Gas turbine CHP O&M in practice experience from the UK, Canada, Sweden and Germany

CHP plants based on one or more gas turbines have been installed in a wide variety of applications in many countries. But what are these plants like to operate? James Hunt talks to owners and operators of plants in four countries to find out about performance, reliability, servicing and operational patterns

Anywhere that you find industrial-scale CHP plants, and even some CHP plants serving buildings, you will find gas turbines à‚— as well as the other main prime mover used for CHP, reciprocating engines. Gas turbines are manufactured by a small number of truly international companies, and have been applied in countries around the world. This article looks at the operation of turbine-based plants in Canada, Sweden and Germany à‚— but starts with a look at one UK operator.

Cogeneration (CHP) plants now generate more than 6% of the UK’s total electricity needs. By 2010, as part of its climate change strategy, the UK Government expects the CHP capacity in the UK to increase to 10 GW. Despite the fact that properly designed and operated cogeneration plant can reduce a plant’s total fuel consumption by 12% or more, some plant owners say that, without greater incentives from government, building new CHP plant in the UK today is simply not economically viable. Bearing these points in mind, what is it like to operate gas turbine-powered cogeneration plant?

The Rolls-Royce Trent gas turbine powered CHP plant at Whitby,à‚ Ontario. Its reliability is now ‘in the top bracket for Northà‚ America’
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Take E.ON UK CHP, which owns and operates the cogeneration interests of E.ON UK, the leading German-owned integrated power and gas company. Cogeneration is important to E.ON, as it is part of the company’s low carbon strategy and, as one of the largest owners of a wide range of power generation plant in the UK, it has invested over à‚£480 million (US $941 million) in 14 UK CHP schemes. These collectively provide more than 577 MW of electricity and 948 MW of heat.

The plant is quite varied. At the smaller end of the scale is the à‚£3.5 million (US $6.7 million) CHP scheme in Bradford. This provides electrical power and up to 25 tonnes of steam/hr to chemical processing company AH Marks under a 20-year contract period. The scheme comprises a 4.5 MW gas turbine plus supplementary/auxiliary fired waste heat recovery boiler, fired to match site demand without needing the standby boilers.

Another plant generates 25 MW of electricity and over 90à‚ MW of steam (70 tonnes/hr for manufacturing processes from four waste heat boilers) for ConocoPhillips’ modern Humber refinery. The CHP plant, in this case, is owned by ConocoPhillips, but is operated and maintained by E.ON. It comprises four gas turbines with back-up systems to ensure continuous running, even when primary gas supply is unavailable.

At the other end of the scale, the CHP plant in Northwich, Cheshire, is one of the largest in the UK, and can supply 500à‚ tonnes of steam/hr, plus 130 MW of electricity to two Brunner Mond soda ash works. The main CHP plant consists of two gas turbines, two heat recovery boilers and a steam turbine. Stand-by boilers provide supply security.

The Kemsley CHP plant à‚— one of 14 operated by E.ON UK CHP
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Colin White is E.ON UK CHP’s maintenance and planning manager. He said that the company’s cogeneration business is 95% gas turbine powered, and that some of the plant dates back to PowerGen days. All are still running reliably, but several no longer run in cogeneration mode because their original customers have gone out of business or changed their requirements. These plant now run combined cycle to the grid à‚— the 56 MWe GE LM6000PD-powered Castleford CHP plant is just such a case.

E.ON’s various CHP plant use gas turbines from several manufacturers. These include GE LM6000s and GE Frame 6Bs, Rolls-Royce RB211 aero-derivatives, Siemens SGT 800s, plus Siemens Tornados and Typhoons. He also said that aero-derivative machines, being smaller and rotating faster, need a higher standard of maintenance. Even so, said White, any problems tend to come from the package (for example the lube oil systems, pumps, valves and the like) rather than the gas turbines themselves.

