Ammonia as a Hydrogen Carrier: Cracking Options for Gas Turbines & CCGTs

By Green Gas Turbines Team · Published December 5, 2025 · 19 min read

Why Ammonia as a Hydrogen Carrier Matters for Gas Turbines

Decarbonizing large gas turbine (GT) fleets is no longer just about hydrogen-ready burners and carbon capture. Increasingly, project developers and policymakers are looking at ammonia as a hydrogen carrier that can be shipped globally, stored in large tanks, and then converted back to hydrogen close to the point of use.

For gas turbines, that conversion step is rarely optional. Pure ammonia combustion suffers from slow flame speed and high fuel-NOx formation, so most practical power concepts rely on ammonia cracking for gas turbines to generate hydrogen-rich fuel. The key engineering question becomes: how much should we crack (partial vs full), and how should we integrate the cracker with the turbine and its waste heat?

Hydrogen Carrier Basics: Why Ammonia Beats Liquid Hydrogen for Transport

Ammonia (NH₃) is a carbon-free molecule that contains 17–18 wt% hydrogen. Its appeal as a hydrogen carrier is thermophysical as much as chemical:

• Milder liquefaction – Ammonia liquefies at about −33 °C at atmospheric pressure, or near ambient temperature at moderate pressure. Liquid hydrogen (LH₂) requires around −253 °C, demanding far more complex cryogenics.
• High volumetric hydrogen density – Per cubic metre, liquid ammonia stores more hydrogen atoms than liquid hydrogen, so a ship or tank of NH₃ actually carries more usable hydrogen energy than the same volume of LH₂.
• Existing global infrastructure – Over 180 million tonnes per year of ammonia production and a mature shipping and storage ecosystem already exist, driven by fertilizer demand. Power projects can piggy-back on that supply chain rather than inventing one from scratch.

From a hydrogen carrier efficiency perspective, ammonia introduces additional process steps (synthesis and cracking) but often wins at system level because transport and storage are simpler, especially for long-distance seaborne trade.

From Tank to Turbine: Combustion Pathways for Ammonia

Once ammonia reaches the power plant, you have three broad options:

1. Direct ammonia firing – Burn gaseous ammonia directly in the gas turbine combustor with a dedicated burner.
2. Partial cracking – Crack only a fraction of the NH₃ to hydrogen, then feed a blended NH₃/H₂ fuel to the turbine.
3. Full cracking – Convert almost all NH₃ to H₂ (plus N₂) and feed a hydrogen-rich stream to a hydrogen-capable turbine or fuel cell.

Modern gas turbine concepts typically use a hybrid approach for stationary power: some degree of ammonia cracking combined with a burner that can handle varying hydrogen content. Completely bypassing cracking and burning neat NH₃ is possible, but only with very specialized combustors and heavy NOx mitigation.

Direct Ammonia Firing: What the Pilots Show

Several OEMs are demonstrating that direct ammonia firing is technically feasible:

• Mitsubishi Power has developed a 40 MW-class H-25 gas turbine configured for 100% ammonia firing, pairing an advanced combustor with downstream SCR to manage fuel-NOx. Test campaigns in Japan are part of a roadmap toward commercial operation around the late 2020s.
• IHI Corporation has operated a 2 MW class 100% ammonia gas turbine and reported major reductions in N₂O emissions through burner design and optimized staging, while maintaining stable operation for hours at a time.

These projects prove that ammonia can be burned directly in GT hardware. But for many large-scale power projects, full direct firing is still a stretch target. That is where integrated cracking becomes more attractive.

Cracking Strategies: Partial vs Full NH₃ to H₂ Conversion

Reaction Basics

Ammonia cracking is the catalytic decomposition of ammonia into nitrogen and hydrogen:

2 NH₃ → N₂ + 3 H₂

The reaction is strongly endothermic, so it requires high temperatures (typically 500–800 °C) and a catalyst. In a gas turbine plant, that heat ideally comes from waste heat in the exhaust rather than burning extra fuel just to run the cracker.

Partial Cracking (“Doping”) for Flame Stability

From a combustion perspective, ammonia’s main weakness is its very low laminar burning velocity — roughly one-fifth that of methane under comparable conditions. In practice, this means:

• Slow flame propagation and a high tendency toward lean blowout.
• Difficulty sustaining a stable flame in lean-premixed, low-NOx combustors.
• Higher unburned ammonia slip if the flame is not well anchored.

