Global demand for energy is expected to increase by 50% between now and 2030, according to the IEA World Energy Outlook. And, according to BP and the IEA Energy Outlook, oil production is expected to grow at an average annual rate of 1.6% a year up to 2020. Gas production is expected to grow at an average rate of 2.5% a year.

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Using associated gas more efficiently will reduce emissions SIEMENS

Fossil fuels therefore remain the dominant source of primary energy, accounting for 84% of the overall increase in demand between 2005 and 2030. But these resources are getting harder to find and develop, increasing the need to maximize recovery from existing assets and replace produced reserves by accessing new, more difficult provinces.

In addition, rising global energy demand poses a threat to the world’s environment. Rising carbon dioxide and other greenhouse gas concentrations in the atmosphere, resulting largely from fossil-energy combustion, are contributing to higher temperature and to changes in climate. Consequently, there is an increasing focus on energy efficiency and awareness.


It is currently estimated that 150-170 billion cubic metres (bcm) of natural gas per year are currently flared or vented globally from upstream petroleum operations. The effect of gas flaring on the environment is an increasing concern.

The Sub-Saharan countries of Africa flared 40 bcm per year; three times the region’s gas consumption. Nigeria is one of the largest flarers of associated gas.

So much gas is flared because there is often no infrastructure to bring the gas to market; a consequence of the poor potential returns and high risks associated with building such infrastructure.

Tax regimes make the flaring of gas increasingly uneconomical. Consequently, oil and gas companies face increasing pressure to utilize dwindling natural resources effectively, which in turn drives development of new technologies to utilize associated gas more effectively.

Flaring gas leads to significant waste of a energy resource and it harms the environment through greenhouse gas and other emissions. Flaring adds more than 400 million tonnes of carbon dioxide emissions every year. It is estimated that 75% of global flaring occurs in just ten countries, but it’s a global problem.

Capturing and using the gas wasted could bring large economic, social and environmental benefits. Location is also a big issue; if flaring is not allowed, then the alternative is to make use of it to produce liquefied natural gas (LNG) for export, or perhaps compressed natural gas (CNG) for re-injection for oil recovery, as well as using gas for the local economy if the demand is there.


For using associated gas for power generation on site or for compressor drives, Siemens can offer gas turbines which include eight frames from 5-47 MW electrical output, which cover a majority of current and future CHP applications within industries, as well as for oil and gas industry applications.

The gas turbines are designed to give optimal output of electricity and heat, while offering fuel flexibility and operational reliability. These machines offer a choice of operating fuels which include natural gas, distillate fuel and some associated fuel gas.

These gas turbines include more than 3900 units sold to date, with a large portion working in the oil and gas industry for power generation and mechanical drive applications.


Associated gas is a natural gas which is found in association with crude oil, either dissolved in the oil, or as a cap of free gas above the oil. Associated gas can also be wellhead gases, flare gas or waste gases such as tail gases from refineries and petrochemical processes.

The associated gas market is growing due to depleting gas fields requiring enhanced oil recovery (EOR) with CO2 or N2, and the lower quality of gas occurring naturally in gas fields.

Siemens’ gas turbines can burn a wide range of fuels — see Figure 1.

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These gases usually comprise hydrocarbons (mainly methane with small quantities of ethane, propane, butane and higher hydrocarbons) with varying levels of inert gases; typically nitrogen and carbon dioxide. Gases usually contain some other contaminants including hydrogen sulphide and mercury.

Wellhead and associated gases cover a Wobbe Index range from 3.5 to 65 MJ/Nm3. The Wobbe Index is the main indicator of the interchangeability of fuel gases such as natural gas, liquefied petroleum gas (LPG) and town gas, and is frequently used in the specification of gas supplies.

The Wobbe Index is defined as: the higher heating value divided by the square root of the specific gravity of the gas.

Medium calorific value (MCV) and high calorific value (HCV) fuels comprise between 10%-15% of the total oil and gas turbine market.

The poorer quality gases, or non-standard fuels, ranging from LCV natural gas through to medium and high calorific value wellhead gases, can be used as fuels in gas turbines for power generation of mechanical drive applications.

Siemens has experience with selected upstream and midstream oil and gas applications using fuels outside the standard fuel range, with its gas turbines running on MCV fuel below 30 MJ/Nm3. Its 6.75 MW turbine has run on HCV fuel using a standard combustion system, and its 13 MW machine has used MCV fuel of 28 MJ/Nm3 with its Dry Low Emissions (DLE) combustion system. DLE combustion systems are used in gas turbines to minimize emissions to the atmosphere of nitrogen oxide and carbon monoxides as well as other unburned hydrocarbons (UHC).

