Mitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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Hydrogen/Ammonia-fired Gas Turbine Initiatives
for Carbon Neutrality

TAKU EGAWA*1

HIROAKI NAGAHASHI*1

AKINORI HAYASHI*2

SHINICHI FUKUBA*3

KENJI SATO*4

SOSUKE NAKAMURA*5

Toward the goal of achieving carbon neutrality by 2050, Mitsubishi Heavy Industries, Ltd.
(MHI) is expanding its line-up of carbon-free power generation systems. With regard to gas
turbines using hydrogen, the development of a gas turbine combustor that can operate on a blendof 30 vol% hydrogen and natural gas has been completed. Combustion tests have been conducted
on a combustor with hydrogen dry single-firing and the development is in progress towardpractical application. Furthermore, for gas turbines using ammonia, the combustion system iscurrently in development to enable 100% ammonia to be fired in small-to-middle gas turbines.
These power generation systems will be verified one by one through actual-unit demonstration
testing by 2025 with the aim of realizing their early commercialization.

|1. Introduction
Achieving net-zero emissions of carbon dioxide (CO2) around 2050 is becoming the world’scommon goal. Countries do not remain in the stage of setting ambitious targets. They have now
entered the stage of executing action plans to fulfil their targets. In Japan, the energy sector is
attributable to more than 80% of the greenhouse gas emissions. While electricity is mainly
converted from primary energy, the Sixth Strategic Energy Plan has set the energy sector to work
toward the goal of hydrogen and ammonia serving as a power source accounting for 1% of theelectricity generated in 2030(1).
MHI has declared “MISSION NET ZERO” and is promoting thereunder decarbonizationfrom the perspectives of both energy transition and the smartification of social infrastructure toachieve carbon neutrality. As shown in Figure 1, decarbonization through energy transition focuses
on “reducing,” “capturing” and “eliminating” CO2 emissions from thermal power plants.
Specifically, it includes (1) CO2 reduction by replacing the coal-fired systems with the low-carbon
and high-efficiency gas-fired systems (GTCC : Gas Turbine Combined Cycles) and promoting theapplication of hydrogen co-firing in gas turbines and ammonia or biomass co-firing in coal-fired
systems, (2) promotion of utilizing Carbon dioxide Capture, Utilization and Storage (CCUS) by
optimizing the entire power plant that is equipped with GTCC and CO2 capture equipment, and (3)promotion of adapting gas turbines to use new fuels with a view to hydrogen (H2) or ammonia(NH3) single-firing, neither of which emits CO2. The development under the sponsorship of New
Energy and Industrial Technology Development Organization (NEDO) is moving forward
regarding the hydrogen co-fired combustor for large gas turbines in which 30 vol% hydrogen isblended with natural gas, and the combustor with hydrogen dry single-firing. The development of a
GTCC system using ammonia has also started. As shown in Table 1, the line-up of carbon-free gas
turbine systems is expanding. MHI aims to achieve decarbonization through energy transition withthese power generation systems by 2030.
*1

Gas Turbine Engineering Department, GTCC Business Division, Energy Systems, Mitsubishi Heavy Industries, Ltd.

*2

Chief Staff Engineer, Gas Turbine Engineering Department, GTCC Business Division, Energy Systems, Mitsubishi Heavy*3

Combustion Research Department, Research & Innovation Center, Mitsubishi Heavy Industries, Ltd.

*4

Manager, Gas Turbine Engineering Department, GTCC Business Division, Energy Systems, Mitsubishi Heavy Industries,*5

Deputy Senior Director, Gas Turbine Engineering Department, GTCC Business Division, Energy Systems, Mitsubishi Heavy

Industries, Ltd.

Ltd.
Industries, Ltd.

Mitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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Figure 1

MHI’s Initiatives for decarbonization of thermal power generation infrastructure
Table 1 MHI product line-up of carbon-free gas turbine systems

Equipment

Summary
Availability
A blend of 30 vol% hydrogen and natural gas is fed into a natural
Development completed30%
gas-fired, low-NOx combustor. Applicable without any changes inin 2018
co-firing
existing gas turbines or with minimum retrofitting.
HydrogenDevelopment to be
gas turbine
completed in:
A multi-cluster combustor for hydrogen single-firing is inSingle-firing
2025 for large frame GT
development.
2023 for small frame GT
Waste heat from a gas turbine is used to decompose ammonia into
H2 and N2. The former is then used as a fuel for the gas turbine.
It is possible to co-fire natural gas and the product gases fromIn development
Ammonia cracking GTCC
ammonia decomposition (H2 and N2), or fire only these productgases. Suitable for the application to large units withhigh-temperature waste heat.
The system remains simple, because no cracking equipment is
Development to beneeded.
Ammonia direct-fired
Ammonia combustion involves generating NOx in large quantities, completed in 2024 before
GTCC
aiming for verification
requiring a dedicated combustor to be developed. NOx removal
equipment for exhaust gas is also essential.

