How Hydrogen-Compatible Combustors Reduce Emissions

Hydrogen is no longer a distant decarbonization concept for the power generation industry. It’s an active engineering challenge that operators managing industrial gas turbines must plan for now—in procurement decisions, permit applications, and long-term service strategies.

The core question for most operators isn’t whether hydrogen will play a role in their fuel mix. It’s whether their existing combustion hardware can support hydrogen blending without trading NOx compliance for carbon reduction.

The answer depends heavily on combustor design. And the good news for operators running B/E-class and F-class gas turbines is that hydrogen-compatible, low-emissions combustion retrofit options exist today—proven in the field, not just in the laboratory.

Why Hydrogen Creates a NOx Challenge

Hydrogen is earmarked as a possible fuel to displace natural gas and provide CO₂-free combustion in gas turbines. A long-term goal is to burn 100% green hydrogen in gas turbines, replacing natural gas. In the short term, hydrogen can be blended with natural gas to reduce CO₂ emissions partially.

The problem is thermodynamic. Hydrogen burns significantly hotter and faster than natural gas. Its adiabatic flame temperature is approximately 2,318- 2,400 K, compared to roughly 2,230 K for natural gas. That high adiabatic flame temperature increases NOx emissions and thermal stress, promoting thermal NOx formation via the Zeldovich mechanism and raising combustor wall temperatures.

In practical terms: a combustor tuned for natural gas that suddenly receives a 30% hydrogen blend will see flame temperatures rise, NOx spike, and combustion dynamics shift in ways that can damage hardware, trigger permit violations, and force operators to derate output to stay compliant.

While diffusion combustors can currently burn hydrogen more effectively, the gas turbine industry recognizes that lean premixed combustors with superior emissions control will remain the dominant combustion system for new designs, even with hydrogen. The challenge is designing lean premixed systems that maintain stability and low NOx as hydrogen content increases.

The Two Main Approaches

Wet Low-Emissions: Effective but Operationally Costly
The earliest hydrogen-capable combustion systems used water or steam injection to suppress the elevated flame temperatures hydrogen produces; existing combustors rated up to 100% hydrogen use a diluent like water to manage emissions. Water injection can keep NOx in range but comes with high operational costs: demineralized water consumption, treatment infrastructure, geographic and seasonal limitations, and efficiency penalties from dilution.

For operators who need hydrogen capability today and can manage the water logistics, wet systems are a proven path. For operators who want to avoid the infrastructure burden and operational complexity, dry alternatives are the right direction.

Dry Low-Emissions with Hydrogen Staging: The Preferred Path

Modern dry low-emissions (DLE) combustors control NOx through lean premixed combustion, mixing fuel and air upstream of the flame zone to achieve uniform, lower-temperature combustion. The engineering challenge with hydrogen is that lean premixed systems designed for natural gas can experience flashback, combustion instability, and NOx penalties as hydrogen content rises.

The solution lies in advanced fuel staging, micromixer designs, and axial fuel injection architectures that maintain flame stability and uniform mixing across a range of hydrogen-natural gas blend ratios.

General Electric has over 30 years of experience with turbines operating on hydrogen-containing fuels, including combustor designs that can blend up to 50% hydrogen with natural gas while maintaining NOx emissions below 10 ppm. Research confirms the trajectory: a 65% hydrogen blend can reduce NOx emissions to as little as 1 ppm, providing a cost-effective alternative to current NOx and CO₂ control technologies.

Siemens engines can handle approximately 30-60% hydrogen in the gas turbine fuel, with industrial gas turbines capable of handling up to 60% hydrogen. The industry consensus, confirmed by multiple independent research programs, is that with appropriate R&D investment, NOx emissions from hydrogen-fueled gas turbines can be controlled to levels similar to those produced by state-of-the-art natural gas-fueled combustion turbines.

What “Hydrogen-Compatible” Actually Means for B/E-Class Operators

For operators running Frame 6B, 7E, 7EA, and 9E turbines, hydrogen compatibility isn’t a single threshold. It’s a spectrum defined by:

Blend percentage: Most current DLE retrofits for B/E-class frames support hydrogen blends in the 20-30% range by volume without hardware changes beyond combustion tuning. Higher blend ratios require combustor design modifications and control system updates.

