Mitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
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Development of Hydrogen/Ammonia-firing Gas Turbine
for Carbon Neutrality
TERUHIRO MATSUMOTO*1 TOMO KAWAKAMI*1

HIROYUKI TAKEISHI*2

KEISUKE MIURA*3

SOSUKE NAKAMURA*4

MASANORI YURI*5

Mitsubishi Heavy Industries, Ltd. (MHI) has dedicated considerable resources to develophydrogen/ammonia-firing gas turbine combined cycles (GTCC). The development of a gas turbine
combustor that can operate on 30 vol% hydrogen mixed with natural gas has been completed foradvanced-class large-frame gas turbines. The hydrogen co-firing ratio has recently been increased
to 50 vol%. Combustion tests of 100% hydrogen dry firing in a combustor for small-to-middle size
turbines have been conducted, and further development of combustors for large gas turbines basedon the knowledge gained from these tests is in progress. A validation test of 20 vol% hydrogenco-firing was successfully completed at a large, high-efficiency GTCC power plant in North
America. Starting with this successful test, further validation efforts using actual facilities in the
future will be conducted with the aim of commercializing this technology. Through the development
and commercialization of hydrogen/ammonia-firing GTCC, MHI will contribute to the achievementof global carbon neutrality.

|1. Introduction
With the goal of achieving carbon neutrality by 2050, initiatives to reduce carbon dioxide(CO2) emissions are being actively promoted in every field, e.g., politics, economics, industry, andscience technology. The European Union has led the world in establishing the "EU Taxonomy" as a
new standard for achieving the "Sustainable Development Goals" by simultaneously achieving
environmental friendliness and economic activity. In Japan, the government has announced "the2050 Carbon Neutral Declaration". The energy sector accounts for more than 80% of greenhousegas emissions, therefore, the efforts in the electricity sector were considered particularly importantin the declaration. For electricity, into which primary energy is mainly converted, it was set in theoutlook for energy supply and demand in fiscal 2030(1) that 1% of electricity shall be covered byhydrogen and ammonia power generation.
Under these circumstances, we have declared "MISSION NET ZERO" and are working
thereunder to provide products, technologies, and services that contribute to CO2 reduction andcooperate with our partners around the world for achieving carbon neutrality in the global
community as a whole. As shown in Figure 1, through the development of the JAC series gas
turbine, we have achieved CO2 reduction by increasing the efficiency and capacity of GTCCs,
which have the lowest CO2 emissions and highest efficiency among thermal power generation
plants. MHI is also developing technologies to improve the operability of gas turbines to respondquickly and flexibly to fluctuations in the amount of electricity generated by renewable energy,
which has been increasing. To further reduce CO2 emissions, MHI is introducing carbon recyclingcombined with CO2 capture, i.e., Carbon Capture Utilization and Storage (CCUS), and non-CO2
emitting fuels such as hydrogen (H2) and ammonia (NH3).
*1

Chief Staff Manager, Gas Turbine Engineering Department, Energy Systems, Mitsubishi Heavy Industries, Ltd.

*2

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

*3

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

*4

Deputy Director, Gas Turbine Engineering Department, Energy Systems, Mitsubishi Heavy Industries, Ltd.

*5

Director, Gas Turbine Engineering Department, Energy Systems, Mitsubishi Heavy Industries, Ltd.

Mitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
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The successful development of a combustor that can use 30 vol% hydrogen mixed withnatural gas fuel in a large gas turbine for power generation(2) was achieved with the support of the
New Energy and Industrial Technology Development Organization (NEDO). This effort was
followed by combustion tests with increased hydrogen co-firing ratio up to 50 vol%. In addition,
the target of obtaining 100% hydrogen dry firing in a combustor for small-to-middle gas turbines
through combustion tests is getting closer, while the development of a single-fuel hydrogen-firing
combustor for large gas turbines is in progress. Meanwhile, research and development of a GTCC
system using ammonia is being conducted, which is expected to be utilized as an energy carrier forhydrogen. As part of the development of these hydrogen/ammonia-firing gas turbines, thevalidation test of 20 vol% hydrogen co-firing was successfully performed at a high-efficiency,
large-scale GTCC (M501G natural gas-firing) power plant in the United States in June 2022(3).
This was the largest scale combustion validation test of hydrogen mixed fuel using an
advanced-class commercial plant and was a very significant step toward the practical application ofhydrogen gas turbines.
This paper introduces the development and validation status of MHI gas turbines for power
generation utilizing hydrogen and ammonia, and the initiatives to achieve carbon neutrality, while
focusing on the schedule for their commercialization.

