and cause
embrittlement.
• Hydrogen’s heating value is 1/3rd of natural gas’, which means that three times as much
hydrogen fuel flow is needed to produce the same amount of power as compared to
natural gas.
• The flammability range of hydrogen is much larger than that of natural gas creating
elevated environmental, health, and safety concerns for both transporting and burning
hydrogen. This is less of a concern for low percentage hydrogen blends and a greater
concern for pure hydrogen. The plot below shows how the upper explosive or
flammability limit changes with increasing hydrogen volume in hydrogen-methane
blends.
Figure 8: Upper Explosive/Flammability Limit of Hydrogen-Methane Blends (Blacharski, Janusz and
Kaliski)
• Hydrogen burns hotter and has a faster flame speed than natural gas. This creates
combustion stability difficulties and increases potential for flame out and flashback.
• Hydrogen flames are much less visible than natural gas flames, making flame detection
difficult.
11 Hydrogen as a Gas Turbine Fuel
Hydrogen embrittlement occurs as soon as hydrogen is introduced into a system and cannot be
undone. As previously stated, the small hydrogen molecules can diffuse into metals and cause
embrittlement. Embrittlement lowers the material’s yield stress which reduces the material’s
fatigue capability, particularly for low cycle fatigue. Temperature, pressure, and stress level can
influence the rate or magnitude of embrittlement. However, not all materials are equally prone to
hydrogen embrittlement. Both stainless steels and nickel alloys, commonly used in gas turbine
combustion systems, experience increased levels of embrittlement at elevated temperatures.
This makes combustion material selections for hardware, weld joints, and braze joints difficult.
There are several main combustion system types used throughout IGTs and the challenges
described above will impact the systems differently. The two main combustion system types
used in today’s industrial gas turbines are Diffusions Systems and Lean Premixed Systems
(DLE Combustor).
DIFFUSION COMBUSTION SYSTEMS
In diffusion flame, or conventional, combustion systems fuel is directly injected into the reaction
zone with no intentional premixing with the combustion air. A diffusion, or non-premixed, flame
burns at the flame surface while fuel on the interior of the flame remains unburned. Diffusion
flames generate higher gas temperatures as compared to premixed because the fuel burns
close to the stoichiometric ratio (Greenwood). The stoichiometric ratio is the ratio between gas
and air where complete combustion occurs. High gas temperature results in lower CO levels,
but higher NOx levels, as illustrated in Figure 9.
Figure 9: Relationship Between NOx and CO (Power Engineering International)
12 Hydrogen as a Gas Turbine Fuel
The figure below shows an example of an annular diffusion combustor. In the primary zone, fuel
is injected and burned. Fuel and air mixing is less than ideal and incomplete combustion of the
fuel occurs. A secondary zone, where additional air is added to the combustor, is required to
complete full combustion of the fuel. The gas temperatures aft of the primary and secondary
zones are too high for downstream turbine component health, thus a dilution zone is used to
inject additional air and to drop the gas temperature to an acceptable level.
Figure 10: Example of a Standard Combustor (Greenwood)
Injecting a diluent such as steam, water, or nitrogen into the primary combustion zone can also
be used to decrease flame temperature and NOx levels.
Figure 11: Representative Diffusion Combustor Using Diluents (Asai, Akiyama and Dodo)
13 Hydrogen as a Gas Turbine Fuel
Diffusion combustors offer greater flame stability over a wider range of flame temperatures and
fuel compositions, including hydrogen, as compared to lean premixed systems. Because the
flame burns close to the stoichiometric ratio it is less prone to lean blow out during operation,
and due to higher gas velocities, it is less likely to flashback. With more flame stability,
combustion dynamics remain within acceptable limits. Some diffusion combustors can burn
100% hydrogen today, but elevated NOx emissions are expected and will require more dilution
at the fuel injection zone. It should be noted that diluent systems add complexity to plants,
requiring water or steam injection systems, and can alter the mass flow rates between the
compressor and turbine sections, potentially reducing surge margin. Alternatives to increased
dilution would be output reduction, which is typically not favorable, or application of a post
emissions control system such as selective catalytic reduction (SCR), which also increases
plant complexity.
Figure 12: Example of a Can-Annular GE 7E Standard Combustor (GE Energy)
LEAN PREMIXED COMBUSTORS (DLE AND DLN COMBUSTORS)
Due to the NOx challenges in diffusion combustors, many of today’s new gas turbine designs
are equipped with lean premixed combustors also known as dry low emissions (DLE) and dry
low NOx (DLN) combustors. The word “dry” indicates that no diluents are being used for
emissions control. While diffusion combustors are currently more capable of burning hydrogen,
the gas turbine industry recognizes that lean premixed combustors, with superior emissions
control, will continue to be the dominant combustion system for new designs, even with
hydrogen.
