Batteries, Coal, Gas

Fuels, Combustion & Environmental Considerations in Industrial Gas Turbines

Issue 5 and Volume 118.

By Brian Igoe and Michael Welch, Siemens Industrial Turbomachinery Ltd

For economic and environmental reasons, it is important that gas turbines used in both industrial power generation and also oil & gas applications can burn a wide variety of fuels, with minimum impact on the environment.

This article will examine the types of gaseous and liquid fuels that can be considered for use in industrial gas turbines, discuss the basic types of combustion system employed such as ‘conventional’ and ‘Dry Low Emissions’. The flexibility of these systems to accept different types of fuel given due consideration to fuel quality and composition will be included along with methods employed to review and assess fuels. Common contaminants found in fuels and the impact these have on the operability and maintenance of an industrial gas turbine will also be covered. Understanding gaseous fuel composition and the impact on the combustion process will be presented along with the resultant emissions to atmosphere and pollution abatement methods available and applied to limit the impact on the environment.

Gas Turbine Fuel and Emission

Ensuring fuel is provided and maintained at a high quality is key to delivering good operation in a modern gas turbine over long periods of time. However, it is not just fuel that is critical, it is also ensuring all fluids entering the GT are equally kept at a high standard, thus minimizing or eliminating all sources of contaminants.

Modern gas turbines operate at high temperatures, and use component designs and materials at the forefront of technology, but these are more susceptible to damage if contaminated fuel and air enter the GT through poor operating procedures. This article will consider the need to ensure good quality fluids enter the GT and review combustion technology which has moved forwards in achieving low emissions without resorting to wet abatement methods. Both conventional and low emissions technologies are discussed along with basic operating parameters associated with the fuels in question.

The fuel range used in GT applications is very wide with the choice based typically on availability and cost. In some cases fuels may have little or no treatment, in others they may have “added value” which results in the high quality pipeline natural gas that provides the fuel of choice for gas turbine OEMs and operators alike. Gas turbines can and do operate on a wide range of fuels, but the impact that such fuels may have on turbine life has to be recognised.

It is not a case of saying these fuels are acceptable, but understanding the details, such as the composition [hydrocarbon species in the case of a gaseous fuel, inert species, contaminants, water vapour, …]. Detailed analysis of the fuels is necessary to determine key parameters of the fluid, such as delivery, storage and conditioning as well as key features of the fuel itself, including Lower Heating Value (LHV), Wobbe Index, dew point and density. Understanding all of these provides the OEM and users alike with indicators that the fuel entering the GT is suitable and can result in good operation across a wide range of loads and ambient conditions. It is also important to determine and understand the products of combustion and impact on the environment. Exhaust emissions are highly regulated in many parts of the world and even those areas that up until recently had no requirements have started to introduce standards or guidelines which need to be noted during the application assessment stage.

Types of Combustion Emissions Regulated

The U.S. Clean Air Act and the European Union (EU) Combustion Plant Directive are examples where limits on the worst polluting species from gas turbine plants are regulated. Consequently, low emissions became the norm and not the exception, especially for pollutants such as nitrogen oxide (NOx), carbon monoxide (CO) and un-burnt hydrocarbons (UHC).

In addition, the major gas turbine OEMs, along with a large number of oil & gas companies, have their own policies with regard to environmental stewardship and offer or specify low emission equipment even in locations where no formal legislation exists, or is set at a higher level.

The result of all of these drivers is to make the Dry Low Emissions or Dry Low NOx (DLE/DLN) combustion system the primary combustion system of choice. In some cases DLE/DLN is the only combustion system offered, especially on newer models.

Available Combustion Systems

Two types of combustion systems are widely used in gas turbines: one based on the “conventional” diffusion flame; the second typically uses lean pre-mix technology targeting low exhaust emissions signature. These are offered in both annular and can-annular arrangements.

Conventional Combustion

Conventional combustion (Figure 1), also referred to as diffusion flame combustion, operates at high primary zone temperatures, circa 2500K, resulting in high thermal NOx formation. Lowering the flame temperature, and hence NOx production, can be achieved by injection of diluents such as water or steam into the primary zone, which quench the flame and has been successfully employed for many years by many of the gas turbine manufacturers. Different OEMs use differing methods for water or steam injection, but all recognize the impact each has on reliability and life cycle costs. Generally such combustion systems have been more tolerant to different fuel types.