See box on emissions legislation below.


If we look at Siemens’s history with oil and gas downstream and industrial applications, it is apparent that the company’s turbines have run successfully on refinery tail gas/waste gas.

Refinery gas composition varies depending on the crude oil that comes through the refinery; therefore there is always a varying quantity of hydrogen.

Siemens gas turbines have also run on flue gas, which comes off some mines.


The key challenge for gas turbine manufacturers, with regard to future operation on alternative fuels, is developing a dry, low NOx combustion system capable of operation on high-hydrogen fuels.

Figure 2, below, shows the impact of hydrogen concentration on the flame speed, which increases as the proportion of hydrogen contained within the gas increases; a situation which is further aggravated through the addition of carbon monoxide.

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This leads to an increase in the risk of the flame stabilising too close to the fuel injector, or other parts of the combustor, leading to overheating and damage. This is known as flashback and can lead to significant damage to the gas turbine within seconds of it occurring.

The combustor (in particular the fuel injector) needs to be designed to cope with this.

This provides a significant challenge for applying dry low emissions technology, as this relies on premixing the fuel and the air prior to flame ignition.

High levels of hydrogen in the fuel causes flashback (unwanted pre-ignition of the fuel), which is very difficult to avoid.

Typically water or steam injection is used to control NOx in conventional combustors.


Siemens has experience in selected oil and gas applications — both up and midstream — with non-standard fuel range and with dry low emissions systems.

Gas turbines are particularly environmentally-friendly and economical thanks to their lower fuel consumptions and low emissions. Siemens is committed to reducing NOx emissions and continues to develop its gas turbines dry low emissions technology.

Fuels outside range or constituents outside of specifications are handled on a case-by-case basis.

The strategy is to develop DLE combustion technology while maximizing fuel flexibility, ambient temperature and load range.

Refinery and chemical plants using cogeneration technology and 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.

Associated gases and waste fuels can be used in a gas turbine to ensure that the gas turbine plant provides the required heat and power in the most reliable, efficient manner possible.

The challenge has been set to gas turbine manufacturers by the market place to burn a much wider range of gaseous fuels while still achieving low emissions levels.

Geraldine Roy is senior market analyst with Siemens Industrial Turbomachinery Ltd, Lincoln, UK.

Emissions legislation

Stricter emissions legislation over the past 15 years has led to the development of DLE combustion systems on gas turbines to minimise the emissions to the atmosphere of nitrogen oxides (NOx), carbon monoxide (CO) and unburned hydrocarbons (UHC).

Tests carried out have demonstrated that the G30 L combustion system used in Siemens’ small industrial gas turbines appears to be extremely flexible with regard to fuel calorific value and composition, with the ability to achieve emission levels similar or better than natural gas over this wide range of gaseous fuels.

The modification required to achieve this increased fuel range would appear to have negligible impact on performance and durability, while having minimum impact on capital and maintenance costs.

The DLE system has now amassed more than 7 million operating hours.

Case Study: Tyanskoye Oil Field

Siemens has sold three SGT-200 gas turbine generating sets which have entered commercial operation at an oil field in western Siberia. The 6.75 MW rated machines are burning wellhead gas to generate electricity for production in the Tyanskoye Oil field.

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SGT-200 gas turbine units for an oil field at the Tyanskoye oil field, Russia

There is not enough gas to go in the pipeline and therefore to make it economically viable, the operator burns the waste gas to produce electricity. They can then export this electricity to the grid.

This is the first application of its kind in Russia — burning wellhead gas which was previously flared. The gas turbines also incorporate a DLE combustion system providing guaranteed NOx and CO emission levels of 25 ppm. The climatic conditions on this site are a real challenge with temperature varying from minus 57°C up to 34°C. The fully packaged sets, which entered commercial operation in August 2001, were manufactured and supplied from Siemens’ gas turbine facility in Lincoln, UK. Siemens has supplied over 140 gas turbines for power generation, gas compression and pumping duty throughout the Russian oil & gas industry.

SGT-100 and SGT-300 units are also used for a power plant at the Khasireyskoye oil field north of the arctic circle in Siberia.

Case Study: Yadana Gas Field

Another project example is for the new platform in the Yadana gas field in the Andaman Sea off the cost of Myanmar.

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SGT-400 gas turbine as used at the Yadana gas field in the Andaman Sea

Siemens has secured an order for the supply of two SGT-400 gas turbine-driven compressor trains to be installed on this new gas platform. These two dual fuel units are fitted with a DLE combustion system.

The turbines have the ability to burn medium calorific gas fuel containing up to 24% nitrogen. The units are used to supply gas to the domestic market and to three power plants in the Bangkok conurbation in Thailand.

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