Inside another E.ON CHP plant (Speke, Merseyside, UK). The company says it has great expertise with the maintenance requirements of larger industrial gas turbines
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The main air filters must typically be replaced every three years, and the pre-filters annually. Electronic monitoring of inlet-differential pressure changes over each stage keeps an eye on filter condition to maximize turbine performance and life. In any case, the company is gradually replacing existing air filters with Class H types, which increase efficiency, reduce carbon emissions and help keep down time to a minimum.

The company’s CHP plants are natural gas-fuelled, though some have a distillate gas back-up capability. This may change in the future, as rising natural gas prices can significantly affect profitability, depending on whether the supply contract is base rate or fixed-rate based. There is one exception, that of the CHP plant supplying the ConocoPhillips Humber refinery. Its four Typhoon/Tornado gas turbines burn refinery distillate gas. Some E.ON plant uses biofuels, but not the CHP plant. The company generally prefers to incorporate bio-fuelling into larger new plant, rather than retrofit. There have been a few fuel problems caused by high sulphur content; but, this is believed to have been caused by insufficient gas pre-heating, and is being addressed.

The plants use heat recovery steam generators (HRSGs), usually made by the turnkey plant manufacturers. Auxiliary / supplementary firing is usually used to take account of varying demand, so increasing plant flexibility. The HRSG equipment has been very reliable, reports Colin White. They don’t even need much cleaning with natural gas as the fuel. However, he said, if a plant is frequently cycled for supply flexibility, there can be a higher incidence of tube and header leaks.

E.ON has great expertise with the maintenance requirements of larger industrial gas turbines, said White, and ‘we sometimes challenge the OEMs about maintenance and other issues. We now often use third party manufacturers too’. He pointed out, though, that CHP plant using aero-derivative gas turbines can be more demanding of OEM expertise, and ‘we may defer to them in the short term, but are working towards an independent strategy, similar to our fleet of larger gas turbines’.

Finally, while cogeneration is important to E.ON, new plant is not currently being built because there is little incentive from government. It is not commercially viable, even though the plant itself is highly thermally efficient. E.ON, and other power firms, continue to lobby the UK government.

Successful CHP introduction for Rolls-Royce’s Trent

The first industrial application for the Rolls-Royce Trent gas turbine was for a 51.2 MW baseload cogeneration plant in Whitby, Ontario, Canada, for Whitby Cogeneration. Installed in 1998, the engine used is a natural gas-fired Trent 60. The Trent, designed for both the peaking and baseload markets, is an aero-derivative development of the RB211 family, delivering over 70,000 hp at up to 42% efficiency. It sets, says Rolls-Royce, a ‘new benchmark for fuel economy, and it meets stringent NOx and CO requirements. In addition to operating synchronously at 3000 or 3600 rpm for the 50 or 60 Hz power generation market, the Trent 60 can be used for variable speed operation with a speed range of 70%à‚—105% speed (100% speed is 3400 rpm).

The Rolls-Royce Trent powered CHP plant at Whitby, Ontario
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The Whitby cogeneration plant, which also works simple cycle when required, comprises a gas turbine and generator that provide electric power to the provincial power authority, plus a Steam Technologies single pressure once-through steam generator (OTSG), which provides process steam for a nearby paper processing plant.

The gas turbine’s waste heat passes to the OTSG to generate the required steam. Being ‘once-through’, no steam drum or blowdown system is needed, so turbine bypass stack, diverter valve or stack silencer are also not required. The gas turbine’s exhaust heat generates up to 83,000 kg/hr (183,000 lb/hr) process steam at a net plant heat rate of 5250 Btu/kWh without duct firing (65% efficiency).

A Rolls-Royce gas turbine installed à‚— doors open for access.
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The plant is operationally flexible because the steam needs vary according to plant demands. The season also makes a significant difference in Canada, due to the widely different winter and summer temperatures. At full gas turbine baseload output, the plant produces a cogeneration heat rate of approximately 5400à‚—5700 Btu/kWh in summer à‚— this represents a 63%à‚—60% efficiency à‚— and 5600à‚—5800 Btu/kWh with an efficiency of 61%à‚—59% in winter. In simple cycle operation (generating electricity only), the plant is rated at 51.2à‚ MW (40.2% efficiency). Supplementary firing is used when more process steam is required. With duct firing, 82,550 kg/hr (181,992 lb/hr) of process steam is produced by the OTSG at 204à‚°C, and 59,874 kg/hr (132,000 lb/hr) without it.