Conventional Combustion
Conventional combustion
Conventional combustion operates at high primary zone temperatures, causing high thermal NOx formation

Reducing exhaust emissions by injecting water or steam into the primary zone is compared to the benefits of DLE/DLN solution (Figure 2). Wet injection needs a large quantity of de-mineralized water and there is an impact on the service regime, with more frequent planned interventions. The ratio of water, or steam, to fuel (WFR or SFR) used results in lower NOx, but can impact CO emissions in a detrimental manner. Completion of a retrofit of existing gas turbines was made to include DLE combustion achieving a notable environmental benefit, offering almost a 5 times reduction in NOx emissions compared to previous abatement system employed (Figure 3).

fig 2
fig 3

Dry Low Emissions Combustion Systems

Lowering primary zone temperatures without resorting to wet diluents is now achieved using lean pre-mix combustion. Dry Low Emissions (DLE) or Dry Low NOx (DLN) combustion systems address the production of NOx at source with a design that does not rely on injected diluents, hence the term “dry”. Of all of the promising technologies: Lean-premixed pre-vaporised combustion; Staged Combustion; Catalytic Combustion; Rich-burn lean quench combustion; lean pre-mixing is the most dominant. Lean premixed system, which reduces the production of NOx by reduction of the reaction temperature, is the one that has been developed by a number of gas turbine OEMs as the combustion system of choice with many millions of operating hours now recorded.

NOx formation increases exponentially with temperature, therefore it is critical to ensure air and fuel is well mixed. Lower NOx has been achieved by combusting the fuel in an excess of air, hence “lean” pre-mix combustion. During the early design and development work, there was much attention devoted to achieving a homogeneous mixture, and burning this mixture without detrimental impact on combustion and turbine hardware. One lean pre-mix combustor design comprises four main features: Fuel/air injection device; stability device; pre-mixing zone; flame stabilization zone.

Meeting emissions requirements is only one aspect of combustion design. It has also to meet operational criteria, including: component life; flexible fuel operation; reliable starting; reliable switching between fuels; reliable transient response; and all without excessive cost.

Methods of reducing NOx Emissions

There are three main ways for NOx formation

  • thermal NOx
  • prompt NOx
  • fuel bound NOx (FBN)

Thermal NOx is by far the most dominant source of NOx and is produced by the reaction between nitrogen and oxygen in the air as described by Zeldovich. This reaction takes place above 1700K and the rate increases exponentially as temperature increases (Figure 4). Prompt NOx is produced by the high-speed reactions at the flame front, whilst FBN can only be influenced by removal of nitrogen bearing compounds in the fuel.

fig 4

DLE Design

DLE Combustion System Design 2000
DLE Combustion System Design 2000
DLE combustion arrangements tend to be can-annular or annular combustion configuration.

DLE combustion arrangements tend to be either can-annular as shown in Figure 5 or annular combustion configuration (Figure 6). In this latter configuration a single combustion chamber is mounted around the outside of the compressor exit section of the gas turbine, with multiple burners mounted through engine casings through holes in the combustor.

Annular Combustor with 3rd Generation DLE Burner
Annular Combustor with 3rd Generation DLE Burner

Diffusion Flame Comparisons with DLE Combustion Systems

In order to produce low NOx and low CO the homogeneous flame temperature within the combustor must be controlled between strict limits. Conventional diffusion flame combustor has a high primary zone temperature due to high turbulence regions promoting mixing and result in temperatures in excess of 2500K. In order to reduce NOx levels either the temperature within the combustor has to be lowered or the NOx must be removed after the turbine. Improvements in mixing the fuel and air to achieve a homogeneous mixture whilst at the same time ‘leaning out’ the mixture within the DLE combustor, achieves the desired effect of a more uniform and lower peak combustor temperature, thus resulting in low thermal NOx production.

Dry Low Emissions Combustion

The design approach by one OEM is shown in Figure 7, highlighting the use of scaled combustion geometry across the product portfolio and use of can-annular combustion hardware.