Hydrogen is considered the most effective carbon-free fuel in replacing or supplementing
fossil fuels. This is because hydrogen has a high potential for converting existing fossil fuelequipment and systems into carbon-free alternatives while keeping them operating. In the value
chain including hydrogen production, transportation, storage and utilization, large-capacity andhigh-efficiency hydrogen-fired gas turbines give the following advantages for those who aspire toachieve carbon neutrality: (1) low-carbonization or decarbonization of existing gas turbine facilities
is possible with minimum retrofitting and the lowest investment costs, (2) hydrogen is expected to
become cheaper as a result of growing hydrogen demand on a large scale, because a single power
generation facility with a large hydrogen-fired gas turbine (hydrogen single-firing) at an output of
500 MW class requires hydrogen equivalent to 2 million fuel cell vehicles, (3) not only liquidhydrogen but also various types of hydrogen carriers such as methylcyclohexane and ammonia canbe handled, and (4) the high start-up and load-changing (ramp rate) capabilities of gas turbines,
which can follow sudden variable renewable energy output (influenced by weather and seasons),
can flexibly balance the gap between the electricity demand and the supply capacity of renewableenergy.
However, there are some difficulties with hydrogen, namely, mass transportation and storage.
Japan largely depends on imported energy. If a hydrogen society is to be realized in Japan, the useof ammonia is considered to be another effective means. Among the carriers for hydrogentransportation and storage, ammonia has a higher volumetric hydrogen density than liquidhydrogen or methylcyclohexane, therefore enabling efficient hydrogen transportation and storage.
Ammonia is also advantageous in terms of handling, as the existing transportation/storage
infrastructure can be used for it. Furthermore, it is possible to directly burn ammonia as aMitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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carbon-free fuel. If GTCCs are able to be introduced ammonia at an early stage, it will become apromising carbon-free fuel of the future.
Focusing on hydrogen or ammonia-fired gas turbines among MHI’s projects for carbon
neutrality, this report presents the development status of the main items (i.e., gas turbine
combustors and combustion technologies) and the schedule for their validation.

|2. Development status of hydrogen or ammonia-fired gas turbines
2.1

Challenges of combustion hydrogen and ammonia

The conversion of a gas turbine from natural gas firing to hydrogen/ammonia firing becomes
possible by adding a new combustor and fuel supply system, and is therefore characterized by theminimum retrofitting as the main body can continue to be in use. Therefore, the development of gas
turbine combustor and combustion technology is the key to success in developing a hydrogen orammonia-fired gas turbine.
Figure 2 shows the combustion types and features of MHI gas turbine combustors. In
diffusion combustion, fuel and combustion air are injected separately into the combustor.
Compared with the premixed type, there are more localized rises in the flame temperature within
the combustor, and nitrogen oxides (NOx) emissions are increased. It is therefore necessary to takemeasures by injecting steam/water and reduce NOx emissions. On the other hand, the stablecombustion range is relatively wide, and the tolerance for fuel property fluctuations is large.
In premixed combustion, fuel and air are mixed in advance before being fed into the
combustor. Compared with the diffusion type, the pre-mixed system can reduce local rises of flame
temperature in the combustor. NOx reduction measures such as steam/water injection are therefore
unnecessary, and there is no decline in the cycle efficiency. Because of its capability ofsimultaneously achieving low NOx and CO2 reduction (high efficiency), the premixed type is usedas the base for the development of hydrogen/ammonia-fired combustor. However, the stablecombustion range is narrow, there are risks of combustion instability and flashback, and unburned
fuel tends to be discharged.

