​Asset management – gas turbine power stations: combined cycle steam turbines  ​

This, part 3 of a four-part overview, focuses on the salient asset management aspects of combined cycle steam turbine/generator–exciter units.

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Sep 27, 2017
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Author(s): Douglas Hutchinson


This overview was written primarily with graduates, engineers and electrical, mechanical, chemical, instrumentation and control and computer technicians in mind who wish to enter the power generation industry at large and gas turbine power generating plants in particular, since combined cycle gas turbine power plants constitute the largest output and most efficient turbine power generation stations operating today. 

Combined cycle steam turbine generators (STGs)

Essential basics: The hydro and steam turbines were, and still are, the ‘beautiful machines’ of the power generation industry. The rugged steam turbines have given extremely reliable workhorse service in every power utility or private power generation enterprise worldwide. After World War II, their development went ahead in leaps and bounds. From steam range generating stations having turbo-generators up to 30 MW size category, machine sizes doubled to 60 MW turbo-generator units and soon went into the 100, 200, 275, 300, 350 then onto 500, 660 and 1000–1500 MW capacity range.

Typical outline STG unit, 100–200 MW range

Large output unit configuration was one boiler/one steam and one generator transformer to connect to the station’s high-voltage switchyard. All generating unit electrical power supplies were provided by one unit transformer. The generating unit was designed to be a self-contained, stand-alone electrical energy producer and in extreme grid system circumstances, could operate in stand-alone ‘Island mode’ – supplying its own auxiliary plant and any localised load until re-connected again to the grid at large (see Fig 1) [1,2] .

Fig 1: Typical Steam Turbine generator (STG) unit, 100 to 200 MW range

Typical outline combined cycle STG unit, 200–300 MW range

Showing typical unit electrical supply to unit auxiliaries and interconnection with grid system. See Fig 2.

Fig 2: Typical STG unit, 200 to 300 MW range, showing typical unit electrical layout

Combined cycle STG unit

In Britain coal-fired STG unit sizes went from 60 to 100–120 MW reheat multi-cylinder machines. Subsequently, reheat became the norm for all turbine/generator units above 100 MW and unit sizes escalated to 200, 275, 300 and 350 MW – then upwards to standardise at 500 MW units for coal-fired power stations.

British nuclear advanced gas-cooled and pressurised water-cooled reactor power stations generally standardised on 660 MW turbine/generator unit designs and sizes or thereabouts. Overseas coal-fired unit orders settled on 660–680 MW reheat and these were exported to a number of countries [3–10].

When combined cycle gas turbine (CCGT) units were introduced, as far as the steam power plant manufacturers were concerned – it was take your pick! However, as CCGT units and their associated heat recovery steam generator (HRSGs) became increasingly sophisticated, steam turbine and generator manufacturers found they had to move from standardised units to ‘tailor-made-to-order machines’ to accommodate the newer HRSG designs.

Steam turbine designs have been perfected over many years since power industry inception. Being more rugged in design and whilst working at considerable steam pressures and temperatures (general pressure circa 2400–2500 psig – temperature circa generally between 538°C/1000°F and 541°C/1005.8°F) these temperatures were far less (almost half) the GT ‘flame temperatures’ experienced on GT units. Note: ‘Super-critical’ coal-fired boiler/steam turbine/generator units were also developed for use in the world’s major economies; however, their inclusion has not been markedly increased [10].

Depending on original equipment manufacturer (OEM), plant historical factors and other relevant and not so relevant factors – meant STG required two types of outages:

  • (i) Annual minor (8–14 days) outages.
  • (ii) Major outages can last between 4 and 8 weeks or longer depending on the number of casing and rotor lift-outs for inspection/maintenance that are considered necessary.