Component Failure
Component Failure
Scaled hardware design across the product portfolio and use of can-annular combustion hardware.

A common design approach was adopted where scaling and adjustments for air flow have been applied depending on the rating and combustor numbers used in the GT model. The combustor comprises a number of sections (Figure 5):

  • Fuel injection device or the pilot burner – houses the pilot fuel galleries and injectors for both gaseous and liquid fuel
  • Main fuel injection device – the main burner – houses the main air swirler and main gas and liquid fuel systems
  • The combustor – the flame mixing and stability device – which includes a narrow inlet feature, called the pre-chamber; is of double skin construction with impingement cooling, this air exhausting into the combustor through dilution holes downstream of the main reaction zone.

A transition duct, located downstream of the combustor, conditions the flow from the circular combustor exit to a sector of the turbine entry annulus.

In this DLE design main combustion air enters through a single radial swirler at the head of the combustor. Flow turns through 90 degrees into the pre-chamber followed by a sudden expansion into the combustion chamber. The swirl number is sufficiently high to induce a vortex breakdown reverse flow zone along the axis. This is termed the internal reverse flow zone. In this design concept the reverse flow zone remains attached to the back surface of the combustor thereby establishing a firm aerodynamic base for flame stabilization. In the wake of the sudden expansion, an external reverse flow zone occurs with flame stabilization in the shear layers around the internal and external reverse flow zones.

Gaseous and liquid fuels are introduced, in two stages:

  • Main, which results in a high degree of ‘premixedness’ and hence low NOx emissions
  • Pilot, which is reduced as the load demand increases and ensures flame stability

The pilot is arranged such that as the pilot fuel split increases, the fuel is biased towards the axis of the combustor.

Describing each element of the DLE system in more detail and referring to Figures 5 shown earlier:

Pilot Burner

Provide fuel for ignition and transient operation, with a small percentage used at full load for stability purposes. An ignition source is mounted in each pilot burner, along with a thermocouple to monitor the temperature of the face of the burner. For dual fuel units, a separate liquid fuel lance, located and accessed through the rear of the burner, provides fuel for ignition and transient operation.

Main Burner

Fuel flow increases as speed and then load is increased. This provides the pre-mixing via the radial swirler and numerous gas injection ports. The swirlers are fixed design with control of fuel necessary to achieve both load and ambient temperature control.

Liquid Core

Located with main swirler/burner when a dual fuel arrangement is required, otherwise a blank ring is used. Diesel is injected through a number of equally spaced nozzles resulting in good pre-mixing with high velocity and achieving good liquid fuel emissions characteristics.

Combustion Liner

Main swirler/burner is mounted at the head of the combustor, which comprises a double skin liner, the outer skin controlling the cooling air feeding the annulus between inner and outer liner. The head of the combustor locates the pre-chamber where the fuel is mixed prior to ignition.

Transition Duct

Controls and directs the hot combustion gases towards the first stage nozzle and typically includes effusion cooling.


Conventional materials typically used in this part of the gas turbine. Burners are routinely made from stainless steel, with the application of a thermal barrier coating in key areas. Combustion chambers are manufactured from Nimonic steels with thermal barrier coatings applied to the inner liner surface.

Gas Turbine Fuels and Fuel Quality

Modern highly efficient gas turbines rely on high-quality alloys allowing increased firing temperatures to be achieved, whilst still maintaining acceptable product life. To achieve this, more attention on the use of the fluids entering the gas turbine is necessary, including air, lubricating oil and fuel. All gas turbine OEMs provide comprehensive specifications covering the fuel quality permitted for use in the gas turbine. These are used to ensure fuel quality is defined at the onset of a project and throughout the lifetime of the turbine and are prepared for good reason. To ensure acceptable turbine operation is achieved with little or no impact on major turbine component life, it is necessary to understand fuel composition and the supply conditions in more detail. Identification of contamination has become particularly necessary as this can have a detrimental impact on exotic materials used in turbine blading.