Figure 2

Diffusion and premixed combustion systems

Figure 3 compares natural gas which contains methane (CH4) as the main component and is
the most common fuel used in gas turbines, hydrogen and ammonia in terms of their lower heating
values and burning velocity. Hydrogen has a higher lower-heating value and a higher burning
velocity than methane; hydrogen burns about seven times quicker. When natural gas and hydrogenare co-fired in a premixed combustor or 100% hydrogen single-fired, the flame position moves
further upstream than when only natural gas is fired. This results in the high flame temperature
combustion occurring before fuel is sufficiently mixed with air, which leads to an increase in NOx
production. There is also an increased risk of flashback by which the flame traveling upstream of
the combustor burns out the areas along the route. Therefore, the combustor of hydrogen-fired gas
turbine needs to be improved to achieve low NOx emissions and stable combustion, particularly
focusing on preventing flashback.

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Figure 3 Comparison of methane, hydrogen and ammonia in terms of lower
heating values and burning velocity

On the other hand, ammonia has a lower heating value that is about one-third lower thanmethane, and the burning velocity is lower nearly one-fifth. As the combustion tends to beunstable, the challenge lies in keeping the flame stable. As shown in Table 2, fuel NOx is producedin large quantities in the process of combustion, because ammonia contains nitrogen (N). The
produced amount is larger by an order of magnitude than that of thermal NOx produced by the
combustion of natural gas. As the mechanism of fuel NOx generation is different, an
unconventional approach is needed to reduce such NOx.
Hydrogen and ammonia have thus dissimilar characteristics. The following sections describe
the status in the development of MHI gas turbine combustors and combustion technologies, withwhich hydrogen or ammonia can be handled.
Table 2
Fuel

Conventional fuel(e.g., LNG)
Ammonia
(NH3)

2.2
(1)

NOx generation mechanisms

NOx generation mechanism
Nitrogen oxides are formed, as a result of nitrogen in the air being
oxidized in the high-temperature combustion field (thermal NOx)
N2 (air) + O2 → NOx*NOx is generated by the thermal decomposition of N2
Nitrogen oxides are formed, as a result of oxidation of the fuel (fuel NOx)
NH3 (fuel) + O2 → N2 + H2O + NOx*NOx is generated by the chemical reaction of fuelAmount of NOx
generated(with no measures taken)
On a scale ofseveral hundred ppm
On a scale ofseveral thousand ppm

Development of hydrogen-fired combustors
Dry Low NOx (DLN) multi-nozzle combustor for hydrogen co-firing
A new hydrogen co-fired combustor was developed based on the conventional DLN
multi-nozzle combustor design, with the aim of preventing the risk of flashback from increasing
due to hydrogen co-firing. Figure 4 gives an outline. This premixed multi-nozzle combustor
has eight premixed fuel nozzles and one pilot flame fuel nozzle in the center to stabilize
combustion. Each nozzle is equipped with a swirler. The air passing through the swirler ismixed more uniformly with the fuel injected through the nozzle. There is a low flow velocity
zone, which is located in the center of the swirling flow (hereafter referred to as the vortexcore). It is believed that flashback occurs when the flame travels upstream through this vortex
core. In the new combustor, therefore, air is injected from the tip of the nozzle to increase theflow velocity in the vortex core, thereby compensating for the low flow velocity therein toprevent flashback.
A single unit of this combustor was used to conduct a combustion test under theoperating conditions (i.e., pressure and temperature) equivalent to a large gas turbine with theturbine inlet temperature of the 1,600°C class (hereafter referred to as the actual-pressure test)(Figure 4, left below). No flashback occurred at the rated load, while the hydrogen co-firingratio with natural gas was increased up to 30 vol%. The combustion was stable without amarked rise in combustion instability. NOx emissions were below the permissible level. These
results support the feasibility of operation in actual units.

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Figure 4

Hydrogen co-fired combustor and NOx levels at 30 vol% hydrogen co-firing testingMoreover, as a measure to achieve a higher co-firing ratio of hydrogen, the pilot flame
fuel nozzle in the center of the combustor employs diffusion combustion, which does not entail
the risk of flashback, as shown in Figure 5. Our plan is to further improve this design forenabling hydrogen single-firing. It is possible to increase the average hydrogen co-firing ratio
for the entire combustor up to 50 vol% by feeding the fuel blended with 30 vol% hydrogenthrough the eight premixed nozzles. Although NOx production may increase in the diffusion
combustion zone, it can be prevented by injecting water therein. The actual-pressure test has
demonstrated the operability of this combustor with NOx emissions below the permissible level
and the stable operation without flashback or marked rise in combustion instability. The
continuous improvement for a higher hydrogen co-firing ratio is still necessary. The
development is in progress toward the validation with an actual unit.

