Running on Fumes: The Quest for Cleaner Fuels in Micro-Gas Turbines - Part 3

Series: The Micro-Turbine Revolution — Powering the Future, Quietly

Part 3 of 7

“The combustion chamber does not care what you call a fuel. It cares about flame temperature, burning velocity, energy density, and whether what you feed it will behave the same way every time. Nature is under no obligation to make these things convenient.”

The Promise and the Physics

Fuel flexibility is one of the most frequently cited advantages of the micro-gas turbine. Read any manufacturer brochure, any industry white paper, or any conference presentation on MGTs and you will encounter some version of this claim: “Our system can operate on natural gas, biogas, landfill gas, syngas, and hydrogen blends.”

This claim is, broadly speaking, true. It is also, in important ways, incomplete.

A gas turbine combustor is not a passive container that accepts whatever you pour into it. It is a precisely engineered thermodynamic environment in which fuel and air must mix, ignite, and burn in a controlled manner — at specific temperatures, pressures, and velocities — thousands of times per second, continuously, for years on end. The flame must stabilise in the right location. The combustion must be complete enough to minimise carbon monoxide and unburned hydrocarbons. The peak temperatures must be controlled tightly enough to suppress nitrogen oxide formation. And the whole system must respond to load changes, ambient temperature swings, and fuel composition variations without extinguishing, without flashback, and without accelerating wear on the hardware.

Doing all of this with a single, well-characterised fuel — pipeline-quality natural gas with a consistent methane content of 90–95% — is difficult enough. Doing it with fuels whose composition varies from site to site, season to season, and even hour to hour is a genuinely hard engineering problem. And doing it with fuels like hydrogen and ammonia, whose combustion chemistry is fundamentally different from hydrocarbons, pushes the boundaries of what current combustor designs can reliably deliver.

This post is an honest examination of that challenge. Not to dismiss the fuel flexibility argument — it is real and it matters enormously for the technology's future — but to understand what “flexibility” actually costs in engineering terms, and what the frontier of research is trying to solve.

Why Fuel Matters More at Micro-Scale

Before examining specific fuels, it is worth understanding why fuel flexibility is simultaneously more important and more challenging for micro-gas turbines than for their larger industrial cousins.

It is more important because of where MGTs are deployed. The applications that most benefit from MGTs — remote power, distributed generation, waste-to-energy, off-grid communities — are precisely the applications where pipeline-quality natural gas is unavailable or unreliable. A 5 MW industrial gas turbine at a utility plant sits on a high-pressure transmission pipeline with consistent, well-characterised gas. A 100 kW MGT at a landfill, a wastewater treatment plant, a remote mine, or a biogas digester in rural Tanzania is dealing with whatever the local resource provides.

It is more challenging because of the physics of scale. Micro-gas turbine combustors are small — combustion chamber volumes in the range of 0.5 to 5 litres, compared to hundreds of litres in a large industrial machine. At small scales, the ratio of combustor wall surface area to combustion volume increases, meaning more heat is lost to the walls. Residence times — the time fuel and air spend in the combustion zone — are shorter, leaving less time for complete combustion. The tolerances on flame position, fuel-air ratio, and temperature distribution are tighter. Small changes in fuel composition that a large turbine combustor would absorb without difficulty can cause significant performance or emissions changes in a micro-scale system.

This is the central tension of MGT fuel flexibility: the applications that need it most are the ones where the engineering challenges are greatest.

Natural Gas: The Baseline and Its Limitations

Natural gas is the reference fuel for which most commercial MGTs are designed and optimised. It is predominantly methane (CH₄) — typically 85–95% by volume in pipeline gas — with small amounts of ethane, propane, and inert gases. Its combustion properties are well understood, its energy content is consistent, and decades of engineering refinement have produced combustors that can burn it efficiently and cleanly.

Even natural gas, however, presents challenges at the micro-scale. The Wobbe Index — a measure of the interchangeable energy content of gases, accounting for both heating value and density — must fall within a specific range for a given combustor design. Natural gas from different sources (North Sea gas, Gulf gas, liquefied natural gas re-gasified from different origins) can vary enough in composition to shift combustion behaviour noticeably.