The main difference between the lean premix and diffusion combustors is that the fuel and air is
mixed prior to injection into the combustion chamber in a lean premix system. The
homogeneous mixture of air and fuel allows for a uniform and lower temperature flame,
reducing NOx emissions without the use of dilution and the associated efficiency penalty. Most
lean premixed combustors also use fuel staging with lean fuel-air ratios to help further control
emissions. Lean premixed systems can look vastly different between OEMs and even turbine
14 Hydrogen as a Gas Turbine Fuel
designs. DLE technology has been continuously evolving as there has been a constant push for
higher efficiencies and lower emissions. The wide variety of designs translates to a large range
of hydrogen burning capabilities across turbines. But today, in almost all cases, lean premixed
combustors can handle lower volume percentages of hydrogen when compared to diffusion
combustors.
Figure 13 offers a simple comparison between a diffusion (top) and a lean premixed (bottom)
combustor. The lean premixed cross section shows an inner and outer fuel circuit. The outer
fuel circuit uses over 85% of the gas fuel and swirls it with air before injecting it out into the
combustor. A smaller center fuel circuit is used for non-mixed pilot fuel that burns rich. In most
cases, the center pilot fuel nozzle is shutoff at steady state natural gas operation. The mixed air
allows for a lower flame temperature, but the lower temperature flame is much closer to the lean
limit and isn’t as stable when compared to a diffusion flame. Additionally, the center pilot nozzle
surrounded by air and fuel on its perimeter creates a dead zone, or slow-moving air zone, in the
center of the nozzle. This region is prone to flame instability and poses an increased risk to
flashback. Note that this a general example and is not inclusive of all DLE designs and
technologies.
Figure 13: Simple Comparison Between Diffusion and Lean Premixed Combustion Systems
15 Hydrogen as a Gas Turbine Fuel
When considering hydrogen in DLE and DLN systems, similar challenges that exist for diffusion
combustors are magnified. First, hydrogen’s higher flame speed as compared to natural gas
(>3x) and the slower moving flame center in the above DLE system increases the flashback
risk. Figure 14 shows an illustrated example of flashback.
Figure 14: Illustration and Description of Flashback (Inoue, Miyamoto and Domen)
Next, the higher flammability range of hydrogen increases the risk of fuel ignition inside the
mixing passages. Combustion dynamics are also altered with hydrogen usage. Elevated
dynamics amplitudes over a larger range are expected for hydrogen since flame stability is
reduced. During transient operation, like startup and shutdown, dynamics are of greatest
concern and for the foreseeable future a “safe fuel”, such as natural gas, will be required for
non-steady operation (startup, shutdown, part-load). In summary, the stable operability window
for most lean premixed combustors is narrower as compared to diffusion combustors, which
translates to premixed combustors only being capable of lower percent blends of hydrogen.
There are ongoing efforts from the gas turbine OEMs to overcome the challenges associated
with hydrogen and lean premixed combustors. Lean premixed combustors are critical to
enabling hydrogen burning in gas turbines with acceptable emissions levels.
16 Hydrogen as a Gas Turbine Fuel
Compressor Considerations
Since all the combustion takes place downstream of the compressor, the combustion of
hydrogen does not have direct impact on the compressor. There are a few indirect impacts that
are notable and pertain to NOx abatement. Two possible ways to minimize NOx emissions are
through unit derate or dilution (standard combustor). If unit derate is chosen to reduce NOx, the
off-design point selected needs to be acceptable for the compressor performance and health. If
additional dilution in standard combustors is chosen to abate NOx, surge margin may be
adversely impacted by the change in mass flow of the turbine section relative to the compressor
section.
Hot Gas Path Considerations
Hydrogen’s higher burning temperature driving up turbine firing temperature is the largest
concern to the hot gas path components. It should also be expected that the gas temperature
profile leaving the combustor will be hotter and look different when firing hydrogen versus
natural gas. For example, the gas temperature profile exiting a diffusion combustor will likely
look more peaky (highest temperature in center of combustor) when burning hydrogen if no
additional changes are made. Firing temperature increase and combustion profile shape
change will drive modifications to the component cooling and coating designs to avoid part life
reduction.
Figure 15: Example of Possible Gas Temperature Profiles of Hydrogen vs. Natural Gas
Additionally, there has been some noted concern about additional moisture content in
combustion gas (water is a byproduct of burning hydrogen) causing higher heat transfer to hot
gas path components (Mulder). Based on the expectation that combustion gas temperatures will
be high, any moisture content will be in the vapor phase. Water and steam, including
superheated or vaporous, both have a higher specific heat (cp) than air. This will translate to
more heat being transferred to the turbine components. Work will be required to determine the
impact, if any, on the downstream turbine components.