Figure 5 Improvement to achieve higher hydrogen co-firing ratio and NOx levels at 50
vol% hydrogen co-firing(2)

Multi-cluster combustor for hydrogen single-firing
As the hydrogen concentration becomes higher, the risk of flashback gets higher. The
resistance to flashback is considered higher, if the mixing distance can be shortened by mixing
air and hydrogen at a higher flow velocity on a smaller scale, rather than the multi-nozzle
system described in the earlier section in which air and hydrogen are mixed together using aswirling flow at a relatively low velocity in a large space. Figure 6 shows a multi-cluster
combustor for hydrogen single-firing, which is currently in development. There are many holes(premixing tubes) in the combustor, in which air and fuel are rapidly mixed. Formation of many
dispersed flames can also reduce NOx production.
In order to verify the combustion concept mentioned above and the combustibility, acombustion test was conducted under the pressure conditions equivalent to the actual unit using
an elemental burner, which is a part taken from the multi-cluster nozzle. Figure 7 shows the
combustion test equipment and the images of the flame during combustion. Hydrogen burns
with a flame with almost no emission of visible light; luminescence particular to hydrogenoccurs in the ultraviolet range. The ultraviolet imaging shows the uniform formation of stable

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flames a little away from the outlets of single premixing tubes in the burner. The test has
confirmed the occurrence of no flashback and stable combustion under the designed test
conditions.

Figure 6

Multi-cluster combustor for hydrogen single-firing

Figure 7 Elemental burner combustion test facility with a multi-cluster burner andhydrogen flames image

Furthermore, for small-to-middle class H-25 gas turbines, a full-scale actual-pressure test
was conducted using a multi-cluster combustor for hydrogen single-firing, which is currently indevelopment. In this test, the load was increased under the simulated operating conditions (i.e.,
temperature and flow rate) of an actual unit in which hydrogen is single fired. Without any
flashback or sudden rise in combustion instability, the combustion temperature reached thelevel equivalent to the rated load of the actual unit. Figure 8 shows the NOx measurementswith increasing load. While attempting to further reduce NOx, the development will continue
toward the validation with an actual unit.

Figure 8 NOx levels at hydrogen
single-firing

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These findings are also used as the basis for the design of multi-cluster combustors forlarge gas turbines. An actual-pressure combustion test with one full-scale combustor isunderway with a view to the validation for an actual unit in the future. The validation test will
be conducted using the actual-pressure combustion test facility at MHI’s Takasago Machinery
Works, as in the case of the hydrogen co-firing test as shown in Figure 9. Hydrogen fuel,which is required in large quantities for the hydrogen single-firing test, will be supplied fromthe hydrogen storage facility newly installed at the Hydrogen Park Takasago (described later)on the premises of Takasago Machinery Works. In the actual-pressure combustion test, thesmall-to-middle class H-25 gas turbine drives the air compressor, which supplies air for
combustion. This gas turbine will be used as the test unit, when hydrogen single-firing in asmall-to-middle gas turbine is verified.

Figure 9 Actual-pressure combustion test facility with which hydrogen single-firing test will
be conducted

2.3

Development status of ammonia-fired combustion systems

The technical challenges for burning ammonia as a fuel in gas turbines lie in keeping theflame stable in the combustor and controlling emissions of fuel NOx (i.e., NOx generated as aresult of oxidation of nitrogen in ammonia fuel), as described in Section 2.1. MHI is looking into
two types of GTCC systems using ammonia, as shown in Figure 10.

Figure 10

Ammonia-fired combustion systems

Mitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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Ammonia direct combustion GTCC system
In this gas turbine system, an ammonia combustor with less NOx emissions is combinedwith high-efficiency NOx removal equipment. For the combustor, a rich-lean two-stage
combustion scheme based on the diffusion combustor is under consideration as shown in
Figure 11. Figure 12 shows a schematic representation of fuel NOx emission characteristics
during ammonia combustion. There is a peak of fuel NOx generation in the neighborhood of a
stoichiometric equivalence ratio of φ = 1 (at which stoichiometric complete combustion occurs
between ammonia and air without excess or lack of either). In our rich-lean two-stage
combustion scheme, however, ammonia fuel and air (primary combustion air) are burnt in the
upstream side of the combustor in a fuel-rich state (φ ≥ 1 in the Rich Zone), before it is shiftedto a lean combustion state (in the Lean Zone) by rapidly mixing with secondary combustion air.
In this way, NOx generation is prevented.