The paper recycling plant can generate its own steam using two back-up auxiliary packaged boilers. Therefore, if the gas supply becomes too expensive from time to time, Fabio Schuler, P.Eng., plant manager at Whitby Cogeneration, sometimes finds it more profitable to shut the plant down and sell gas (which has been paid for in advance) rather than electricity. He also pointed out that, as the steam demand from the paper plant has decreased a little, he sells spare electrical capacity on the spot market when required.

Rolls-Royce doesn’t only supply the aero-derivative Trent à‚— its Avon 200 is a significantly upgraded version of the highly successful industrial gas turbine
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From the outset, the Trent 60 was fitted with a dry low emissions (DLE) system, designed to provide less than 25 ppm NOx/2 ppm CO at full power. However, initially combustion noise restricted the engine from operating at full power, so the plant had to be de-rated until a fix was found, which took nearly two years. Today, both gas turbine and DLE system have run reliably and successfully at full baseload rating since 2003, as has the whole plant. Indeed, since 2000, the plant achieved around 96% reliability, increasing to 99.7% in 2007, with up to 96% availability. The reliability is now ‘in the top bracket for North America’ according to Fabio. Fired hours run/year now average over 7000 (7800 in 2007), and the total hours run to date is over 64,000.

The Trent 60 boasts a rapid engine maintenance time and up to 4000 starts without overhaul. At Whitby Cogeneration, Fabio Schuler carries out routine maintenance once a month, but has some ‘flexibility’ in this. Rolls-Royce has a long-term service agreement (LTSA) to provide site and factory support for the gas turbine, with an option for a further six-year renewal in 2010. The scope of services covers trained personnel to plan and supervise all scheduled and unscheduled on-site gas turbine maintenance, spares, plus supervision of any engine removal, installation and commissioning. Also included is 24-hour technical support. Maintenance also covers remote monitoring, and this includes regular borescope inspections (mainly to the hot section). Hot section repairs are scheduled at 25,000 hour intervals, but a major inspection and complete overhaul is carried out after 50,000 operating hours. A backup gas turbine is available to replace the contract engine temporarily when that is removed for overhaul.

Large new Gothenburg cogeneration plant

A cogeneration plant in Gothenburg, Sweden, is too new to provide meaningful operational trends, but does show how careful specification and modern requirements and design can have a significant impact on operation.

Turnkey contractor Siemens built the Rya plant. This gas (and steam) turbine-powered district heating system is the city’s biggest environmental project ever, and one of the largest such plants in Scandinavia. Despite the increase in power production in Gothenburg, emissions of acid pollutants, sulphur and nitrogen oxides are actually lower. Natural gas is the primary fuel, but biogas or syngas may be used in the future. Selective catalytic reduction (SCR) reduces nitrogen oxide (NOx) emission to well under 20 mg/MJ, operating on natural gas à‚— so there is no ash either. This plant meets around 35% of Gothenburg’s district heating demands and 30% of its power requirements with very high thermal efficiency (to 92.5%).

The plant is extremely flexible because it uses three gas turbines instead of a single large one, and also because supplementary firing can be used with the HRSGs to maximize power production at any heat production rate. Optimized for district heating, this plant has a very high heat recovery à‚— that from the lubricating oil alone results in a 0.5% increase in efficiency (representing an extra 3 MW produced, enough to heat 250à‚—300 extra homes).

The Rya plant is monitored remotely, and the operations monitoring system for the whole of Gothenburg’s district heating is located at the Sàƒ¤venàƒ¤s operations management centre. The local Rya plant control system for the combined cycle equipment is also controlled remotely from Sàƒ¤venàƒ¤s. The distributed and redundant control and monitoring system is integrated into the Sàƒ¤venàƒ¤s system, and decisions can be made regarding plant operation based on data from it.