NOx performance at blend ratio: A combustor that achieves 5 ppm NOx on natural gas may produce 15-20 ppm at a 30% hydrogen blend without tuning optimization. Understanding the NOx-versus-blend-ratio curve for your specific hardware is essential for permit planning.

Flashback margin: As hydrogen content rises, the risk of the flame propagating upstream into the premixer increases. Combustor designs with adequate flashback margin at target blend ratios are a non-negotiable specification requirement.

Turndown stability: Hydrogen-blended combustion can narrow the stable operating range, reducing turndown capability at low loads. Operators who need flexible dispatch across a wide load range must verify that hydrogen blend performance holds across the full operating envelope, not just at baseload.

Hanwha Power’s LEC NextGen: Designed for Fuel Flexibility

Hanwha Power’s LEC NextGen combustion system, the next evolution of the proven LEC III™ platform, was developed specifically to address these requirements for 7EA, 7E, 6B, and 9E frames. LEC NextGen delivers sub-9 ppm NOx on natural gas, with hardware and control architecture designed for hydrogen blending as fuel supply infrastructure develops.

The practical implication for operators: LEC NextGen provides a retrofit path that solves the immediate NOx compliance challenge while building in the fuel flexibility to transition to hydrogen blends without another combustor replacement. One investment, two problems solved.

For F-class operators, Hanwha Power’s FlameSheet™ combustion technology delivers equivalent fuel-flexibility benefits, with stable operation on natural gas, LNG, and hydrogen blends alongside single-digit NOx performance.

Planning for Hydrogen Now, Even If Your Timeline Is Later

Most operators aren’t burning hydrogen today. Pipeline infrastructure is limited, green hydrogen production costs remain elevated, and blending mandates vary significantly by jurisdiction. But the permit applications, equipment procurement decisions, and service agreements being signed today will govern operations through 2035 and beyond.

NOx emissions from gas turbines burning up to 100% hydrogen are a key consideration. As OEMs increase hydrogen-to-natural-gas ratios, they are targeting maintaining NOx emissions comparable to their advanced combustor designs. The combustion hardware decisions operators make during autumn 2026 outages will determine whether their units are positioned to take advantage of hydrogen infrastructure as it develops, or locked into a second retrofit cycle when blending requirements arrive.

The right time to specify hydrogen-compatible combustion hardware is when you’re already opening the turbine for an inspection or major component replacement. The incremental cost of specifying hydrogen-capable hardware during a planned combustion outage is a fraction of what a dedicated retrofit costs when hydrogen supply becomes available, and operators are scrambling to comply.

Autumn outage season is that window.

The Bottom Line

Hydrogen-compatible combustors solve two problems simultaneously: they cut NOx to levels that satisfy the most stringent current air quality requirements, and they position existing gas turbines to accept hydrogen blends as fuel supply and regulatory frameworks evolve. For operators managing B/E-class and F-class fleets, that combination of immediate compliance value and future fuel flexibility is the strongest case for combustion retrofit investment available today.

Evaluating hydrogen-compatible combustion retrofits for your fleet? Hanwha Power's engineering team provides combustion retrofit assessments, permit compliance analysis, and hydrogen blending compatibility evaluations for Frame 7EA, Frame 6B, and other B/E-class and F-class turbines. Contact us to discuss your emissions targets and fuel flexibility requirements.

Attending the 2027 PSM Asset Managers Conference? Hydrogen combustion technology, fuel flexibility, and decarbonization strategies will be among the topics on the agenda as the industry navigates the next phase of the energy transition. Register here to secure your spot.

References:

• Turbomachinery Magazine, "The Future of Hydrogen as a Gas Turbine Fuel," July 2026
• Clean Air Task Force (CATF), "Emissions and Performance Implications of Hydrogen Fuel in Heavy Duty Gas Turbines," July 2023
• U.S. DOE / NETL, "A Literature Review of NOx Emissions in Current and Future State-of-the-Art Hydrogen Gas Turbines," 2024
• ScienceDirect, "Hydrogen-Natural Gas Blending for Enhanced Performance of the MS-5002C Gas Turbine," 2025
• Power Engineering, "GE Vernova Validates 100% Hydrogen-Fueled DLN Combustor Technology," 2024
• Energies (MDPI), "Research Status and Technical Progress of Hydrogen-Fueled Gas Turbine," March 2025
• Hanwha Power, LEC III and LEC NextGen Product Documentation, psm.com