Figure 11

Ammonia combustor with a two-stage combustion scheme

Figure 12 Fuel NOx emission characteristics
during ammonia combustion

The development of this system will proceed first with targeting small-to-middle class
H-25 gas turbine series. The ammonia combustion test facility at the Nagasaki District of MHI
Research and Innovation Center is used to conduct an atmospheric pressure combustion test
using a full-scale test combustor (one unit) for evaluation of the items such as flame stability,
NOx emissions and changes in the properties when fuel is switched from hydrocarbons toammonia. Figure 13 shows the visualized images in the combustor, when the fuel(hydrocarbons or ammonia) is combusted. Hydrocarbons burn with a blue flame, whileammonia produces a distinctive orange flame. The actual-pressure combustion test facility witha high-pressure ammonia supply system at the Hitachi Works (Katsuta) will be used to conduct
a combustion test under the pressure conditions equivalent to the actual unit. The development
will be continued with the view to enabling operation in an actual unit and commercialization inor after 2025.

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Figure 13 Atmospheric-pressure combustion test facility for ammonia and flame images in
combustor(2)

Ammonia cracking GTCC system
In the ammonia cracking GTCC system, high-temperature waste heat from the gas
turbine is used to decompose ammonia into hydrogen and nitrogen. The hydrogen is then burnt
in the hydrogen co-fired combustor (Section 2.2 (1)) or the combustor for hydrogen
single-firing under development (Section 2.2 (2)). The main component of the system is theammonia cracking equipment. It is also considered usable as a system by which hydrogen isreleased from ammonia transported as a hydrogen carrier, to supply to otherfacilities/equipment using hydrogen. For the practical application, research will be continued
considering the transfer of heat with a power generation system and the operability of the entire
system as well.

|3. Verification schedule
Actual gas turbines will be used for verification to enable early commercialization ofhydrogen or ammonia-fired gas turbines. For the enhanced reliability of MHI products throughverification using in-house facilities, the “Hydrogen Park Takasago” has been constructed on thepremises of Takasago Machinery Works, to make it possible to perform the world’s first integrated
technological validation from hydrogen production to power generation (Figure 14). The facility
has been in operation since 2023.

Figure 14

Hydrogen Park Takasago

Figure 15 shows the schedule for actual-unit verification, together with the reduction
timetable for CO2 emissions from gas turbines. The single-combustor test has confirmed that themulti-nozzle combustor for large gas turbines with hydrogen co-firing can operate with blends ofhydrogen fuel (up to 50 vol%). This satisfies the European CO2 emission standards (the criteria by
the EU taxonomy, which prescribe that gas thermal power plants with construction approval by theend of 2030 must not emit more CO2 than 270 g/kWh(2)). From 2023, the validation of hydrogenco-firing in the actual unit is underway using the hydrogen supply system at the Hydrogen Park
Takasago, with the aim of confirming the reliability for commercialization. Furthermore, hydrogen
single-firing in an actual small-to-middle gas turbine will be validated using a multi-cluster
combustor. Specifically, the H-25 gas turbine of the actual-pressure test facility (Figure 9) will be
used as the test unit for validation. The commercial operation of hydrogen co-firing (30 vol%)including the U.S. project described later will be started in 2025. For large gas turbines, hydrogen
single-firing is aimed to be verified by demonstration in 2030. Regarding ammonia firing, aMitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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demonstration will also be conducted on the small-to-middle class H-25 gas turbine to realize
practical application.

Figure 15

Schedule for actual-unit validation|4. Overseas projects for hydrogen or ammonia-fired gas turbines
In parallel with the scheduled demonstrations with an actual unit mentioned above, MHI
takes part in business development in the leading regions for the utilization of hydrogen andammonia in Japan as well as overseas, thereby working toward enabling the products to bepractically applied while promoting collaboration with external parties. Some examples are given
below.

4.1

Advanced Clean Energy Storage project in Utah, USA

Green hydrogen is produced using electricity from renewable energy sources found inabundance in the U.S. West Coast, before being stored in an underground rock salt cavern. Whenelectricity is needed, the stored green hydrogen is taken out to feed the gas turbine for power
generation. The generated electricity is then supplied widely in the states of California and Utah,aiming to stabilize the regional electricity supply and demand over a medium and long-term period.
MHI received an order for a GTCC power generation facility consisting of two 840 MW class
M501 JAC-type gas turbines as the core component, whose power generation plans involve 30
vol% hydrogen co-firing by 2025 and hydrogen single-firing by 2045. It is expected that power
generation with 30 vol% hydrogen co-firing contributes to a reduction of up to 4.6 million tons of
CO2 emissions per year.