Figure 1

MHI initiatives in the power generation sector to achieve carbon neutrality|2. Role of hydrogen/ammonia-firing gas turbines in carbon
neutrality
Hydrogen is considered the most effective carbon-free fuel to replace or supplement fossil
fuels. This is because hydrogen has a high potential for converting existing fossil fuel equipment
and systems into carbon-free alternatives while keeping them in operation. As the infrastructure for
global hydrogen procurement is being developed, examples of utilizing existing gas-firing power
generation infrastructure, currently available on a large scale both in Japan and overseas, includes
the production of hydrogen with water electrolyzers using carbon-neutral electricity from theexisting electric power system (grid), producing hydrogen by pyrolysis of natural gas sent throughexisting gas pipelines, and utilizing waste heat from gas turbines, for example, for the heat requiredfor pyrolysis. In these cases, hydrogen production can be gradually increased and mixed withnatural gas for use in gas turbine power generation, reducing the need for large capital investment
all at once. As a result, investment costs can be controlled and hydrogen power generation may berealized with the highest economic rationality.
Large-capacity, high-efficiency hydrogen-firing gas turbines have the following roles in thevalue chain that includes hydrogen production, transportation, storage, and utilization (Figure 2).

Mitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
3(a) Existing gas turbine equipment can be converted to low-carbon or decarbonizedequipment with minor modifications. It is expected to promote a smooth shift to acarbon-neutral society by reducing investment costs without requiring large-scale renewal
except for the gas turbine combustor and fuel supply system.
(b) Not only liquid hydrogen, but also various hydrogen carriers such as
methylcyclohexane and ammonia can be used. Low-purity hydrogen can be used, resulting in
the reduction of hydrogen costs.
(c) A large hydrogen-firing gas turbine with an output of 500 MW (100% single-fuelhydrogen-firing) requires hydrogen equivalent to 2 million fuel cell vehicles in a single power
generation plant. Therefore, it is expected to stimulate large-scale hydrogen demand, expand
the supply chain, and reduce hydrogen costs.
(d) Gas turbines start-up quickly and can apply rapid load changes. These features arevaluable to quickly respond to sudden grid power requirements oscillations induced by weather
and seasonal changes on renewable energy dispatch. These fast response characteristics can be
maintained while applying hydrogen production and storage capabilities.
As described above, the utilization of hydrogen for large-capacity, high-efficiency gas
turbines for power generation plays an indispensable role toward achieving carbon neutrality.

Figure 2

Role of hydrogen gas turbine|3. Development of hydrogen-firing combustors
Hydrogen-firing gas turbines do not require large-scale modification of existing natural
gas-firing gas turbines, except for the combustor and fuel supply system. Therefore, the key points
for development are combustion technology and combustors that can handle hydrogen-firing.
Figure 3 shows the combustion types and features of MHI gas turbine combustors that areused as the basis for the development of hydrogen-firing combustors. In the case of a diffusion
combustor, fuel and combustion air are injected separately into the combustor. Compared to thepremixed type, the flame temperature in the combustor increases locally and NOx emissions arehigher, therefore, steam and water injection are necessary to reduce NOx emissions. On the other
hand, the stable combustion range is relatively wide, and the tolerance for fuel property fluctuations
is large.
In the case of a premixed combustor, fuel and air are pre-mixed and fed into the combustor.
Compared to the diffusion combustion, pre-mixed type can reduce the local flame temperature in
the combustor. Therefore, NOx reduction methods, such as steam and water injection are
unnecessary for pre-mixed combustors and the cycle efficiency is not reduced. On the other hand,the stable combustion range is narrow, there is a risk of flashbacks, and unburned fuel tends to bedischarged. MHI multi-nozzle DLN combustor has eight premix fuel nozzles and one pilot flame
fuel nozzle in the center of them to stabilize combustion. Each nozzle is equipped with a swirler,