The most common gas turbine strategy is therefore to crack only a fraction of the ammonia (for example 20–30%) and create an NH₃/H₂ blend. The hydrogen behaves like a “spark plug” for the mixture:

• Faster flame speed and wider stable operating window.
• Improved ignition and re-ignition performance.
• Better tolerance to transient load changes and grid-frequency events.

OEMs like GE Vernova, IHI, Mitsubishi Power, and Siemens Energy are all exploring some variant of partial ammonia cracking for gas turbines, whether for new designs or retrofit concepts.

Full Cracking: Hydrogen Turbines and Fuel Cells

In full cracking concepts, ammonia is decomposed almost completely to a hydrogen-rich mixture (H₂ with N₂ ballast). That stream feeds either:

• a hydrogen-ready industrial gas turbine, or
• a fuel cell system (typically PEM or SOFC) that requires high-purity hydrogen.

For direct turbine firing, full cracking is less common today because:

• The cracker must be large enough to process all of the fuel.
• The energy penalty of cracking becomes more visible if it cannot be fully covered by waste heat.
• Most current GTs are not yet certified for 100% hydrogen operation at scale.

However, full cracking is highly relevant for fuel cell projects and for future plants where the gas turbine is explicitly designed as a hydrogen machine and ammonia is just the upstream carrier.

Reactor Options for Ammonia Cracking in GT Projects

Packed Bed Reactors (PBR): Today’s Workhorse

The standard industrial approach to ammonia cracking is the packed bed reactor (PBR): a tube or bundle of tubes filled with a supported catalyst (typically Nickel or Ruthenium on a porous support). Key features:

• Mature technology – Similar hardware is already used in reforming and other high-temperature processes.
• High throughput – Multi-tubular designs can process large ammonia flows at GT scale.
• Simple layout – In a combined-cycle plant, PBRs can sit in the HRSG or in a dedicated exhaust-gas duct, using turbine exhaust as the primary heat source.

Limitations include axial temperature gradients, relatively slow start-up (large thermal mass), and the need for very high inlet temperatures when using lower-cost catalysts like Nickel.

Membrane Reactors: Cracking and Separation in One Unit

Membrane reactors integrate the catalyst bed with a hydrogen-selective membrane (often Pd-based or advanced ceramic/metal composites). Hydrogen is removed through the membrane as it forms, which:

• Shifts the reaction equilibrium, enabling high NH₃ conversion at lower temperatures.
• Delivers a stream of high-purity H₂ suitable for fuel cells or high-hydrogen turbines.
• Reduces total reactor volume for a given hydrogen output.

For stationary power, membrane reactors are especially attractive when you need clean hydrogen for a PEM fuel cell or a hydrogen-only combustor. Challenges include membrane cost (especially Pd-alloys), long-term mechanical stability, and sealing under thermal cycling.

Electrified and Modular Cracking Systems

Beyond classical fired or exhaust-heated reactors, several R&D programs are exploring:

• Electrically heated monolith or foam reactors with fast dynamics and compact footprints.
• Solar-driven or thermochemical recuperation systems that couple ammonia cracking to renewable or low-grade heat sources.
• Modular skid-mounted crackers sized for individual turbines or industrial users, simplifying project deployment.

For now, though, PBRs plus good heat integration remain the default choice for gas turbine projects.

Catalyst Choices: Nickel vs Ruthenium (and What Comes Next)

The performance, size, and temperature of an ammonia cracker are dominated by the catalyst. Two metals are especially important:

Nickel (Ni): Cost-Effective Workhorse

• Pros: Abundant, relatively inexpensive, and already familiar in reforming and hydrogen plants.
• Cons: Lower intrinsic activity for NH₃ decomposition, so PBRs with Ni catalysts typically require inlet temperatures >700 °C to approach equilibrium conversion. That means more heat-exchange surface and larger reactors.
• Use cases: Large stationary plants where space is available and high-temperature heat from GT exhaust (or duct firing) is readily accessible.

