by Robin McMillan, David Marriott and Su Ri Han

Using ‘waste’ gases as fuels for gas turbine-based cogeneration plants adds yet another advantage to this high efficiency technology. But some care is needed to configure the turbine plant to operate on, for example, hydrogen-rich refinery gas and coke oven gas. Robin McMillan, David Marriott and Su Ri Han explain more.

In order to counteract the effects of global warming, the pressure to reduce the environmental impact of power and heat production is growing. Reduction of the amount of carbon dioxide emitted during the generation of heat and power is seen as the key to reducing impacts on the environment. However, it is expected that the demand for power will increase dramatically over the next ten to 20 years, driven by the continuing economic expansion in countries such as China and India.

Whilst technologies are now available that emit very low levels of carbon dioxide or use fuels obtained from renewable sources, these are often uneconomic to install and operate. The challenge is to employ a more pragmatic approach that uses existing proven technologies in a more effective way.

Distributed cogeneration power plants are an economic way of significantly reducing carbon dioxide emissions during the production of power and heat. Installing power plants closer to the point of use reduces electrical transmission losses and provides a ready source of heat for the production of steam, hot water and chilling. Optimization of cogeneration facilities can lead to overall useful power-to-heat input ratios of greater than 90%, which can reduce the carbon footprint of an installation by 50%.

The economic and environmental impact of cogeneration can be further enhanced by utilizing waste gases such as refinery and coke oven gases. It is also worth noting that application of cogeneration-to-waste gases in some regions can qualify for carbon credits.


This feature will concentrate on gaseous fuels, with Figure 1 showing the main families of gaseous fuels available for firing gas turbines.

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As well as a large variation in heating value, and corresponding variation of required volume of gas to be fed into the turbine, the composition of these fuels varies greatly. For example, the lower-heating-value fuels such as those from gasification tend to contain high levels of inert compounds, with the energy coming from hydrogen and carbon monoxide, whereas coke oven gas contains high levels of hydrogen and little or no inert species. The differences in composition and heating values lead to different challenges in the gas turbine, as discussed on page 45 under ‘fuel considerations.’

Figure 2. Flow chart for IGCC-plant in Varnamo. Note that, as well as the plant operating in combined cycle, waste heat from the HRSG was used to provide district heating
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As well as the technical challenges, the overall economics of the gas turbine application and the fuel source/supply are critical. For example, the amount of capital investment required to build an integrated gasification and combined-cycle plant currently means that such plants have only marginal viability, even at very large scale (>1000 MWe).

A good example of where the economics do not add up, despite technical demonstration, is the biomass-fuelled IGCC plant built in Varnamo, Sweden. This plant demonstrated several thousands of hours of successful operation using a gasifier feeding an SGT-100 gas turbine. As well as the plant operating in combined cycle, waste heat from the HRSG was used to provide district heating. Despite this technical success, the cost of the electricity produced by the plant was too high for it to operate beyond the demonstration phase.

In contrast, a process waste gas can provide a huge financial opportunity for a user who can use or sell on the heat or electricity available through installation of a cogeneration plant.

One example of a waste gas that provides a viable opportunity is coke oven gas. In general, in China, coke-producing plants are located away from steel production facilities. This means, instead of using the gas as part of the steel production process, in a large number of cases the gas is simply flared or, even worse, vented. Table 1 shows typical sizes of coke plants and the volume of waste gas produced.

Table 2 shows various options for implementing gas turbine solutions to produce electricity and steam at an efficiency of up to 95% (gas turbine, plus fired boiler, plus steam turbine, plus waste heat).

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Burning waste gases, as well as being financially attractive, can also benefit the environment by producing power and heat that would otherwise be produced by the burning of premium fuels, resulting in a net reduction of carbon dioxide produced. As such, installation in China can be entitled to carbon credits.

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Another example is using refinery gases where a hydrogen-rich off-gas is produced and is used to fire a gas turbine and heat recovery system providing both process steam and electricity. These gases can contain very high levels of hydrogen (>80%).

Another application that takes the term ‘waste’ to an extreme is operating a gas turbine on landfill and sewage gas. In an application using sewage gas, heat is recovered from the gas-turbine exhaust and used to accelerate the anaerobic digestion of sewage, producing a medium-calorific gas (consisting of methane and carbon dioxide) that is then used to fire the gas turbine. In addition to heat supplied to the digester, a steam turbine can be applied to increase the overall electrical efficiency of the plant in applications where process steam is not required.


In order to understand the impact of a fuel on the gas turbine it is important to recognize the key combustion and flow characteristics of the various fuels discussed. Figure 3 attempts to map out the fuels in terms of the key influencing properties of volume flow, hydrogen content and extinction characteristics. These three parameters have strongest impact on how the gas turbine is adjusted to cope.

Volume flow is the easiest to understand: As the heating value of the fuel drops, larger flow areas are required to deliver and inject the fuel into the turbine and provide the same heating value. In some extreme cases, such as fuels derived from air-blown gasification or blast-furnace gas, the compressor and turbine may need to be re-designed to cope with the difference in volume added after the compressor in the form of fuel. In the case of blast furnace gas, the volume of fuel injected into the combustor is actually higher than the volume of air exiting the compressor.

Figure 3. Family of fuels showing key characteristics
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The extinction limit of the fuel determines the flammability range for combustion, meaning that only very rich fuel-air mixtures will stay alight (particularly of concern for lean-burn DLE systems). Given a high enough inert content, some fuels may become incombustible.

One of the biggest challenges for DLE combustion systems comes with gases containing hydrogen. Figure 4 shows the impact of hydrogen (and carbon monoxide) on the burning velocity of gas mixtures.

As can be seen, relative to natural gas, the flame speed increases dramatically with the addition of hydrogen, a situation which is further aggravated through the addition of carbon monoxide. The top line in the chart is roughly where indirectly fired gasification fuels sit (the balance being inert). As a stable combustion system relies on ignition of the fuel away from the fuel-injection geometry, addition of hydrogen leads (in some cases) to the flame establishing itself in an abnormal position too close to the fuel injector or combustor walls. This is known as flashback and can lead to significant damage to the gas turbine within seconds of occurring.

SGT-200 unit operating on high-hydrogen fuel at an oil refinery in the UK
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As a consequence, systems operating today on high-hydrogen fuels, such as refinery gas, are modelled on diffusion-based combustion systems and any NOx-control relies on the injection of a diluent such as water, steam or inert gas (some gasification processes adopt this) to reduce NOx to required levels.

Figure 4. Burning velocity of various fuel mixtures compared to methane. Note the balance of composition is made up with inert gas, in this case nitrogen
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The key challenge gas-turbine manufacturers face, for future operation on alternative fuels, is developing a dry low NOx combustion system capable of operation on high-hydrogen fuels.

In addition, the high level of contaminants associated with some of the gases illustrated in Figure 3, needs to be reduced to levels suitable for long-term operation in gas turbines. The additional fuel treatment to remove components such as ammonia and tars from syngases produced by gasification, and hydrogen sulphide and siloxanes from digester and landfill gases, add to the overall plant complexity and cost.


Cogeneration plants fuelled using waste gases provide an economic and environmentally-friendly way of helping to satisfy the heat and power needs of industry or a community. The feature has explored the use of waste fuels in a gas turbine, explaining some of the main considerations necessary to ensure the cogeneration plant provides the required heat and power in a reliable, efficient manner.

Robin McMillan and David Marriott are with Siemens Industrial Turbomachinery, Lincoln, UK. Su Ri Han is with Siemens China, Shanghai, China.