Heavy-duty gas turbines’ fuel pick ‘n’ mix

Power generation plants have to be increasingly flexible in the range of fuel that they burn, which means that gas turbines have an important role to play here. Jeff Goldmeer, manager of HDGT fuel capability at GE Energy, looks at what fuels are available for them.

Dr Jeff Goldmeer, GE Energy, USA

Greater environmental awareness and the desire to find the best use of potential gas and liquid fuel stocks are changing the global energy landscape. As nations aim for domestic energy security and try to reduce environmental impact and the effect of variable fuel costs, there has been a continued push to diversify and examine alternate or non-traditional fuel sources.

Assembly of the rotor of a GE Frame 9E gas turbine
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Natural gas combined-cycle plants provide high efficiency compared with other technologies, so there is an increased demand for natural gas as power generators aim to reduce their carbon emissions. An increased availability of liquefied natural gas (LNG) is also favourably impacting this emphasis on gas generation. At the same time, countries will continue to look at available natural resources, including coal, as a way to increase energy stability and security. As the industrial sector has begun to recognize the effect of greenhouse gases on the global climate, they are now looking for solutions to curb their emissions. Solutions for reducing carbon dioxide (CO2) emissions can be as simple as leveraging increasing energy conversion efficiency or switching to more carbon-neutral fuels. Finally, these pressures are also drivers for many industrial and refinery plants to re-examine the potential inherent value of off-process gases or process waste streams as a way to maintain or reduce energy operating expenses.

Traditional gas turbine FUEL

Natural gas has penetrated power generation in a major way and will continue to make significant penetrations in power additions. But natural gas resources in the world are unequally distributed. In Europe, for example, demand is greater than local supply, so multiple natural gas pipelines from Russia and North Africa supply this demand. Yet events of the past few years have shown that this supply can be interrupted by geopolitics.

An increased emphasis on the development of LNG facilities has augmented the available supply, but adding LNG to the pipeline adds inherent issues because it increases variation in the gas supplied to power generation facilities. LNG can have a greater content of inert gas, such as N2, and higher hydrocarbons, especially ethane (C2H6). This variation in fuel composition can be characterized using the Modified Wobbe Index (MWI), a system designed to deal with such fuel-specific energy variations.

The key to adapting to the variations in fuel composition is a control system that is able to measure and adjust to these changes. GE Energy bases its approach on a control system that links directly to the operability boundaries impacted by fuel quality: combustion dynamics, emissions and blowout. For units fitted with Continuous Dynamics Monitoring and Mark VI control systems or higher, no specialized system hardware is required beyond minor redundancy upgrades of existing control sensors, for example humidity and fuel manifold pressure. GE Energy has validated its OpFlex Wide Wobbe control technology with simulations and field tests.

The closed-loop simulations modelled the gas turbine and control system and included the actual control-computer hardware and software coupled to a real-time system model that was matched to field data. Results from the simulations demonstrated the ability of the system to withstand a rapid change in fuel composition with little operational impact. The field test validation employed a 7FA+e gas turbine with a DLN2.6 combustor operating in a 107FA combined-cycle mode with heated fuel. As the system experienced a rapid change in MWI, it was able to maintain NOx levels without impact on combustion.

This control system was installed on four turbines at two sites in Florida, USA in 2007. Since installation, the systems have accumulated more than 12 000 hours of operation and have accommodated transitions from natural gas to LNG with wide variation in fuel heating value. This system is available for GE’s Frame 7FA gas turbine and is also in development for its Frame 9FA gas turbine with DLN 2.6+ combustions systems.

Non-traditional gas turbine fuels

In this changing energy landscape there is a growing interest in non-traditional fuels or alternative fuels and on capitalizing on the experience gained during the past two decades. Gas turbines are continuous-flow machines that have demonstrated distinct capabilities to accept a wide variety of fuels. Their robust design and universal combustion systems enable heavy-duty units to handle a vast range of fuels.

There are many alternative fuels for gas turbines, but not all of them can be applied in every global region. For example, it is not expected that heavy fuel oil (HFO) will play a large role outside oil-producing regions. Alternative fuels can be classified into three categories.

First, byproducts of industrial processes are derived from the chemical, oil & gas or steel sectors. Many of these fuels cannot be transported or stored, and their essential appeal will be to reduce fuel supply in industrial plants in the carbon-constrained environment.

Syngas and synfuels are derived directly from abundant fossil carbon in the form of coal, lignite, heavy ends including tar sands, and shale oil. They show great potential for the carbon-constrained economy, provided they are subjected to carbon capture.

Finally, bioliquid fuels are more evenly distributed around the world and are of prime interest because of their overall neutral carbon balance. GE Energy is enabling its customers to explore first-generation biofuels as the industry looks to more sustainable fuel stocks.