Ruthenium (Ru): High-Performance Benchmark

• Pros: Ru-based catalysts on conductive or basic supports can deliver near-equilibrium NH₃ conversion below about 500 °C, slashing reactor size and easing heat-integration constraints.
• Cons: Ruthenium is an expensive noble metal, and supply is limited. Poisoning by impurities (sulfur, alkali metals, particulates) must be carefully controlled.
• Use cases: Compact, high-performance crackers (for example near fuel cells, offshore platforms, or space-constrained GT retrofits) where catalyst cost is acceptable.

In the literature, Ruthenium is often treated as the performance reference, while Nickel is the baseline industrial standard. A large body of ongoing research is trying to close the gap with more abundant metals and tailored supports:

• Promoted Ni catalysts (e.g. Ni with alkali or rare-earth promoters) to lift activity at lower temperature.
• Non-noble candidates based on Co, Fe, or bimetallic systems.
• Structured catalysts (foams, monoliths, 3D-printed internals) that improve heat and mass transfer in the reactor.

For power developers today, though, the practical choice is still between Ni (cheaper, hotter, bigger) and Ru (smaller, cooler, costlier).

How OEMs Are Implementing Ammonia & Cracked-Ammonia Solutions

Mitsubishi Power: Ammonia-Fired H-25 and Chemically Recuperated Cycles

Mitsubishi Power has positioned ammonia as a core decarbonization option for its H-25 (40 MW class) gas turbine. Two elements stand out:

• 100% ammonia firing with a purpose-designed combustor and downstream SCR to manage high fuel-NOx, targeting commercial use around the end of this decade.
• Ammonia-to-hydrogen cycles where ammonia is cracked using turbine exhaust heat, and the resulting hydrogen (with some nitrogen ballast) feeds a hydrogen-capable turbine. Thermodynamic studies show that when cracking is fully integrated with the combined-cycle heat-recovery train, overall cycle efficiency can match, or even slightly exceed, that of a reference natural-gas GTCC.

IHI & GE Vernova: Retrofitting F-Class Turbines for Ammonia

IHI Corporation and GE Vernova have signed joint development agreements targeting 100% ammonia-capable combustors for heavy-duty frames like the 6F.03, 7F, and 9F series. The aim is to:

• Retrofit existing F-class GTs with new burners, fuel systems, and NOx control hardware.
• Use a combination of partial cracking and tailored aerodynamics to keep flames stable while controlling fuel-NOx.
• Demonstrate ammonia firing at scale in commercial plants, including projects on Jurong Island in Singapore where existing natural gas units will be adapted for low-carbon fuels.

For asset owners, this pushes ammonia from an R&D curiosity toward a concrete gas turbine retrofitting pathway.

Siemens Energy: Fuel-Flexible Combustion & Ammonia Blends

Siemens Energy is exploring ammonia both as a direct fuel and as a source of cracked hydrogen for turbines and fuel cells. Public work includes:

• Combustion research on ammonia-hydrogen blends for industrial GTs, building on its large hydrogen-combustion portfolio.
• Concepts where cracked ammonia feeds SGT-class turbines or fuel cells, using GT exhaust heat to drive the cracking step.

The common theme across OEMs is a shift from generic “hydrogen-ready” messaging to specific architectures that treat ammonia as a primary hydrogen carrier with integrated cracking.

System Integration: Using Waste Heat to Pay the Energy Penalty

The main thermodynamic drawback of ammonia as a hydrogen carrier is that cracking consumes energy. If that energy comes from burning extra fuel, overall hydrogen carrier efficiency suffers. Gas turbines mitigate this by using waste heat:

• Placing the cracker in the exhaust gas path (upstream of the HRSG or within it), effectively turning some sensible heat into chemical energy.
• Using recuperative layouts where ammonia is preheated by exhaust, cracked in a high-temperature section, and then cooled to match combustor inlet temperature.
• In advanced chemically recuperated cycles, adjusting the cracking extent such that the exhaust still exits the HRSG at a temperature compatible with steam cycle requirements.

Well-integrated designs show that you can offset most of the cracking energy penalty by reusing heat that would otherwise be vented through the stack. The remaining trade-offs are mainly:

• Extra capital cost (crackers, catalysts, and balance-of-plant).
• Additional pressure losses and potential impacts on HRSG design.
• More complex operability and control, especially during start-up and low-load operation.