The Rya plant’s load range is 20%à‚—100% of maximum heat production, and the balance between power and heat production can be varied. This high flexibility not only means easy adaptability to varying heat loads and outdoor temperatures, but also ensures security, even under difficult circumstances. Normal working includes:

  • Island operation à‚— this allows electricity production for parts of the power grid in Gothenburg without having to be connected to the national grid.
  • The plant can supply itself and run idle without supplying power or district heating, independently of any external power supply.
  • If the external power supply fails, the plant can still be started up.

Siemens is responsible for maintenance of the gas and steam turbines, and the control and auxiliary systems. The company provides training, on-site assistance and telephone support

CHP for Kassel industry and district heating

In Kassel, Germany, a cogeneration plant generates electricity, as well as supplying heat to both industry and the city’s 100 km domestic district heating scheme. This city-owned plant comprises a 21-year old 10 MW GE heavy-duty gas turbine, and a second 30 MW GE aero-derivate gas turbine. The latter was installed as an addition to the first machine in a 2005 plant modernization carried out by Tognumà‚—MTU. These two machines exhaust into 40 bar pressure/485à‚°C temperature heat recovery boilers (535à‚°C gas turbine exhaust down to 80à‚°C at boiler exit) to provide steam for a single 10 MW BBC (now Siemens) steam turbine. Overall, the power to heat ratio is 1:1, so that à‚— of the total 100 MW à‚— 50 MW goes to electrical power generation, and 50 MW goes to district heating. The old part of the plant as a whole was designed and built by BBC. There is also a trigeneration aspect, currently small but growing, which is used for industrial air-conditioning, and also in a shopping centre.

The Tognumà‚—MTU modernized CHP plant in Kassel, Germany
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Natural gas is the fuel, although Heinz-Helmut Faulstich, Vice Director of the Kassel plant, said that the older gas turbine was originally liquid natural gas (LNG) fuelled. The natural gas is pre-heated, as it can contain elements of liquid gas which could have too much energy for the combustors. The original gas turbine uses steam injection to improve exhaust emissions, but the nearly new GE machine doesn’t need such treatment as its emissions are so low from the outset. Faulstich said that the air filters are not cleaned. Instead, pressure differentials are electronically monitored, and the elements are changed when dirty à‚— usually every three years (annually for the pre-filters).

The Kassel CHP plant has a maintenance contract with the Tognum subsidiary MTU Friedrichshafen. Its service partner, MTU Maintenance Berlin-Brandenburg, operates worldwide and is licensed by GE to perform major overhauls and repairs on industrial (and aviation) gas turbines. Under the terms of this contract, scheduled maintenance is carried out twice a year, taking four days in total. Every 25,000 hours, the combustors and other hot-side HP side components are changed completely. Under this operating regime, the plant runs, on average, 5600 hrs / year at full load; more at smaller loads.

In 2007, one gas turbine developed an oil leak between centre stages. This necessitated a strip down, but MTU is confident that the same problem will not occur again. Since July 2007, the plant has been 100% reliable, and Heinz-Helmut Faulstich is very satisfied with the plant’s operation. In any case, MTU guarantees 95% availability.

Remote monitoring and predictive maintenance

Various gas turbine OEMs have been experimenting with remote data collection over some years now. Siemens Power Generation is one example, having first connected a modem to the Rustronic MkII turbine control system in 1993. Today, much more developed systems are routinely used on gas turbines and plant equipment to help plant owners and operators achieve maximum performance, reliability and availability. Very often, problems in the making can be fixed before any real damage occurs, saving a great deal of money. The historic data, plus the ability to provide remote assistance, allows gas turbine OEMs to advise customers on the best course of action to take in order to alleviate unnecessary down time.

An MTU supplied gas turbine being ‘packaged’
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For example, a gas turbine developed a vibration problem following routine shutdown. After several days of running with increasing vibration, the control system automatically shut the engine down. Following shutdown and a restart, the vibration levels increased to almost twice their previous normal levels, and the predictive trender reported that a shutdown could be expected anytime in the next four days. The customer then experienced four running trips caused by high vibration.