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and the air passing through the swirler and the fuel injected through the nozzle are more evenly
mixed, reducing the flame temperature in the combustor further and enabling lower NOx
combustion. Multi-cluster-type premixed combustors have more nozzles compared to themulti-nozzle type. Although there is no swirler as in the multi-nozzle type, each fuel nozzle issmaller so that the fuel and air are mixed on a smaller scale and the flame is dispersed, thusachieving both high flashback resistance and low NOx combustion.
Hydrogen has the characteristic of burning faster than natural gas. Therefore, when natural
gas and hydrogen are co-fired in a premixed combustor or single-fuel hydrogen is fired, the risk offlashbacks is higher than when only natural gas is fired. Because flashbacks can cause the flame totravel upstream of the premixed nozzle and burn that area, the combustor for a hydrogen-firing gas
turbine needs to be improved mainly to prevent flashbacks, as well as to achieve low NOx
emissions and stable combustion. Figure 4 shows an overview of our combustors for hydrogen gas
turbines, in which either hydrogen co-firing or single-fuel hydrogen firing is possible, and theirdevelopment status is described in the next section.

Figure 3

Our gas turbine combustors and their features

Figure 4 Combustors for hydrogen gas turbinesMitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
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3.1

Dry Low NOx (DLN) multi-nozzle combustor for hydrogen co-firing

A hydrogen co-firing combustor was developed based on a modified conventional DLN
design with the aim of reducing the risk of flashbacks induced by hydrogen co-firing. Figure 5
shows an overview of the combustor where air supplied from the compressor flows into the
combustor passing through the swirler and creating a swirl flow. Fuel is supplied through small
holes on the surface of the swirler vanes and is rapidly mixed with the surrounding air by the swirl
flow. As shown in the upper right corner of Figure 5, there is a region of low flow velocity
downstream of the swirler (hereinafter referred to as "vortex core") at the center of the swirl flow.
This lower axial velocity can promote flashback against the downstream flow. The modified
combustor injects air from the tip of the nozzle to increase the flow velocity of the vortex core tocompensate for the low flow velocity region and reduce the risk of flashback.

Figure 5(a)Hydrogen co-firing combustor

30 vol% hydrogen co-firing combustion test
An actual pressure combustion test was conducted on the test facility shown in Figure 6.
A full-scale hydrogen co-firing combustor under operating conditions equivalent to those of an
actual gas turbine were applied. Figure 7 shows the change in NOx emissions with respect tothe hydrogen mixing ratio in the fuel under conditions equivalent to the rated load of a gas
turbine with a Turbine Inlet Temperature (TIT) of 1,600°C. The figure indicates the trend of aslight increase in NOx with an increase in the hydrogen mixing ratio. This is thought to be
attributable to the fact that hydrogen mixed in the fuel increases the combustion rate, causing
the flame position in the combustor to move upstream inducing insufficient fuel-air mixing.
However, it was confirmed that NOx emissions were below the permissible value and within
the operational range even when 30 vol% hydrogen was mixed into the fuel. It was also
confirmed that the pressure level of combustion instability was not significantly affected bychanges in the hydrogen mixture ratio. No flashbacks were observed in the 30 vol% hydrogenco-firing. These results indicate that the 30 vol% hydrogen co-firing can be operated without
flashbacks or significant increases in NOx and combustion instability.

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Figure 6

Takasago pressure combustion test facility

Figure 7

Change in NOx emissions with respect to hydrogen mixing ratio(b)

50 vol% hydrogen co-firing combustion test
A diffusion combustion type was considered to further increase the hydrogen co-firingratio in order to reduce the risk of flashback. This involved feeding 100 vol% hydrogen throughthe pilot fuel nozzle located in the center of the combustor, as shown in the center of Figure 8,
while feeding 30 vol% hydrogen through the eight premixed nozzles for an average of 50 vol%hydrogen co-firing ratio for the entire combustor. The increase in NOx production in the
diffusion combustion zone can be suppressed by injecting water in that zone. This combustor
demonstrated stable operation without flashbacks or significant increases in combustion
instability while tested at actual-pressure combustion. It was confirmed that NOx emissions
were below the permissible value. Based on this test results, the feasibility of 50 vol%hydrogen co-firing, the prospect of not exceeding 270 [g/kWh], CO2 emissions of gas-firing
power generation projects approval for construction by the end of 2030 as set in the EU
Taxonomy(4) was obtained.