Process byproduct fuels

A number of industry processes generate byproduct streams that are suitable for combustion in power plants, for instance crude oil topping, platforming, dehydroalkylation and de-ethanization in refineries and thermal crackers and aromatics plants in petrochemical facilities generate valuable gases that are called ‘fuel gas’ or ‘net gas’ and are generally mixed to constitute the fuel gas network of the plant.

Heavy-duty gas turbines can achieve maximum benefit from alternative fuels for several reasons:

  • They develop better power generation performances than steam cycles
  • The power/heat ratios of gas turbine -based CHP match the requirements of modern industrial plants.
  • They meet the stringent reliability/availability standards placed by refiners and petrochemists.
  • They can run over 8000 hours without interruption.
  • They accept other alternative fuels such as fuel oils, naphtha, C3-C4 gas and heavy distillates.

Heavy-duty gas turbines have demonstrated an unequalled integration capability in the energy schemes of the hosting plant.

For instance, liquefaction units in LNG production plants that produce C2+ tail gases that can feed the gas turbines are used as mechanical drivers for the compression units. Crackers and reformers in refineries produce hydrocarbon or hydrogen-rich byproducts that can be used in plant cogeneration with performances close to that of natural gas in CHP plants. The steam produced by the CHP serves plant processes and excess power can be exported to the external grid.

Another example is the case of petrochemical plants that want to reduce the amount of hydrocarbon and/or hydrogen gas that is flared. These gases could potentially be blended into the existing natural gas stream that fuels an onsite gas turbine. The resulting system could increase net plant efficiency and reduce fuel costs.

Low-calorific-value fuels

These synthetic or recovery gases stem from industrial processes and ultimately derive from the oil & gas or steel sectors. Many of these fuels cannot be transported or even stored, and are essentially of interest for their ability to minimize fuel input to industrial plants in a carbon-constrained environment. Based on considerable experience in medium/low heating value, GE Energy has developed an improved low-calorific-value (LCV) gas version of the its MS9001E gas turbine. This product is commercially available for various LCV applications, for example as gasified refinery petcoke, Corex export gas and blended recovery fuel gas. Several projects are under implementation.

In terms of LCV gas experience, a combined-cycle power plant in Italy has become a major reference plant for the use of recovery. In commercial operation since the end of 1996, this plant consists of three CHP/CCGT units, has a total generating capacity of 520 MW, and supplies 150 tonnes/hour of steam for the process. Each combined-cycle unit is built around a GE Energy MS9001E gas turbine with an ISO output rating of 130 MW and is able to burn mixtures of recovery gas and natural gas. The combustion system is of the dual-gas type, and natural gas is used for startup and shutdown operations. The gas turbine drives a 103 MW double-end generator and a 27 MW fuel gas compressor in an integrated single-shaft arrangement.

A horizontal heat recovery boiler produces steam at two pressure levels (9500 kPA and 2500 kPa) and reheats the low-pressure steam that is fed back into a 68 MW steam turbine generator set. Supplementary firing provides extra system flexibility in using available recovery fuel gas to raise gas temperatures at the super-heater inlet. Each combined cycle unit has a total net output of 168 MW and supplies 46 MW of heat to the process. Considering the steam generated for the process, the net electrical efficiency is 41.5 per cent. Without process steam generation, it rises to 43.9 per cent net.

In today’s steel industry, increasingly fierce competition is driving a trend to reduce energy production costs and replace conventional power plants with GTCC power plants, which can raise electrical efficiency from 30-35 per cent to 40-45 per cent. Although initial investment is higher, net electrical efficiency is improved by 8-10 per cent. The primary fuel is blast furnace gas (BFG), which is a byproduct from the steel works. BFG is an ultra-LCV gas (700-800 kCal/Nm3) that can be mixed with coke oven gas (COG 4200-4800 kCal/Nm3) and possibly converter gas (LDG 1900-2200 kCal/Nm3) to meet gas turbine minimum fuel calorific value constraints.

Syngas and synfuels

Carbon fuels such as heavy refinery bottoms, coal or lignite that are in the syngas/synfuel category of alternative fuels described will play an increasing role à‚– provided their combustion is in efficient and environmentally-conscious conditions. Coal is an abundant, evenly distributed energy source worldwide. It is a resource that estimates say will last for several centuries. In some European countries, such as Germany, the UK and Poland, it has been a major natural resource. From both an efficiency and environmental prospective, integrated gasification combined cycle (IGCC) or ‘cleaner coal’ is a promising technological solution for long-term power needs. IGCC actually combines:

  • Advanced conversion efficiency
  • Solid and liquid feedstocks from local sources
  • Competitive capital expenses
  • Most favourable pollution emissions control, for example of NOx, SO2, mercury and PM10
  • CO2-capture readiness, when combined with carbon capture and storage (CCS)
  • Fuel felixibility

Gasification plants that use GE-designed gas turbines (operating or under contract) produce more than 2500 MW of power worldwide in total. This turbine fleet has accumulated a total of more than 900 000 hours of operation on low-calorific syngas fuels and significant operation with co-firing of alternative fuels.