The choice of gaseous fuels as a primary fuel for use in gas turbines is dictated by widespread availability and low price. Compositions of gaseous fuels vary widely, from those taken directly from wells (can contain high amounts of heavier hydrocarbons), to those containing non-combustible species (such as nitrogen & carbon dioxide). In some cases hydrogen sulfide may be present, which, left untreated, can produce sulfur oxides in the exhaust, and, more significantly, can combine with halides to form compounds which readily attack the exotic alloys used in turbine blading, resulting in premature component failure.

Gaseous fuels can contain a wide variety of contaminants such as: solids, water, higher hydrocarbons, hydrogen sulphide, carbon dioxide, carbon monoxide, and hydrogen. The importance of providing a comprehensive fuel composition in order to determine the suitability of such fuels should not be underestimated. Concerns and issues can be identified at an early stage to allow preventative measures, such as fuel treatment, to be taken.

Higher hydrocarbons influence the hydrocarbon dew point, hence a high supply temperature is required. If the temperature is not maintained then liquid dropout (condensate) will result and can cause problems in the fuel system, or, more seriously, impinge on combustor surfaces leading to localized burning and component failure, such as indicated in Figure 8.

Component Failure
Component Failure
DLE Pre-chamber damage as the result of heavy hydrocarbon carry over and oxidation.

Hydrogen sulfide combustion results in sulfur oxides in the exhaust (hence potential for acid rain). Of equal concern is the presence of alkali metal halides, such as sodium chloride or potassium chloride, and water vapour. These result in the formation of alkali sulfates, giving rise to aggressive corrosive attack of the nickel alloys used in modern turbine blades.

Gaseous Fuel Assessment Criteria

Assessment of gaseous fuels is necessary to determine the suitability, some of which are discussed here:

Temperature Corrected Wobbe Index

Pipeline quality gas fuels contain mostly methane, with small quantities of ethane.

Wobbe Index (WI) is one of the parameters used to assess fuel and allows a direct comparison of different fuels to be made based on heat content. Wobbe Index (number) is the Net (lower) calorific value of the fuel divided by the square root of the fuels specific gravity.



Where CVv<sup>0</sup> = net calorific value (MJ/m3) at standard conditions (288K, 1.013bara)

SG0 = specific gravity at standard conditions


where ρfuel and ρair are at standard conditions (288K, 1.013bara)

Fuels are often provided at different supply conditions. Therefore the use of Temperature Corrected Wobbe Index (TCWI) becomes an important aspect when reviewing fuels. Gas fuels containing water and or higher hydrocarbon species will result in higher dew point requirements, hence the need to provide a set amount of superheat margin, ensuring the gas remains in a vapour at all times.



Tfuel is temperature of fuel at turbine skid edge (K)

WIT = Temperature Corrected Wobbe Index

WI0 = Wobbe Index at standard conditions, 288K

Fuels with visually different compositions may have the same Wobbe Index and therefore same heat content. However, other factors such as dew point need to be evaluated.

GT OEMs have limits on ranges of fuel CV or WI before it becomes necessary to introduce changes in combustion hardware. This may be as simple as geometry changes within the same burner or more extensive and involve fuel system changes. The objective is to achieve a similar fuel supply pressure and pressure drop across the burner to ensure stable combustion is maintained.

Dew Point and Supply Temperature

Gaseous fuels comprise a variety of hydrocarbon species, each of which has a unique “dew” point temperature, i.e. the temperature at which the gas condenses producing liquids, and those fuels which also contain water will have in addition a water dew point. Thus it is possible to determine the dew point for a known gas at a given pressure. It is normal to apply a margin of superheat over the calculated dew point to prevent condensate or liquid drop out. Some OEMs apply a minimum of 20°C, but others may apply higher levels, commonly 25-30°C. Fuels which contain higher, and variable, hydrocarbon species may require a higher margin of superheat to be applied.

Other Contaminants

Water and higher hydrocarbons are two contaminants already discussed, but there are others that are met and need to be considered

Carbon Dioxide

CO2 reacts in the presence of moisture producing a weak acid, but mostly acts as a diluent reducing the heat content available in the fuel.