Figure 8 Measures to increase hydrogen co-firing ratio and NOx emissions from 50 vol%hydrogen co-firing

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3.2

Multi-cluster combustor for single-fuel hydrogen firing (Figure 9)
When the hydrogen concentration becomes higher, the risk of flashback, which occurs in the
low flow velocity region of the vortex core, becomes higher when the fuel-air mixing type by swirl
flow used in the multi-nozzle-type hydrogen co-firing combustor described in the previous section
is used. Therefore, a mixing type that does not use swirl flow and can mix air and hydrogen on asmaller scale is considered to be more resistant to flashback. MHI is developing a single-fuelhydrogen combustor based on the multi-cluster combustor applied to the IGCC(5) Osaki CoolGen
Corporation facility in Japan.
A full-scale, actual-pressure combustion test was conducted using one multi-cluster
combustor for single-fuel hydrogen firing, which is being developed for small-to-middle size Hclass gas turbines. In the test, the load was gradually increased from a low combustion temperaturestate, during 100% hydrogen firing under operating conditions equivalent to the actual equipment.
The NOx value increased gradually as the load increased, but there were no sudden increase in
combustion instability level or flashback during the load increasing process all the way up to the
combustion temperature equivalent to the rated load. This development will continue toward
validation using actual equipment, while applying the knowledge and technology obtained on themulti-cluster design for large frame gas turbines.

Figure 9

3.3

Multi-cluster combustor and NOx at 100 vol% single-fuel hydrogen firing

Diffusion combustor

Since the 1970s, MHI has manufactured many small-to-middle gas turbines for thecogeneration market that handle hydrogen-rich fuels. The diffusion combustor employed (Figure10) has a proven record in the utilization of fuels with a wide range of hydrogen content ratios.
These long experience includes refinery off-gas fuels with hydrogen contents as high as 90 vol%.
The above effort includes a successful single-fuel hydrogen firing combustion tests
conducted as part of a research and development project of international hydrogen-utilizing clean
energy system technology (World Energy NET WORK (WE-NET)).

Mitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
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Figure 10

Diffusion combustor capable of hydrogen firing|4. Ammonia-firing gas turbine
There are challenges in mass transportation and storage of hydrogen. The practicalapplication of the hydrogen value chain may take precedence in Europe and the United States,
where large-scale gas infrastructure such as pipelines is available. On the other hand, in Japan, theuse of ammonia (NH3) is considered to be an effective means to realize a hydrogen society. Among
carriers for transporting and storing hydrogen, ammonia has a higher hydrogen density per volume
than liquid hydrogen or methylcyclohexane, and can transport and store hydrogen efficiently. In
addition, existing infrastructure for liquefied petroleum gas and the like can be converted totransport and store ammonia. Considering that ammonia can be directly combusted as a carbon-freefuel, it is expected to be effectively used following its early introduction into power generation
facilities in the future. MHI is currently working on the development of a gas turbine system using
ammonia, as shown in Figure 11, and will further expand the lineup of carbon-free power
generation systems.

Figure 11

4.1

Ammonia-utilizing gas turbine system

Ammonia direct-firing gas turbine system

MHI have begun developing a small-to-middle single-fuel ammonia-firing gas turbine
system that can use ammonia as a fuel for gas turbine power generation, targeting its use for our
H-25 series gas turbine (40,000-kW-class output). Ammonia (NH3) direct firing tends to cause
combustion instability because its combustion rate is about 1/5 of that of methane, which is themain component of natural gas, and generates a large amount of nitrogen oxide (NOx) due to theoxidation of nitrogen (N) in the ammonia fuel. To solve these issues, the development of a
combustor that can reduce NOx emissions is in progress to establish a gas turbine system thatcombines high-efficiency NOx removal equipment with the developed combustor, toward theMitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
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practical use of the system.
In developing the combustor, the deployment of a rich-lean two-stage combustion scheme
based on a diffusion combustor is being considered (Figure 12). This scheme combusts fuelammonia and air (primary combustion air) in the upstream region of the combustor in a fuel-richstate (above stoichiometry (equivalent ratio φ = 1)), and then immediately shifts the state to a lean
combustion state by rapid mixing with secondary combustion air to suppress NOx emissions. The
ammonia combustion test facility shown in Figure 13 have been prepared using one full-scale
combustor. It is being used for development and analysis of combustion stability, NOx emissions,and characteristics during ammonia fuel switching in prototype combustor tests.
There has been no previous application of direct ammonia-firing to such a large-power gas
turbine. This development can contribute to carbon neutrality by stimulating demand for hydrogenand ammonia on a large scale.