To avoid the risk of generating primarily false alarms, the gas turbine manufacturer met with selected users and determined the rules necessary to decide when alarms should be raised. As a result, the diagnostic system alarms were automatically relayed into the SAP business system, requesting the technical support help desk investigate the problem. Also, the relevant manager was emailed to advise him. Between them, they decided that an engineer should be sent to site to investigate further, and it was found that the worst vibration levels were reported during reduced-load running; full load resulted in only an almost imperceptible increase. A second visit included a vibration survey, and this allowed the vibration trip and alarm levels to be temporarily raised to prevent unnecessary trips. This allowed the customer to continue operation to a routine service, when some wear was found on the reverse side of the inlet bearing journal pads. The bearing was replaced and the customer experienced no more problems.


The cogeneration plants covered in this article vary widely in terms of country of origin, technical arrangements, size, rating and customer type, and also in the ways that their electricity and heat are used à‚— especially the heat. Also, some are new, or relatively so, while others are now a decade or two old. Yet all seem to have fulfilled their designated roles admirably, despite the fact that in a few cases their original rationale has disappeared, usually because the main customer has reduced its heat/electricity requirements or gone out of business.

For the most part, these plants have been thoroughly reliable, especially the gas turbines themselves. If there has been any significant plant trouble at all, it has not generally been in the steam or electricity generating side. Rather, most problems, generally relatively small, have been in the plant accessories and related equipment. As long as these power units are carefully serviced in line with their OEM’s recommendations (and often serviced by the OEMs themselves), their reliability has been impressive, availability always high, and their lives long. Even though the gas- or bio-fuelled reciprocating engine has made significant inroads, partly because of its greater operational flexibility, even here gas turbines are significantly better than they used to be. In terms of performance, gas turbines are ideal for many cogeneration applications.

James Hunt is a UK-based writer on energy and electrotechnical issues.

Long-term servicing

Long-term service agreement (LTSA) contracts typically include an availability guarantee with liquidated damages applying if the gas turbine genset falls short in any year the LTSA applies. Typically, the gas turbine manufacturer will have responsibility for the overall maintenance of the gas turbine package, with the plant operator (and often the owner) covering all maintenance on the balance of plant.

The number of plant service personnel will vary according to the size and complexity of the plant. Typically, however, for a plant of around 50à‚ MW, it might be 10 experienced staff, some of whom can fill in for each other if required. In addition, there will be around four operators and three maintenance technicians, for balance-of-plant servicing, plus supervisory operators on site at all times. These employees will operate the plant, carry out routine maintenance services, and supply the on-site manpower for scheduled and unscheduled gas turbine maintenance events, as well as engine installation and removal à‚— the latter under the supervision of the gas turbine’s manufacturer.

A typical major gas turbine overhaul involves stripping down, followed by inspection of combustors, nozzles, guide vanes, compressor blades and discs, turbine blades and discs. Replacement or refurbishment of such components is carried out as required, either because of normal wear, or damage, or in terms of life-limit restrictions.

A small plant example

A recent example of a small cogeneration plant is the William Grant & Sons Distillers operation in Scotland. By investing in a Siemens SGT-100 gas turbine powered CHP scheme, the company significantly reduced and stabilized its energy costs and, in the five years or so since the CHP plant was installed, the initial capital investment has been completely recovered through savings in fuel and operating costs. Moreover, the high thermal efficiency achieved (84%) entitled Grants to an 80% rebate on the UK Climate Change Levy, a scheme designed to reduce greenhouse gas emissions. Excess electricity can be exported to the local grid network. This flexibility ensures operation virtually always at maximum efficiency. Should the grid connection fail, the cogeneration scheme will continue to operate independently.

Installed in 2001, the unit had already accumulated over 25,000 hours by 2005, and it operates 24/7 for 50à‚ weeks a year, with just two weeks’ annual shutdown, allowing Siemens to carry out maintenance. A long-term maintenance contract covers the gas turbine generator package.

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