More fundamentally: natural gas is a fossil fuel. Its combustion produces CO₂. In a net-zero energy system, burning natural gas — however cleanly and efficiently — is a transitional strategy, not an endpoint. The future of the micro-gas turbine, if it has one, must involve a transition to fuels with lower lifecycle carbon intensity. Which brings us to the alternatives.

Biogas: The Most Accessible Alternative — and Its Complications

Biogas is produced by the anaerobic digestion of organic matter — food waste, agricultural residues, sewage sludge, animal manure, energy crops. It is also produced by the natural decomposition of organic waste in landfills (where it is called landfill gas). The primary energy component is methane, but unlike pipeline natural gas, biogas is a mixture: typically 50–70% methane, 30–45% carbon dioxide, with trace amounts of hydrogen sulphide (H₂S), water vapour, siloxanes (from digested waste containing personal care products), ammonia, and other contaminants depending on the feedstock.

Biogas has several compelling characteristics as an MGT fuel. Its carbon is biogenic — it comes from organic matter that recently captured CO₂ from the atmosphere — meaning its combustion is considered carbon-neutral or even carbon-negative when it displaces fossil fuels or prevents methane from being released directly to the atmosphere. A tonne of methane released to the atmosphere has approximately 80 times the short-term global warming impact of a tonne of CO₂. Capturing and burning biogas that would otherwise vent or flare is one of the highest-value climate interventions available.

Biogas is also locally available at a wide range of sites — landfills, wastewater treatment plants, agricultural operations, food processing facilities, and increasingly purpose-built anaerobic digestion plants. Running an MGT on biogas at these sites turns a waste management challenge into a revenue-generating asset.

The engineering complications, however, are significant.

Lower and variable methane content. Biogas with 55% methane has a heating value roughly half that of natural gas. The combustor must handle this lower energy density and, crucially, must handle variations in that content — landfill gas in particular can shift from 45% to 65% methane over the course of days or weeks depending on waste composition, moisture, and temperature. MGT control systems must adjust fuel flow rates and combustor operating points continuously to maintain stable, efficient combustion across this range.

Hydrogen sulphide contamination. H₂S is corrosive to metals and combustion equipment, and its combustion produces sulphur dioxide (SO₂), itself a regulated pollutant. Biogas fed to an MGT typically requires desulphurisation — either through chemical scrubbing or biological treatment — to reduce H₂S to acceptable levels. This adds capital cost and operational complexity to the fuel conditioning train.

Siloxanes. Digested municipal waste and landfill gas frequently contain siloxane compounds — organosilicone molecules used in cosmetics, detergents, and personal care products. When siloxanes combust, they produce silicon dioxide (SiO₂) — in effect, microscopic glass particles — which deposit on turbine blades and combustor walls, causing abrasion and accelerating wear. Siloxane removal from biogas before combustion is essential but expensive and technically demanding.

Moisture content. Raw biogas is saturated with water vapour at production temperatures. Free water in the fuel stream is highly damaging to combustion equipment and must be removed through condensation and drying upstream of the MGT.

Pressure consistency. Biogas from landfills and digesters is typically available at low pressure — often only a few millibar above atmospheric. MGT fuel systems require fuel delivered at specific pressures; a gas compression system adds energy consumption and capital cost.

Despite these complications, biogas-fuelled MGT installations are among the most commercially successful deployments of the technology. When the fuel conditioning challenges are properly engineered and the economics of displacing both grid electricity and biogas flaring are accounted for, the business case is strong. Several hundred MGT installations worldwide run on biogas or landfill gas, with demonstrated operational track records of tens of thousands of hours.

Syngas: Promise from Waste — and the Tar Problem

Syngas — synthesis gas — is a mixture of hydrogen and carbon monoxide produced by the gasification or partial oxidation of carbonaceous materials: coal, biomass, municipal solid waste, agricultural residues, industrial waste streams. At its cleanest, syngas from biomass gasification has a composition of roughly 20–30% hydrogen, 20–30% carbon monoxide, 10–15% carbon dioxide, and 2–5% methane, with the balance being nitrogen if air-blown gasification is used.

