Rising fuel costs and tightening emissions standards have combined to make it more attractive than ever to install on-site cogeneration systems, particularly where users have access to free waste products that can be used as fuel, rather than paying to dispose of them. As Drew Robb writes, much recent work on gas turbine design has been to allow their use of non-standard fuels, as well as overall efficiency.

’The past year has seen a turning point in the growth of the generation and use of electricity from biogas,‘ says Holly Emerson, Ingersoll Rand‘s Marketing Manager in Davidson, North Carolina, USA. ’Concern and awareness over global climate change has caused this stuff to become mainstream. I also think we‘re now seeing the ’perfect storm‘ of citizen outcry for climate change legislation and rising energy costs that will really propel the widespread adoption of renewable energy technologies.‘

To meet this demand, manufacturers are refining their systems to boost efficiency while also accommodating a wider range of fuel sources.


One of the major drivers in cogeneration is expanding ethanol production. Commodities information provider F.O. Licht, part of London-based Informa plc, states that worldwide ethanol production grew from 10.77 billion US gallons (41 billion litres) in 2004 to 12.15 billion gallons (46 billion litres) in 2005, a 13% annual growth rate; two-thirds of that amount was produced in Brazil and the US. With US regulations calling for the addition of ethanol to gasoline, production is expected to continue its rapid growth.

Microturbines are continually being developed to accommodate a wider range of fuels such as biogas (Ingersoll Rand)
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According to the Renewable Fuels Association, US ethanol production capacity grew from 3.9 billion gallons (15 billion litres) in 2005 to 4.86 billion US gallons (18 billion litres) in 2006, a nearly 25% increase. Yet the country still imported another 653 million gallons (2.47 billion litres) of ethanol that year, primarily from Brazil. US production capacity had nearly quadrupled since 1999, and another 6 billion gallons (23 billion litres) of annual capacity is under construction.

Since ethanol plants require a good deal of process heat, as well as electricity, this presents a prime opportunity for cogeneration. The US Environmental Protection Agency has targeted this industry for increased use of cogeneration.

‘Dry mill ethanol plants have large, constant, and coincident electric and thermal loads, resulting in a strong technical fit for CHP to efficiently provide both steam and power for these facilities,’ says Kim Crossman, Team Leader for the US Environmental Protection Agency’s Combined Heat and Power Partnership. ‘With CHP, ethanol production facilities can realize a reduction of approximately 15% in energy intensity … and these efficiency gains translate directly into greenhouse gas emissions reductions.’

According to Energy and Environmental Analytics, Inc.‘s (EEA) July 2006 report ’An Assessment of the Potential for Energy Savings in Dry Mill Ethanol Plants from the Use of Combined Heat and Power (CHP)‘, cogen can cut a plant‘s total fuel consumption by 12%. A 50 million gallon ethanol plant requires steam loads of 100,000-150,000 lbs (45,000-68,000 kg) per hour and 4-6 MW of electricity. By using a Solar Turbines Centaur 50, the plant would generate 4 MW of power, but the waste heat would only produce about 20% of the plant‘s steam load. Supplemental duct firing would satisfy the remaining steam requirements. Bruce Hedman, EEA‘s Director of Distributed Generation Markets and Technology advises that the plant be sized according to the steam requirements.

‘You can match up the thermal load and electrical output pretty well to provide most if not all the steam and most of the electrical needs of the plant,’ he says. ‘Make sure you don’t go above the base electrical load. If you are producing more than you use on the site, it is usually difficult to sell it to the utility.’

Frequently, these cogen plants are operated by the utility, rather than the plant, so it is necessary to design the control system properly. For example, when US Energy Partners built a 40 million gallon (150 million litres) ethanol plant in Russell, Kansas, the city installed two Solar Taurus 70 gas turbines at the plant with a capacity of 15 MW and 65,000 lbs (30,000 kg) per hour of 100 psi steam. When both are running, they produce about a third of the steam needed. Since the CHP systems and the plant systems are owned and operated by separate entities, it was necessary to set up a control system that would link the two in order to prevent damage.

‘We have a special knife gate that goes down to prevent heat from going to the boiler until they are ready for it,’ Duane Banks, the city’s Electrical Utility Director. ‘But you have to have safeties in place so that if the knife gate is not in the right position, the turbine doesn’t run. Otherwise you might not have the correct water level in the boiler and can have an explosion.’


Ethanol turbines are typically in the multi-megawatt range, but most on-site power installations are much smaller.