17 Hydrogen as a Gas Turbine Fuel
CURRENT OEM EXPERIENCE
There are numerous companies that produce a range of industrial, aeroderivative, and even
aviation gas turbines that are exploring hydrogen usage in varying capacities. This section
focuses on the hydrogen experience and ongoing developments of the main original equipment
manufacturers in the industrial and large aeroderivative gas turbine spaces. It is a thorough
review but is not intended to be inclusive of all companies and all hydrogen work being
completed in the industrial turbine space today.
Ansaldo Energia
The Italian based turbine manufacturer offers E, F, and H class gas turbines capable of 80MW
and greater. Ansaldo claims more than 15 years of hydrogen burning experience and
capabilities ranging from 25-80% hydrogen blends depending on turbine model (Ansaldo
Energia). They target 100% hydrogen burning capability across all frames by 2030.
Table 2: Ansaldo Energia’s Main Gas Turbine Offerings
Of the above offerings, Ansaldo claims all can burn hydrogen in some capacity, except for the
AE64, with no required hardware modification.
18 Hydrogen as a Gas Turbine Fuel
Table 3: Ansaldo Energia Hydrogen Capability by Engine
The AE94 engines uses Ansaldo’s tried and true single stage combustors. The AE94.2 uses silo
style combustors with DLN burners and the AE94.3 uses an annular combustor again with DLN
burners. In 2006 two AE94.3A were commissioned to burn 15% hydrogen by volume, which has
since been increased to 25%. Combined, these two engines have over 200,000 EOH.
Figure 16: Ansaldo Energia AE94.2 and AE94.3A Engines
Ansaldo’s GT26 and GT36 engines take advantage of Ansaldo’s latest and greatest combustion
model, the sequential combustor. These engines are advertised as capable of burning up to
50% hydrogen by volume.
19 Hydrogen as a Gas Turbine Fuel
Figure 17: Ansaldo Energia GT26 and GT36 Engines
What makes this possible is Ansaldo’s sequential combustor that utilizes two combustion
stages. By splitting fuel between the first and second combustion stages, the conventional first
stage can maintain flame location at a lower temperature. The lower temperature gas travels to
the second stage which uses auto-ignition to maintain flame stability even at a higher fuel flow.
These combustors with hydrogen use have been validated in lab conditions (not full engine).
Ansaldo is working to further validate these combustors and to increase the hydrogen burning
capability up to 70% by volume.
Figure 18: Ansaldo Energia Sequential Combustor
It should be noted that Ansaldo through PSM also offers combustion system upgrades, such as
the FlameSheet combustor which is retrofittable to GE, MHI, and Siemens E and F class
engines. The combustor can currently burn up to 60% hydrogen and has demonstrated up to
80% in a lab setting (Power Systems Mfg, LLC).
20 Hydrogen as a Gas Turbine Fuel
General Electric
General Electric claims to be the leader in gas turbine fuel flexibility and hydrogen with more
than 100 turbines that operate fuels with some level of hydrogen, which have accumulated 8
million operating hours, and more than 30 turbines that have operated with fuels of at least 50%
hydrogen (General Electric Gas-Power). Most of GE’s experience with hydrogen has occurred
at industrial facilities or at IGCC plants (integrated coal gasification combined cycle) where the
hydrogen or fuel source is collocated with the power plant.
Figure 19: GE Experience with Hydrogen Gas Turbines (General Electric Gas-Power)
GE summarizes their hydrogen burning capability by engine frame in a bar chart that
differentiates between capability with lean premixed combustors and diffusion combustors. This
highlights the significant differences in these technologies and the required progress that lean
premixed combustors must make to enable high hydrogen blend fuels.
21 Hydrogen as a Gas Turbine Fuel
Figure 20: GE Gas Turbine Hydrogen Capability by Frame (General Electric Gas-Power)
GE is committed to continued development of hydrogen combustors and gas turbines. GE
industrial gas turbines, except for some of the legacy Alstom offerings, have historically had
can-annular combustion systems. These can-annular systems have evolved from a single
nozzle diffusion combustor to a multi-nozzle quiet combustor, and then to a DLN combustor
design. GE was the original leader in DLN and DLE technologies. Their latest HA turbines are
equipped with DLN 2.6e combustion systems that can burn up to 50% hydrogen by volume
when paired with an HA engine (Goldmeer). The DLN 2.6e, instead of using the typical 5-6 fuel
nozzles with swirlers, uses hundreds of smaller nozzles to help promote even mixing of air and
gas without the air dead or slow zones that were described in the combustion section of this
paper.
Figure 21: GE’s Combustor Evolution (Goldmeer)
22 Hydrogen as a Gas Turbine Fuel
GE has a handful of commercial hydrogen demonstration projects underway or in the works.