Syngas is thermodynamically interesting as an MGT fuel. Its hydrogen content gives it a high burning velocity — it ignites and burns faster than methane — which is an advantage for combustion stability in short-residence-time micro-scale combustors. Its energy content, however, is substantially lower than natural gas (typically 4–7 MJ/m³ compared to 34–38 MJ/m³ for natural gas), requiring much higher volumetric flow rates to deliver equivalent power — which has implications for fuel valves, piping, and the combustor itself.

The most significant barrier to syngas use in MGTs is not the combustion chemistry but the upstream fuel conditioning challenge: tar.

Raw syngas from biomass gasification contains tars — complex organic compounds produced by the incomplete thermal conversion of the biomass. These tars are sticky, high-boiling-point hydrocarbons that condense on cool surfaces downstream of the gasifier, fouling pipes, valves, and — fatally for the MGT — the fuel injection system and combustor inlet. Tar content in raw gasifier syngas can range from 1 to 100 grams per normal cubic metre, compared to acceptable limits for MGT combustors of approximately 0.01–0.1 grams per normal cubic metre. The gap between what comes out of a gasifier and what an MGT combustor can accept is two to three orders of magnitude.

Tar removal — through hot gas filtration, thermal cracking (reforming), or wet scrubbing — is the central unsolved challenge of biomass gasification for power generation at small scales. It is technically achievable; research systems have demonstrated adequate tar removal. But doing so robustly, cost-effectively, and with the reliability required for commercial operation has proven elusive.

The consequence is that syngas-fuelled MGT systems are far less commercially mature than biogas systems. A handful of demonstration projects have operated for meaningful periods, but there is no large-scale commercial syngas MGT deployment comparable to the biogas installed base. This is an area where the technology is genuinely not yet ready — not because the MGT itself cannot handle syngas, but because the gasifier-plus-cleanup system upstream of the MGT has not reached commercial maturity at small scales.

The opportunity, however, is enormous. Municipal solid waste gasification feeding an MGT would represent a triple benefit: waste diversion from landfill, low-carbon power generation, and elimination of the need for an expensive combustion facility. We will return to this vision in Part 5.

Hydrogen: The Fuel of the Future, the Combustor's Nightmare

Of all the alternative fuels discussed in this post, hydrogen attracts the most attention, the most investment, and the most fundamental engineering challenges. It is worth treating in some depth.

Hydrogen (H₂) is the ultimate clean fuel — its combustion produces only water vapour, with no CO₂, no particulates, and — if combustion temperatures are managed correctly — very low NOx. In a world powered by green hydrogen produced through electrolysis using renewable electricity, the gas turbine becomes a genuinely zero-carbon dispatchable power source. For a technology sector under existential pressure from intermittent renewables, this is an existential lifeline.

But hydrogen is, in important ways, the most combustion-challenging fuel that a gas turbine will ever be asked to burn. Understanding why requires a brief excursion into combustion physics.

Burning velocity. Hydrogen's laminar burning velocity — the speed at which a flame front propagates through a fuel-air mixture — is approximately 2.5–3 metres per second under typical combustion conditions. Methane's burning velocity is approximately 0.35 metres per second. Hydrogen burns nearly eight times faster than methane.

This has a critical implication: flashback. In a gas turbine combustor, fuel and air are mixed and then the mixture is ignited in a combustion zone maintained downstream of the fuel injection point. The flame is held in position by the balance between the incoming flow velocity (which pushes the flame downstream) and the burning velocity (which drives it upstream). If the burning velocity exceeds the flow velocity — which hydrogen's dramatically higher burning velocity makes far more likely, especially at partial load — the flame travels back upstream into the mixing zone and the fuel injector, causing immediate hardware damage and potentially catastrophic failure.

Flashback is the defining safety and durability challenge of hydrogen combustion in gas turbines. Large industrial turbine manufacturers (GE, Siemens, Mitsubishi) have been working on this problem for over a decade and have developed combustor designs capable of burning 30–50% hydrogen blends (by volume) reliably. Full 100% hydrogen combustion in a standard lean pre-mixed combustor remains a research challenge for large turbines, and the problem is more acute at micro-scale.