Ingersoll Rand produces microturbines in the sub-megawatt range. In November 2005, its MT250 microturbine was certified as meeting the California Air Resource Board’s (CARB) emission standards for distributed generation technologies. According to Holly Emerson, this required passing a stringent set of emission limits comparable to the Best Available Control Technology (BACT) standards used in larger and most advanced of central power plants. In February, Ingersoll Rand also signed an agreement with United Technologies Corp. to provide microturbines for use in UTC’s PureComfort combined cooling heating and power (CCHP) and PureThermal hot water products.

CHP plant capable of running on off-specification gas at a northern Russian oilfield. Combustion technologies are being improved to deal with fuel impurities (Opra Gas Turbines)
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Holly Emerson explains: ‘We are also currently developing a combustion system that can handle higher levels of hydrogen than previously. The first 250 kW machine with this fuel- handling capability will be integrated in a pyrolysis plant in western Europe.’

She says that biogas can be run in the same turbines as natural gas, but lower BTU fuels require a different combustor and fuel conditioning.

‘In general, the challenges are fuel variability, moisture and contaminants,’ she explains. ‘We remove moisture and contaminants from the fuel with a combination of siloxane removal, iron sponge and liquid knockout, depending on what is required for the specific application.’

The company is removing siloxanes and moisture at several sites including wastewater treatment plants and landfills. For a 70 kW microturbine it recently commissioned at a 1000-cow dairy farm in New York; it also had to remove hydrogen sulphide (H2S).The farm had a digester in place to convert manure into methane and byproducts, with the methane being burned to produce hot water. Since there was more methane than needed, the excess was being burned off. Ingersoll Rand owns and operates the equipment and sells the power to the farm at a discount. The microturbine can generate about 500 MWh annually while consuming 8 million cubic feet (226,500 m3) of methane, a greenhouse gas which is 21 times as powerful as carbon dioxide (CO2).

Jay Johnson, Ingersoll Rand’s CHP Solutions Manager, says that the company is expanding the range of tools for delivering the heat to customers including hotter hot air, boiler integration and air/air heat exchangers.

As fuel costs rise, the drivers that make heat recovery more appealing also drive adoption of technologies which simply need less heat, he explains. ‘For instance in the paint curing oven design, higher-cost fuel encourages the use if infrared curing technology. We are responding by focusing in on solutions using the hot exhaust itself rather than just extracting the high grade heat from it.’

Opra Technologies ASA of Hengelo, the Netherlands, reports increasing demand for its compact, single-stage OP16 gas turbines that produce 1.5-2.0 MW.

‘We see cogen as a priority area for Opra where we will invest considerable resources in the coming years,’ says Managing Director Fredrick R. Mowill. ‘It is not so much a technology issue but more a matter of combining marketing smarts with creative applications engineering.’

To meet demand, the company will open a new 5000 m2 and headquarters facility in Stavanger, Norway later this year. Its current facility will be used for engineering and packaging of complete generating set solutions. In addition to working to gradually boost the power and efficiency of its turbines, Mowill says that the company is placing a lot of emphasis on developing better combustion technology to deal with the complexities of biofuels, while keeping emissions at a minimum. The company has two turbines running on sour well-head gas at an oilfield in northern Russia that each produce about 1.8 MWe and provide hot water for general facilities use and to heat the pipelines during the winter.

‘I believe that the biofuel market is becoming more interesting and we are well prepared to make the necessary adjustments required to run on off-specification fuels,’ he says. ‘We handle these projects on a case-by-case basis and make modifications to our standard solutions as required.’

Another company getting into the biogas turbine arena is Brückner Biotec GmbH of Siegsdorf, Germany. The company already has plants running that use combustion engines ranging from 20 kW to 1MW. It is designing combustion turbines for CHP use at larger installations.

‘Biogas contains up to 45% CO2 and biogas engines have been adapted to that application,’ says Brückner Biotec’s CEO, Dirk Volkman. ‘We are speaking to suppliers right now to find out which kind of turbine and make best suits our purposes.’

The company is building a 250 kWe R&D facility in southern Germany to test various applications, including the use of biogas in turbines. The goal is to develop turnkey biogas plants in the 1-10 MWe range.

‘Biogas is renewable and can be made from any organic substance,’ says Volkman, ‘Though capital expenditure is still high, prices will come down in the mid term, so this will be an interesting alternative for natural gas production.’