Hydrogen Sulfide

Hydrogen sulfide is highly toxic and can pose unique challenges to operators as well as in the operation of gas turbines. Besides specific health and safety requirements H2S (also sulfur in liquid fuels) can combust producing SOx (SO2/SO3) emissions to atmosphere, which react in the presence of moisture resulting in weak acid production (acid rain). Where SOx legislation exists, treatment of the fuel at source to remove or lower H2S (or sulfur in liquid fuels) is necessary.

In the presence of sodium, potassium or vanadium, such as found off-shore or in coastal environments, further assessment will be required as the reaction of these metals and their salts with sulfur results in the production of sodium and potassium sulfates or vanates which are highly corrosive to modern materials used in the hot gas path components, such as turbine nozzles and rotor blades.

Hydrogen and Carbon Monoxide

Both readily combust, but require special understanding before acceptance as a GT fuel. Both exacerbate combustor flame speed, and can result in flashback, where the flame velocity exceeds the local combustor velocities. This makes these types of fuels less suited for lean pre-mix type combustion systems. However, conventional diffusion flame combustion systems are more tolerant to such fuels, subject to full assessment and application of appropriate safety measures.

Other Fuels used in Industrial Gas Turbines

Pipeline quality gas fuel has been shown to be the primary source of fuels for gas turbine applications mainly due to widespread availability and low cost. However, there are many other fuels which are used or considered, especially where pipeline gas is either not available or of insufficient quantity.

Premium Liquid Fuels

Diesel fuel and kerosene processed to internationally recognized quality standards are used either on their own or in conjunction with gas fuels (dual fuel operation).

Distillate fuels (No2 Diesel and kerosene, for example) are processed from crude oil and can be made to a wide range of specifications. Other liquid fuels such as natural gas liquids or higher hydrocarbon liquids, such LPG (a mixture of propane and butane), are also produced and have been used as a gas turbine fuel, although special consideration is needed in such cases.

The suitability of commercially available diesel fuels must be assessed and compared to the OEM’s own specification. Several international specifications exist, all with small differences that can make a huge difference in gas turbine operability. Typical Specifications include EN590 and ASTM D975 along with low and Ultra Low Sulfur diesels.

Alternative liquid fuels to fossil diesel are becoming more widespread such as paraffinic biodiesel and liquids derived from natural gas, the latter via conversion techniques such as Fischer Tropsch and commonly referred to as “Gas to Liquids” or GTL fuels (similar fuels include BTL – biomass to liquids and CTL – coal to liquids). Although production quantities are small today these will grow in years to come and either will be blended with fossil diesel or used as a stand-alone fuel. Specifications for such fuels are in development, such as TS 15940:2012, covering Paraffinic biodiesel fuel.


LNG is available from a wide variety of sources and can vary significantly in properties due mostly to the content of ethane, C2 species in the composition (in place of methane). These tend to be higher in Wobbe Number than standard pipeline quality natural gas, so may require nitrogen dilution to ensure compatibility with general pipeline quality fuel specifications.

Wellhead Gases as a GT Fuel

Alternative gaseous fuel solutions for gas turbines are used where export of the gas fuel from source makes little economic sense. Assessment and use of wellhead, or associated, gas fuels can allow marginal wells and locations to be developed.

Each fuel is assessed on its merits with some recommendations made regarding minimal cleanliness, water content, dew point control, all of which have been covered in detail.

Unconventional Gaseous Fuels

Unconventional gas implies gas fuels extracted from coal beds (coal bed methane or coal seam gas) or from shale rock using the technique called fracking. The merit of this process is not discussed, but rather the fuel extracted and treated. The method may be unconventional, but once extracted and cleaned the gas is very much conventional and can be treated in the same way as pipeline quality gas or LNG.

Biogas Fuels

Mainly weak methane-based gas fuels (can be referred to as medium Btu fuels) containing high levels of carbon dioxide, CO2 and/or Nitrogen, N2. which can be naturally occurring or derived from the decomposition of waste material (Land Fill Gas – LFG) or from anaerobic digestion (AD) process or Waste Water Treatment Process (WWTP), and can be considered as a useful fuel for gas turbines. LFG, AD, or WWTP are sometimes recognized as renewable fuels and can gain ‘green’ accreditation and additional economic benefits. There are many examples of gas turbines operating on these weak fuels using conventional combustion, but in recent times extended fuels capability using low emission combustion configurations have been developed. With such fuels it is a requirement of the fuel system to provide sufficient quantity of fuel to sustain stable combustion and be responsive to variations in such fuel sources.