Emissions, NOx Control, and Safety

Fuel-Bound NOx and N₂O

Unlike hydrogen or natural gas, ammonia contains nitrogen in the fuel itself. During combustion, that nitrogen can form:

• Fuel-NOx – Generated directly from fuel-nitrogen, often dominating over thermal-NOx at typical GT flame temperatures.
• N₂O (nitrous oxide) – A potent greenhouse gas that can form in fuel-rich or low-temperature regions of the flame.

GT-scale ammonia concepts therefore combine:

• Advanced combustor designs (e.g. rich-lean staging, swirl-stabilized flames, and tailored residence-time fields).
• Optimized ammonia/hydrogen ratios from partial cracking to speed up combustion.
• Back-end SCR systems to remove remaining NOx and limit ammonia slip.

Partial cracking helps: faster, hotter, shorter flames reduce unburned NH₃ and can cut N₂O formation, but detailed design and kinetic modelling are essential.

Safety: Toxic vs Explosive Risk

From a safety standpoint, ammonia and hydrogen present very different hazards:

• Ammonia is toxic and corrosive. It poses inhalation risks (eye and respiratory damage) even at low ppm levels and is corrosive to some materials, especially in the presence of water. Leaks are easily detected by smell but can create hazardous vapour clouds.
• Hydrogen is highly flammable and explosive, with very low ignition energy and wide flammability limits. It can accumulate in enclosed spaces and ignite from minor sources.

Ammonia-to-power plants must therefore implement both:

• Industrial toxic-gas management (ventilation, scrubbers, detectors, emergency response) around storage, piping, and cracking systems.
• Conventional flammable-gas safety (H₂ detection, zoning, purging, and explosion protection) around cracked-gas manifolds and turbine inlets.

A credible design explicitly acknowledges these risks rather than overselling ammonia as inherently safer or simpler than hydrogen.

Design Choices: Direct Firing vs Cracking vs Hybrid

For developers and fleet owners, ammonia-based projects tend to fall into three broad patterns:

Project Checklist: Developing an Ammonia-to-Power GT Project

1. Clarify the role of ammonia in your system. Is it a long-distance hydrogen carrier for a single plant, part of a regional import terminal, or a balancing resource for a renewables cluster?
2. Choose your combustion pathway. Decide early between direct firing, partial cracking, or full cracking based on turbine platform, OEM roadmap, and emissions constraints.
3. Define the cracked-gas specification. Set targets for NH₃ conversion, H₂ fraction, N₂ content, and allowable ammonia slip to the turbine.
4. Select reactor and catalyst technology. For most GT projects today this means a Ni- or Ru-based packed bed reactor, with membrane reactors considered when very high-purity hydrogen or compactness is critical.
5. Integrate with the GT cycle. Place the cracker to maximize use of waste heat while respecting HRSG pinch points, stack temperature limits, and backpressure constraints.
6. Engage the OEM early. Request formal assessment of fuel compatibility, combustor options, NOx mitigation, and inspection intervals. For retrofits, ensure any ammonia concept is consistent with gas turbine retrofitting guidelines and warranties.
7. Update safety studies and operating procedures. Hazard studies must cover ammonia toxicity and hydrogen explosion risks, including abnormal scenarios during start-up, shutdown, and upset conditions.
8. Start with a pilot. Use a limited-scope demonstration (for example one GT, limited operating hours) to validate combustion stability, emissions, and catalyst life before scaling up.

Frequently Asked Questions

Further Reading & References

• U.S. DOE – Potential Roles of Ammonia in a Hydrogen Economy
• Mormino et al. – Ammonia as Effective Hydrogen Storage: A Review on Production, Storage and Utilization
• Mitsubishi Heavy Industries – Hydrogen/Ammonia-Fired Gas Turbine Initiatives for Carbon Neutrality
• Turbomachinery International – Ammonia & Hydrogen Combustion: Major Challenges Ahead
• GE Vernova & IHI – Joint Development of Ammonia-Capable Gas Turbines
• Lamb et al. – Ammonia for Hydrogen Storage; A Review of Catalytic Ammonia Decomposition and Hydrogen Separation
• Peters et al. – Thermocatalytic Ammonia Decomposition: Status and Research Demands
• Lan et al. – Ammonia as Hydrogen Carrier: Advances in Ammonia Decomposition
• Recent Reviews – Reactor Systems for Hydrogen Production via Ammonia Decomposition