NOx formation. The other major challenge of hydrogen combustion is NOx. Hydrogen's high burning velocity and high adiabatic flame temperature — the theoretical peak temperature achievable if all the heat of combustion is retained in the products — means that hydrogen flames in air are extremely hot. At these temperatures, the Zeldovich mechanism for thermal NOx formation is highly active. A combustor optimised for low-NOx combustion of methane, relying on lean pre-mixing to keep temperatures below the NOx formation threshold, does not necessarily achieve the same low-NOx performance with hydrogen, because the higher burning velocity changes the flame structure and temperature distribution.

Achieving low-NOx hydrogen combustion requires either very lean hydrogen-air mixtures (with attendant stability challenges), staged combustion designs, exhaust gas recirculation, or catalytic combustion approaches — all of which add complexity, particularly at micro-scale.

Current State of MGT Hydrogen Operation. Most commercial MGTs can today operate on natural gas blended with up to 10–20% hydrogen by volume without combustor modifications. Some advanced systems have demonstrated operation on blends up to 30–50% hydrogen with modified combustors. True 100% hydrogen operation in a commercial MGT product is not yet available from any manufacturer, though several research programmes are actively pursuing it.

The roadmap for hydrogen in MGTs likely runs through: low-blend operation today (10–20% H₂, achievable with software and minor hardware adjustments), medium-blend operation in the near term (30–50% H₂, requiring modified combustors available as upgrade kits), and high-blend or pure hydrogen operation in the medium term (requiring purpose-designed combustors, likely catalytic or staged-combustion architectures).

Ammonia: The Dark Horse

Ammonia (NH₃) has emerged as a serious candidate for long-distance energy transport and power generation. Unlike hydrogen, it is liquid at moderate pressures at room temperature, making storage and transport far more practical. It can be produced from green hydrogen and atmospheric nitrogen, with no carbon in the molecule and therefore zero CO₂ from combustion.

Ammonia's combustion properties are, however, extraordinarily challenging. It has a very low burning velocity (approximately 0.07 metres per second — five times slower than methane and forty times slower than hydrogen), very narrow flammability limits, and a high ignition temperature. Flames are difficult to stabilise, combustion efficiency is poor at lower temperatures, and unburned ammonia in the exhaust is itself a toxic pollutant.

Ammonia also contains nitrogen — and burning nitrogen-rich fuel in oxygen produces fuel NOx in addition to thermal NOx, making low-NOx combustion design far more difficult.

The current state of ammonia combustion in gas turbines is firmly in the research and early demonstration phase. Small turbines in Japan and South Korea have demonstrated ammonia combustion in blends with hydrogen or methane, but no commercial product is available. For micro-gas turbines, ammonia is a long-term research avenue rather than a near-term fuel option.

The Wobbe Index and the Engineer's Dilemma

Underlying all of these fuel discussions is a fundamental constraint: the Wobbe Index. This dimensionless number, defined as the higher heating value of a gas divided by the square root of its specific gravity relative to air, captures the interchangeable energy delivery of gases at a given supply pressure and nozzle size. For a given combustor and fuel injection system, gases with similar Wobbe indices can be substituted without recalibration; gases with significantly different Wobbe indices will deliver different amounts of energy per unit time and may push combustion outside stable operating limits.

Natural gas has a Wobbe Index of approximately 50–55 MJ/m³. Hydrogen has a Wobbe Index of approximately 48 MJ/m³ — deceptively close to natural gas, which might suggest easy substitution. But the Wobbe Index is not a complete description of combustion behaviour; it captures energy delivery but not burning velocity, flame temperature, or emission formation kinetics. Two gases can have similar Wobbe indices and profoundly different combustion characteristics — as hydrogen and methane illustrate perfectly.

The engineer's dilemma is this: designing a combustor that can handle a wide range of fuels with very different Wobbe indices, burning velocities, and emission formation characteristics simultaneously — while maintaining high efficiency, low emissions, and long hardware life — is not a matter of incremental optimisation. It is a fundamentally multi-variable design problem with no clean solution. Every decision that improves performance with one fuel compromises it with another.

The most advanced MGT combustor designs address this through active control — real-time monitoring of combustion dynamics (using pressure sensors or optical diagnostics), combined with continuous adjustment of fuel flow, air staging, and pilot fuel injection to maintain optimal operation as fuel composition shifts. This closed-loop combustion control is one of the most important areas of active development in the field, and it is where significant progress is being made.