Figure 16

Advanced Clean Energy Storage project in Utah, USAMitsubishi Heavy Industries Technical Review Vol. 60 No. 3 (September 2023)
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4.2

Hydrogen co-firing demonstration project at McDonough Atkinson Power
Plant, USA

In 2022, as a hydrogen co-firing demonstration project at an existing gas turbine power plant,
MHI Group together with Georgia Power, a U.S. electric utility, and the Electric Power ResearchInstitute (EPRI) conducted a combustion verification test in which an MHI M501G-type natural
gas-fired gas turbine (with a DLN multi-nozzle combustor) successfully operated on a blend ofhydrogen and natural gas at the McDonough Atkinson Power Plant in Georgia, shown in
Figure 17(3). This project was the world’s first demonstration of 20 vol% hydrogen co-firing in alarge, high-efficiency GTCC power generation facility, and was the largest test of its kind inhistory. CO2 emissions are reduced by about 7% from the level of natural gas firing, without
affecting the turbine inlet temperature, emissions and maintenance intervals. This verification test
has also demonstrated the following: the operation at a hydrogen blend ratio of 20 vol% throughout
the full-load range of gas turbines while maintaining the same NOx level as natural gas-fired
operation, and the improved combustion efficiency as a result of the decreased carbon monoxide(CO) emissions at partial load by co-firing hydrogen, thereby resulting in a 10% reduction(absolute value) in the minimum load at which the gas turbine can operate in compliance with theemission regulations.

Figure 17 U.S. McDonough Atkinson Power Plant and the verification test results of
combustion with a hydrogen blended fuel4.3

Implementation plan of ammonia-fired gas turbines

Many countries are planning to introduce ammonia to existing thermal power plants.
Although the application of ammonia co-firing in coal-fired boilers is ahead of the curve, there isalso a growing worldwide demand for ammonia-fired gas turbines, as indicated by the
implementation of the feasibility study (FS) for GTCC. MHI is also taking part.

|5. Conclusion
Focusing on hydrogen or ammonia-fired gas turbines among MHI’s projects for achievementof carbon neutrality, this report presents the development status of the main item (i.e., gas turbine
combustors) and the schedule for validation.
Regarding the co-firing system of hydrogen and natural gas, the single-combustor test has
demonstrated operability under the conditions in which 30 to 50 vol% hydrogen is co-fired. The
development will be advanced to the next stage of actual-unit validation for commercialization. For
the hydrogen single-firing system, actual-unit validation will be started with small-to-middle gas
turbines. The development of gas turbine systems using ammonia will also be continued forcommercialization. Expanding its product line-up of carbon-free power generation systems, MHI
aims for decarbonization through energy transition by 2030.
Through cooperation with its partners across the world for the development andcommercialization of hydrogen/ammonia-fired GTCCs that can contribute to CO2 reduction, MHI
continues to make efforts to achieve carbon neutrality as soon as possible.

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Acknowledgements:
The description of the combustors for hydrogen co-firing and hydrogen single-firing in
Section 2.2 of Chapter 2 in this paper is part of the results of a NEDO-funded project(Development of Technologies for Realizing a Hydrogen Society: JPNP14026). The ammonia
cracking GTCC system described in Section 2.3 of Chapter 2 has been developed with support
from NEDO as part of a project (Development of Technologies for Realizing a Hydrogen Society:
JPNP14026).

References
(1)

(2)

(3)

Outlook for energy supply and demand in FY 2030 (related materials), Agency for Natural Resources andEnergy,https://www.enecho.meti.go.jp/category/others/basic_plan/pdf/20211022_03.pdf
EU taxonomy: Complementary Climate Delegated Act to accelerate decarbonization,
https://finance.ec.europa.eu/publications/eu-taxonomy-complementary-climate-delegated-act-accelerate-d
ecarbonisation_en
Mitsubishi Power, Georgia Power, EPRI Complete World’s Largest Hydrogen Fuel Blending at Plant
McDonough-Atkinson, (2022) ,PRESS INFORMATION, Mitsubishi Heavy Industries, Ltd.,
https://power.mhi.com/regions/amer/news/20220610