Several recent refinery-based gasification projects boast exceptional performance and fuel flexibility. Process feedstock includes coal, lignite, petroleum coke, heavy oil and waste materials converted by six different gasifier types. An example is the gasification that will be part of the expansion of a refinery located in China’s Fujian Province. This project will expand the crude oil processing capacity of the existing refinery from 4 million tonnes to 12 million tonnes per year. GE Energy will supply two Frame 9E gas turbines, both rated at nearly 130 MW, and two generators for the IGCC plant, which will support operations at the expanded petrochemical complex.

Polk power station in Florida is one of the first IGCC plants in the USA
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For the near-pure hydrogen used in combustion gas turbines, GE Energy benefits from existing gas turbine experience on high-hydrogen fuels derived from a variety of process plant applications. F-class gas turbines with hydrogen content up to 45 per cent by volume have been in operation for more than ten years, with collected operation experience of more than 80 00 hours on the fleet leader.

GE Energy continues to develop advanced gas turbines with syngas fuel capability to meet market demand for improved gasification cycle efficiencies with increased output and reduced capital costs. The 9FB IGCC, which will be the unit for the 50Hz market, builds on the F-Fleet experience achievements in reliability and maintainability, and combines the performance of the 9FB natural gas combined-cycle unit, coupled with GE’s proven diffusion combustion system and syngas hot-gas-path components. In addition, the 9FB is being designed for potential operation on syngas and high-h2 fuels.

Advanced F technology results in bigger units that provide the benefits of reduced capital expenses and higher combined-cycle efficiency. Since early dry low-NOx (DLN) type combustors are limited to a maximum h2 content of less than ten per cent because of the potential for flashback, the contemporary combustor for F-class machines that operate with hydrogen-content syngas is the diffusion-flame IGCC version of the multi-nozzle combustor.

Current research and engineering efforts funded under US Department of Energy (DOE) Contract DE-FC26-05NT42643 may lead to DLN systems for future syngas and high-hydrogen applications. The results of sub-scale testing of multiple new combustor designs have demonstrated potential pathways to reach the DOE NOx goal.

Renewable liquids

As many countries in the world look for new fuel opportunities, they are confronted with growing concern over greenhouse gas emissions. One approach to resolving this concern is to use carbon-neutral fuels. These are fuels that do not add any additional carbon to the current environment. One such solution is biofuels, which in essence recycle carbon that is already in the environment. Fossil fuels, on the other hand, put carbon back into the environment after being sequestered for thousand or millions of years.

There are many diverse biofuels and biofuel feedstocks being considered across the globe. These feedstocks can include corn, soy, palm, rapeseed or jatropha. Multiple chemical processes can be used to take these raw plant-based elements and convert them into alcohol-based fuels, such as methanol and ethanol, or petroleum-like fuels such as biodiesel. Most popular liquid biofuels can be classified in three groups:

  • Vegetable oils (VOs) as virgin or recycled product
  • Alcohols
  • Esterified VOs or fatty acid alkyl esters (FAAE).

A fuel that is attracting significant attention for gas turbine power generation is biodiesel. Biodiesels or FAAE are modifications of triglycerides. GE Energy has demonstrated the performance of biodiesel on both its heavy-duty industrial and aeroderivative gas turbines over a range of operational loads. The units tested were the MS6001B, MS7001EA and LM6000. The biodiesel field tests were performed in conjunction with Duke Energy (on the 7EA) and Brookfield Power (on the LM6000).

GE’s Aeroderivative turbines have also operated on biodiesel blends. In all field tests, the NOx emissions were at least as low as the baseline comparison with operation on diesel oil (DO). In some cases, the emissions were lower. More specifically, the results of the 6B biodiesel field test can be summarized with the following points, taking DO as a basis for comparison:

  • SOx is minimal (lower than 1 ppm), as expected
  • No visible plume; smoke opacity lower than with DO
  • CO and VOCs are as minute as with DO
  • The NOx-abatement effect of water injection is normal and similar to that with DO
  • PM’s, PAH and aldehyde emissions are below the detection limits.

Considering the potential for a reduced carbon footprint, biodiesel may be an attractive alternative to distillate fuels when available.


An analysis of emerging fuels shows that the power generation community will face challenges. The predictability of fuel resources and environmental commitments will be an important factor in long-term plans. As a result, there is a push to explore all sustainable alternative energy channels.

Any sensible use of alternative fuels à‚— including process streams from industrial plants such as refinery, petrochemical, iron and steel à‚— will generate added value via economic and environmental benefits. In a carbon-constrained environment, the technology trend is for combustion systems capable of burning syngas and hydrogen-rich fuels in combination with delivering the required operability. In this new context, the strong operational experience gained by gas turbines with a wide cluster of fuels create favorable prospects, especially for F-class machines that develop high performances.

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