Siemens Power Generation, which makes industrial gas turbines in the 5-50 MW range, has been working on boosting the efficiency of its turbines as well as the range of fuels they can run on. In addition to selling generator sets to customers, the company is concentrating on delivering what it calls ‘Power Islands’ complete, turnkey on-site plants that Siemens operates. In December 2006, it opened its largest such plant to date, a 260 MWe CHP plant in Gothenburg, Sweden. Containing three 45 MW SGT-800 gas turbines and one 141 MW SST-900 steam turbine, it operates at 92.5% efficiency and delivers about 35% of Gothenburg’s district heating demands and 30% of its power. The SGT-800 gas turbine is specially designed for cogeneration applications, and is optimized to exhaust into a heat recovery steam generator for maximum efficiency and minimal heat loss. It is fitted with low NOx burners for operation on both oil and natural gas.

On a smaller scale, Scottish distiller William Grant & Sons uses a 5.25 MW SGT-1000 to produce 5000 kW of electricity and 12,500 kg/hour of 10-bar process steam. The factory uses two-thirds of the electricity and sells the rest to the grid. Because of its efficiency, the distiller receives an 80% rebate on the Climate Change Levy, a UK tax designed to reduce greenhouse emissions.

A new version of Siemens’ largest gas turbine, the SGT-800, has been redesigned to boost its output from 45 MW to 47 MW. This is undergoing final validation and will be released next summer. It will be available as a new unit or as a retrofit to existing GTs.


Getting the most out of a CHP system doesn’t just depend on turbine efficiency but HRSG design as well. Manufacturers such as Alstom and Vogt Power are continually researching new ways to raise the reliability and performance of their equipment. One concern is the ability to respond rapidly to changes in demand. Typically HRSGs are used on baseload units, but increasingly they are being cycled daily or twice a day.

The 5.25 MW gas turbine and HRSG at the William Grant & Sons distillery in Scotland. The system produces 5000 kW of electricity and 12,500 kg/hour of process steam (Siemens)
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‘Startups and shutdowns can be very detrimental to the life of the plant,’ says Tony Thompson, Director of Engineering for Vogt Power. ‘The difference in the thermal growth rates between two materials can cause leakage in the joints and seals, and could cause customers to shut down.’

To reduce or eliminate damage, Vogt has developed methods to retain heat in the boiler so that minimized thermal stress cuts startup time. Thompson says that it normally takes a HRSG around 2.5 hours to go from a cold start to a full load, but if the water is already hot, that time can be cut in half. The Alstom solution includes a design called OCC (Optimized for Cycling Construction) which uses a single row of tubes with a very small header.

‘By using thin pressure parts in the header areas, thermal stress is less than half of what it would be in a typical HRSG, so it survives frequent shutdowns and cold starts,’ says Tom Mastronarde, Alstom’s Chief Engineer for Global Technology Development.

To reduce leakage problems, both companies now use stainless steel, bellows-type boiler penetration seals. Vogt uses a stainless clamshell design PenSeal Plus boiler penetration seals from Expansion Joint Systems, Inc.

‘Because it comes in two pieces, we don’t have to cut into the large expensive piping, but can just put them around the pipe and weld them in the field,’ says Mark Schweikhart, Associate Project Engineer for Vogt Power. ‘Whereas on capital projects – the brand new boilers that we design – we use the EJS one piece seal which can be welded in place as the piping is installed.’

Vogt also sells its customers a new type of PenSeal called the Penetration Slider Seal which clamps onto the pipe rather than requiring welding.

In addition, Vogt and Alston are working with customers on issues related to water impurities and water temperature which result in flow-assisted corrosion. Alstom has switched to mandating that its customers follow certain water quality guidelines. Even so, if the water is not the right temperature, it can still cause problems. Some operators are running their gas turbines at minimum capacity during low demand periods, rather than fully shutting them down. This extends turbine life and reduces startup time, but also means there is not enough heat for the HRSG to operate properly.

‘The most common operating problem in the last two to three years has been customers trying to turn the GTs down as low as possible,’ says Thompson. ‘The boilers were never intended to be turned down that low.’

This can result in pitting of the headers and tubes, and impact damage to the blades in the steam turbine if there is a high level of dissolved silica in the spray water. Thompson says that these can be addressed by redesigning the boiler or adding an additional attemperator. New boilers, he says, are capable of operating down to 50% or 60% of load.


These improvements, coupled with the new burner designs, give operators a wider range of options in building CHP systems that meet their own exact needs. The next few years, however, we are likely to see sizeable changes in gas turbine designs as nanotechnology moves out of the lab and into production. The initial products include corrosion-resistant blade coatings and better lubricants which will provide incremental improvements in performance. The bigger change will come when nano-engineered composite materials become available in sufficient quantities to replace the metals used in the rotors and blades themselves, vastly reducing the tonnage of spinning metal and boosting efficiency and reliability.

Drew Robb is a US-based writer on energy.
e-mail: cospp@pennwell.com