Refinery; Process Off-gas; Hydrogen Syngas

Process off-gas, such as a refinery tail gas, can be used as a suitable gas turbine fuel. These fuels can contain high levels of hydrogen and carbon monoxide, therefore require special consideration due to the much higher flame velocities of these species.

In this category is syngas, derived from the gasification or pyrolysis of coal, petcoke, various wood types, or municipal or agricultural waste products. These are low in heating value compared to biogas, for example, but comprise hydrogen and carbon monoxide as well as quantities of inert species, CO2 and N2. All of these need special consideration due to the impact each has on combustor flame speeds and the propensity for “flashback” and the resultant damage to combustion hardware.

Hydrogen rich fuels have been used with some success, but require the use of conventional combustion. Wet injection can be applied to reduce atmospheric pollution. A derivative of this capability is gases produced from coke batteries in the steel making process. Coke Oven Gas, COG, is high hydrogen, but also contains methane and to a lesser extent CO. Conventional, diffusion combustion system is applied but additional gas cleaning is essential to prevent a shortening of the hardware life due to the effects of contamination found in such fuels.

Natural Gas Liquids and LPG fuels

Less used, but still viable, gas turbine fuels include those containing higher hydrocarbon species. These require specific assessment and consideration within both the fuel system and combustor injector.

LPG can be used either in vaporized or liquid form. When vaporized and maintained in gaseous form, the gas should be supplied at elevated temperatures due to the use of the higher hydrocarbons usually associated with LPG, butane and propane. Special injectors will be required to ensure the metered fuel is correctly controlled.

When supplied in liquid form special consideration must be made to the fuel system. LPG has a low viscosity and special pumps are required to overcome the problem of low lubricity. Control of the fluid is critical to ensure other problems are avoided such as:

  • Waxing (fuel temperature too low)
  • Exceeding flash point (temperature too high)
  • Corrosion (particularly where copper is present)
  • Vapor lock due to premature vaporization of liquid

Storage of such fuels needs particular attention. Having a lower viscosity in liquid form and being heavier than air when in gaseous form means special precautions have to be adopted.

Crude Oil as a GT fuel

Viscosity is one of the key parameters used when evaluating liquid fuels for use in industrial gas turbines and generally should be <10cSt (most regular diesel fuels <7.5cSt @ 40degC).

There are cases where neither diesel nor gaseous fuels are available and the only “fuel” is crude oil. This creates challenges that have to be handled through fuel pre-treatment and fuel injection system functionality. Firstly, heating the fuel reduces the viscosity, but noting the limitations:

  • First is 100°C, at which water boils off (all liquid fuels contain a small amount of water) causing cavitation in fuel pumps
  • Increasing fuel oil supply pressure allows the heating to be extended beyond 100°C, but is limited by the temperature limits within the fuel delivery system
  • Further heating can result in fuel cracking and coking in the fuel system and burners depending on the constituents within the crude oil

Crude oils need to be treated in order to meet industrial gas turbine limits on metallic and other contaminants in the fuel.

Crude oil often contains high amounts of alkali metals (Na, K) and heavy metals (V, Ni, etc.) which, if introduced into the combustion system, can result in accelerated deposit formation and high temperature corrosion in gas turbine hot gas path components.

Major corrosive constituents include Vanadium pentoxide (V2O5), sodium sulfate (Na2SO4) and aggressive low melting forms in the Na2SO4 – V2O5 and Na2O-V2O5 systems. Determination of the ash sticking temperature is usually a good feature to use, and should be >900°C if sticking to the blade is to be avoided.


The understanding of fuels used in modern high performance, high efficiency gas turbines is a critical step in achieving the goals of high availability and reliability, but at the same ensuring the environmental needs are fully met.

The impact of the wide range of fuels used in gas turbine combustion systems, especially those of the low emissions variety, has been considered.

In conclusion, the supply of the right quality fuels can result in the above requirements being met, while the use of fuels outside the advised specifications can result in increased maintenance requirements.

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