What the Research Frontier Looks Like

Beyond the immediate commercial challenge of biogas and early hydrogen blending, the research community is pursuing several directions that could significantly expand MGT fuel flexibility over the next decade:

Catalytic combustion. Rather than flame combustion, catalytic combustors use a catalyst surface to oxidise fuel at lower temperatures, below the NOx formation threshold, and with much higher stability across a range of fuel compositions. Catalytic combustors have demonstrated extremely low emissions and high fuel flexibility in research settings, but catalyst durability at the temperatures and pressures found in MGT combustors has historically been the limiting factor. Advances in catalyst materials — particularly palladium-based and mixed-oxide catalysts — are improving this picture.

Flameless oxidation (FLOX / MILD combustion). In this regime, fuel and air are diluted with hot recirculated combustion products to the point where the mixture temperature is above the autoignition point but below the temperature at which luminous flames form. The result is distributed, low-temperature combustion with extremely uniform temperature profiles and very low NOx. FLOX combustion has been demonstrated in micro-scale combustors with excellent results, but stabilising it robustly across the operating range of an MGT — from startup to full load — requires careful engineering.

Plasma-assisted ignition and stabilisation. Non-thermal plasma can extend the flammability limits of difficult fuels, accelerating fuel oxidation chemistry and enabling stable combustion of lean mixtures that would otherwise extinguish. Research groups in the US, Europe, and Japan are exploring plasma-assisted combustion for hydrogen and ammonia, with promising early results.

Digital fuel composition sensing. One of the key enablers of practical multi-fuel operation is knowing, in real time, what fuel is arriving at the combustor. Laser-based gas composition analysers, inferential calorific value sensors, and Wobbe index meters are becoming smaller and less expensive, opening the possibility of truly adaptive combustion control systems that can respond autonomously to fuel composition changes.

The Pathway Forward

The honest assessment of cleaner fuels in micro-gas turbines is this: biogas is ready now, with appropriate fuel conditioning. Natural gas with hydrogen blends up to 20% is ready now. Higher hydrogen blends are achievable with modified hardware and will be commercially available within the next few years. Pure hydrogen operation requires combustor architectures that are in development but not yet commercially proven at micro-scale. Syngas requires upstream tar removal technology that is still maturing. Ammonia remains a long-term research option.

This is not a narrative of frustration — it is a narrative of a technology climbing a well-defined development curve. The gap between what is commercially available today and what the climate requires is real, but the direction is clear and the pace of progress is accelerating under the pressure of global decarbonisation commitments.

The micro-gas turbine that is installed today on natural gas, running cleanly and efficiently, is not a stranded asset when the energy transition arrives. It is a platform — ready to accept progressively cleaner fuels as those fuels and their delivery infrastructure develop. That upgrade pathway is one of the technology's most underappreciated strategic attributes.

But the journey from platform to fully decarbonised distributed power source requires solving combustion chemistry problems that have occupied some of the best engineers in the world for decades. The solutions are emerging. They are not yet complete.

Key Takeaways from Part 3

• Fuel flexibility in MGTs is real but requires serious engineering — small combustors are more sensitive to fuel composition variation than large industrial turbines.
• Biogas is the most commercially mature alternative fuel for MGTs, but requires upstream conditioning to remove H₂S, siloxanes, moisture, and to stabilise methane content.
• Syngas from gasification has enormous potential but is blocked by the tar removal challenge — a problem that is technically soluble but not yet commercially proven at small scale.
• Hydrogen combustion faces fundamental challenges: flashback risk (8× higher burning velocity than methane) and elevated NOx formation at high flame temperatures. Commercial MGTs can handle 10–20% hydrogen blends today; higher blends require modified combustors in active development.
• Ammonia is a long-term research direction with severe combustion challenges; it is not a near-term MGT fuel option.
• Active combustion control, catalytic combustion, and FLOX/MILD combustion are the most promising research pathways to robust multi-fuel operation.
• MGTs installed on natural gas today can be upgraded to accept cleaner fuels as those fuels mature — making them transition assets, not stranded ones.