Figure 12 Combustor based on rich-lean two-stage combustion
schemeFigure 13

4.2

Ammonia firing combustion test facility

Ammonia decomposition cycle gas turbine system

In the case of firing ammonia in large gas turbines with combustion gas temperatures higher
than small-to-middle gas turbines, it is necessary to take into account the fact that an larger amountof fuel-derived NOx is generated and that adopting the aforementioned rich-lean two-stage
combustion scheme involves many design constraints and technical issues, such as the larger sizeand greater complexity of the combustor. Therefore, for the large gas turbine, the use of anammonia decomposition system into hydrogen and nitrogen is being considered. This systemapplies waste heat from the gas turbine and the hydrogen is combusted in either a hydrogenco-firing combustor that has been already developed, or in a single-fuel hydrogen firing combustor
that is under development.

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When hydrogen produced through ammonia decomposition is combusted, some of theammonia remaining from the ammonia decomposition process is expected to be converted to fuelNOx in the combustor and emitted additionally to the thermal NOx originally generated in the
combustor. Aiming to satisfy the NOx emission limits, an actual pressure combustion test was
conducted in order to determine the amount of NOx increase due to residual ammonia. In the test, afuel mixture of natural gas and ammonia decomposition gas, which was composed of 20 vol%hydrogen, 6.7 vol% nitrogen, 73.3 vol% natural gas, and a small amount of ammonia, wascombusted in a 1,650°C-class hydrogen co-firing gas turbine. Figure 14 shows the relationshipbetween the concentration of ammonia in the fuel and the NOx concentration in the exhaust gas
when the turbine inlet temperature is 1,650℃ (rated conditions). The NOx concentration increased
linearly with increasing ammonia concentration (marked with "●" in the figure), and theconversion ratio of ammonia to NOx (CR (Conversion Ratio in the figure)) was approximately
90%. The test results also confirmed that stable operation was possible without flashbacks orsignificant increases in combustion instability.
Toward the practical application of this system, the ammonia decomposer study is ongoingas the main piece of the facility, as well as the heat transfer with the power generation system andthe operability of the entire system.

Figure 14 Relationship between concentration of ammonia
in the fuel and NOx concentration in exhaust gas|5. Demonstration schedule toward practical application
The validations of the practical application of hydrogen power generation, will proceed withan actual gas turbine based on the results obtained through elemental development. The
development, design, manufacture, and validation of gas turbines is on-going at the Takasago
Machinery Works facility (Takasago City, Hyogo Prefecture). By conducting the cycle
development, which consists of verification tests of each element in the basic design phase,reflecting their results in the detailed design, and finally conducting validations using actual
equipment, in the same plant, there has been a quick and reliable practical use of products. In
connection with the development and demonstration of hydrogen gas turbines, the Takasago
Hydrogen Park is being built (Figure 15). This is the world's first validation facility forhydrogen-related technologies, including upstream generation of hydrogen. It is scheduled to begin
operation in 2023. By additionally installing the hydrogen production and storage facility adjacentto the existing GTCC validation facility, validation with an integrated process from next-generationhydrogen production technology to power generation using a hydrogen gas turbine is possible. The
facility will use the park's hydrogen to demonstrate hydrogen co-firing (30 vol%) in a large gas
turbine and single-fuel hydrogen firing in a small-to-medium gas turbine using an H-25 series gas
turbine. This effort will facilitate the start of hydrogen co-firing (30 vol%) commercialization,
including the U.S. Utah project, in 2025. Additional single-fuel hydrogen firing in a large gas
turbine is being targeted for practical use by 2030. Ammonia firing validation using an H-25 series
gas turbine will support the aim of its commercialization.

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Figure 15

Takasago Hydrogen Park and schedule for commercialization|6. Hydrogen-firing gas turbine projectThrough our initiatives toward hydrogen-firing gas turbines, MHI is participating in businessdevelopment in domestic and overseas regions where the utilization of hydrogen is being applied.
The aim is to commercialize MHI products while promoting collaboration with outside parties.
This chapter presents two hydrogen-firing gas turbine projects in the United States.