Their latest 7HA and 9HA engines are being equipped with the DLN2.6e combustors. Most
recently, the Long Ridge Energy Plant (Ohio) in early 2022 completed execution of a
demonstration that burned a 5% hydrogen blend with natural gas in GE’s 60 Hz 7HA.02.
Figure 22: GE’s Planned Commercial Hydrogen Demonstrations (GE Power)
23 Hydrogen as a Gas Turbine Fuel
Mitsubishi Hitachi Power Systems (MHPS)
MHPS is actively pursuing increasing their hydrogen burning capability. Like other OEMs, they
do have experience burning hydrogen-rich fuels such as syngas and off gas.
Figure 23: MHPS Experience with Hydrogen Rich Fuels (Inoue, Miyamoto and Domen)
MHPS has three combustor technologies with varying hydrogen capabilities: diffusion
combustor, DLE multi-nozzle combustor, DLE multi-cluster combustor.
Figure 24: Comparison of MHPS Hydrogen Enabled Combustors (Nose, Kawakami and Araki)
24 Hydrogen as a Gas Turbine Fuel
MHPS has made strides with both of their DLE combustor types to enable hydrogen burning.
Their typical DLE design uses 8 premixing nozzles where only gas is injected at the center of
the nozzle and air and gas are injected and mixed on the perimeter of the nozzle. This fuel
nozzle configuration with an absence of air at the nozzle center, creates a low velocity air zone
at the center. The low velocity zone can lead to flashback when using hydrogen due to the
higher hydrogen flame speed as compared to natural gas. To overcome this concern, MHPS
has added air injection to the nozzle center.
Figure 25: MHPS Latest DLE Fuel Nozzle Design (Nose, Kawakami and Araki)
The DLE multi-cluster combustor is MHPS’ latest technology and believed enabler for achieving
burning of 100% hydrogen by volume. Like GE’s DLN2.6e, the combustor uses many smaller
fuel nozzles to disperse the fuel and combustion flame creating more stable combustion that
minimizes the risk of flashback. The combustor is currently under continued development.
Figure 26: MHPS Multi-Cluster Nozzle (Nose, Kawakami and Araki)
25 Hydrogen as a Gas Turbine Fuel
The below figure shows the latest hydrogen gas turbine development status per MHPS.
Figure 27: MHPS Hydrogen Development Status by Gas Turbine (Mitsubishi Heavy Industries)
Siemens
Siemens claims extensive experience with high hydrogen content fuels in greater than 55 units
with over 2.5 million cumulative engine operating hours since the 1960s (Siemens Gas and
Power). This experience spans across multiple industries, geographies, and engine frames with
varying output levels. The vast majority of this experience is with high hydrogen content
synfuels.
Figure 28: Siemens Energy Hydrogen Experience by Turbine and Location (Siemens Gas and Power)
26 Hydrogen as a Gas Turbine Fuel
Siemens has three primary combustion system types: DLE, wet low emissions (WLE), and
diffusion. These systems are both annular and can-annular depending on the turbine model.
Figure 29: Siemens Gas Turbine Hydrogen Capability by Model (Siemens Energy)
Figure 30: Siemens Combustor Design Examples (Siemens Gas and Power)
Siemens has several DLE technologies with which they are equipping their latest turbines. They
are:
• HR3 burners for annular combustors in SGT5/6-2000E and SGT5/6-4000F
• Ultra-low NOx Platform Combustion System (ULN/PCS) in the SGT6-5000F and
SGT5/6-8000H
• Advanced Combustion for Efficiency System (ACE) in SGT5/6-9000HL
Each of these systems has the capability of burning 30-50% hydrogen by volume with a target
of 100% by 2030.
27 Hydrogen as a Gas Turbine Fuel
SUMMARY
Gas turbines will continue to be an important part of the World’s energy network as they
complement renewable energy sources well and have a large existing installed base. Through
use of pure hydrogen fuel, there is opportunity to drastically reduce CO2 emissions generated
as a byproduct of burning traditional fuels. There are many technologies that exist and that are
under development that will help make hydrogen prevalent in the future energy economy. Many
of these technologies are very promising, but the major challenge will be scaling them and
making hydrogen generation, distribution, and usage economically viable and truly green.
Many of the World’s largest energy companies and gas turbine OEMs are betting that these
challenges can be overcome. Gas turbine OEMs are committing significant resources to
designing hydrogen burning technology into their new engines and to creating modification
packages for existing engines. The focus of these design efforts is mainly on the turbine
combustion systems, while the remainder of the engine and overall engine architecture remains
mostly unchanged. Through continued aggressive goal setting and funding, it is expected that
hydrogen usage in gas turbines will fully be enabled in existing and new assets within the next
one to two decades.
28 Hydrogen as a Gas Turbine Fuel
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