6.1

Hydrogen fuel co-firing validation project at McDonough Atkinson Power
Plant in US

In June 2022, MHI U.S. subsidiary, Mitsubishi Power Americas, together with Georgia
Power, a U.S. electric utility, and The Electric Power Research Institute (EPRI), one of the world's
leading independent, non-profit energy research and development organizations, successfullycompleted a hydrogen-natural gas mixed fuel combustion validation test under both partial-loadand full-load conditions, using an M501G series natural gas-firing gas turbine that operates
commercially at the McDonough Atkinson power plant in Georgia, shown in Figure 16. The
validation test was conducted as part of Georgia Power's initiatives to build an energy grid of the
future and enhance CO2 emission reductions across their commercial power generation fleet. This
test was the world's first 20 vol% hydrogen-mixed fuel combustion validation in high-efficiency,
large-scale GTCC power generation facility, and the largest test of its kind in history. By using 20
vol% hydrogen mixed fuel, CO2 emissions are reduced by about 7% compared to natural gas
combustion, without affecting turbine inlet temperature, emissions, and maintenance intervals.
MHI DLN multi-nozzle combustor was used in the validation test and the following items wereconfirmed:(i) Operation with a 20 vol% hydrogen mixed fuel was achieved in the full-load range of thegas turbine.
(ii) Reduced carbon monoxide (CO) emissions generated at partial load with hydrogenco-firing. This improved combustion efficiency and it was confirmed that theminimum load can be lowered by 10% (absolute value) while complying withemission regulations.
(iii) Same NOx level achieved with natural gas-firing operation can be maintained during 20

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vol% hydrogen co-firing operation.
(iv) Safe switching between natural gas and hydrogen mixed fuel through adjustments of theoperational control logic without increasing the turbine inlet temperature, wassuccessfully validated. This is particularly important when shutting off the hydrogen.
MHI was in charge of engineering, planning, supply of hydrogen co-firing facility andcomponents, operation control, commissioning, and risk management for this project. This effort
represents a substantial progress of MHI efforts to implement hydrogen combustion towards
developing 100 vol% single-fuel hydrogen firing technologies and was a very significant step
toward the practical application of hydrogen gas turbines.

Figure 16 McDonough Power Plant in US and results of combustion validation test
using hydrogen-mixed fuel

6.2

Intermountain GTCC power generation project in US

MHI received an order for a GTCC power generation facility consisting of two 840MW class
M501JAC gas turbines capable of operating with hydrogen mixing fuel. This GTCC power
generation project was planned by Intermountain Power Agency (IPA) in the state of Utah, inwhich power generation using 30 vol% hydrogen co-firing by 2025 and single-fuel hydrogen firingby 2045 is planned. This project is associated with the upgrading of an existing coal-firing power
plant, and the conversion to 30 vol% co-firing GTCC is expected to contribute to a reduction of up
to 4.6 million tons of CO2 emissions per year. The hydrogen fuel is expected to be produced fromrenewable energy sources and stored underground through an advanced clean energy storage
project. As shown in Figure 17, this project (1) produces green hydrogen by water electrolysis
using inexpensive renewable electricity from the U.S. West Coast, (2) stores the green hydrogen inunderground salt cavities that are abundant in this region, and (3) utilizes the green hydrogen stored
in the salt cavities to generate electricity by GTCC when power is needed. The generated electricity
will be supplied from the Intermountain Power Plant to California and Utah on the other side of the
Rocky Mountains to establish a hydrogen value chain in the region.

Figure 17 Overview of Intermountain GTCC power generation project in US

Mitsubishi Heavy Industries Technical Review Vol. 59 No. 4 (December 2022)
13|7. Conclusion
This paper introduced the development and validation status of MHI gas turbines for power
generation utilizing hydrogen and ammonia, and the initiatives to achieve carbon neutrality,
focusing on the schedule for their commercialization.
It describes the development of a hydrogen-natural gas co-firing gas turbine combustor, andthe successful prospect of operating gas turbine under 30 vol% hydrogen co-firing conditions.
This effort will continue to develop hydrogen co-firing systems and validate actual equipment
toward its practical application. It will also continue the development of direct firing gas turbine
systems utilizing ammonia as well as ammonia decomposition cycle gas turbine systems andexpand the product lineup of carbon-free power generation systems.
MHI will cooperate with its partners around the world through the development andcommercialization of hydrogen/ammonia-firing GTCCs to contribute to CO2 reduction, and will
make further efforts to achieve carbon neutrality for the entire global society.
(Acknowledgements)
The contents described in Chapter 3 of this paper are part of the results of a project(Development of Technologies for Realizing a Hydrogen Society: JPNP14026) funded by the New
Energy and Industrial Technology Development Organization (NEDO). The development of GTCC
using ammonia decomposition gas described in Chapter 4 was supported by the New Energy andIndustrial Technology Development Organization (NEDO) as part of a project (Development ofTechnologies for Realizing a Hydrogen Society: JPNP14026).

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