Combined cycle steam turbines having installed capacities <60 MW generally drive air-cooled generators. Generator plants above this capacity generally have hydrogen-cooled generators. Usually, both generator types have air-cooled exciter plants. Both air-cooled generators or hydrogen-cooled generators and their associated air-cooled exciter plants dovetail conveniently into their prime mover maintenance frequencies. Thus maintenance outages for STG/exciter units can generally also be accommodated within:

  1. Annual short duration (8–14 days) outages
  2. Major steam turbine outages lasting ∼4–8 weeks.

Also note GT generators and exciter units are the same as their CC ST generators/exciter units. Maintenance wise, they can be dovetailed to fit into GT hot gas path/major inspection maintenance periods.

Depending on design, unit size, locations, running-hour profiles, steam pressure and temperature excursion limits, over-speed incidents, electrical system low-frequency incidents, HRSG boiler drum water level incidents – particularly high water level incidents etc. – all are considered as in the case of gas turbines to formulate a short (annual) or major maintenance outage.

Note: High HRSG boiler drum levels are particularly studied because at high steam pressure conditions – silica is soluble in steam – and silica carry-over during boiler drum high water level excursions, will cool as it passes through turbines stages to deposit very hard scales on HP turbine blades, restricting steam flow and changing blade geometry profiles to sufficiently lower turbine efficiency.

Prudent technical analysis and planning generally determines when and to what extent the maintenance programme will look like, and this together with forward-looking inspection reports and photographs contribute to the final maintenance work list from which, a minor or major outage duration is derived using critical path analysis (CPA) networks.

In the commercial times that prevail, it is commonplace for all maintenance planning to include permit-to-work preparation times, work scheduling, parts delivery and scheduling, contractor and manpower scheduling, scaffolding scheduling, right down to the last nut and bolt levels for all steam turbine/generator/exciter/balance of plant maintenance [3–14].

CC STG unit – maintenance watch areas

Fig 3: CC STG unit – maintenance watch areas

STG Section 1 – STG journal and thrust bearings lubrication

Essential basics: All STGs journal bearings support the HP, intermediate pressure (IP), low pressure (LP), generator and exciter shafts and are forced lubricated from a central lubricating oil storage tank and forced lubricating oil filtration/pumping/and cooling system.

Turbo-generator machinery having very heavy shafts (say) 250 MW machine – HP/IP rotor weight would ∼20 t and the weight of each LP rotor would ∼40–45 t. These heavy shafts require superb lubricating oil systems which generally consist of:

  1. Main lubricating oil tank – assume 250 MW unit – tank capacity = ∼35,000 l.
  2. 2 × AC lube-oil pumps.
  3. 1 × DC lube-oil pump.
  4. 1 × Start-up HP lube-oil pump.
  5. Turbine shaft-driven main oil pump – pump takes over lube-oil duties when turbine reaches near synchronous speed and maintains all services whilst the turbo-generator remains in service.
  6. Minimum of three off lube-oil coolers (for STGs invariably water cooler).
  7. One off lube-oil purifier plant system.
  8. Lube-oil filtration plant system + magnetic filters at all bearing oil outlets.
  9. Turbo-generator jacking oil system.
  10. Designed interconnections with generator hydrogen seal oil system.

The above lubricating oil system provides the necessary closed loop, forced circulation, lubricating oil system for most types of turbo-generator machinery.

Combine cycle or any other turbo-generator machine operations – starts and ends with the lubricating oil system. It is the first plant system to be put into service from turbo-generator standstill, remains in operation throughout all running operations and is the last plant system to be shut down after turbo-generator machine operations cease and shafts return to standstill [15–17].

STG Section 1 – steam turbine/generator/exciter bearing positions

Fig 4: STG unit bearing positions

STG Section 1 – thrust bearing position

Thus in ‘reheat’ steam turbines, the thrust bearing is always positioned between the HP and IP turbines keeping thrust bearing sizes and lubricating oil cooling supplies at minimum levels consistent with thorough lubrication for mechanical thrust loads (see Fig 5).

Fig 5: STG thrust bearing position

STG Section 1 – steam turbine power oil

Essential basics: This system is started by a HP power oil electrically driven pump. Once the turbine shaft is running at synchronous speed, a turbine shaft-driven main power oil pump takes over the power oil supply system and usually, the automatic shutdown of the electric power oil pump. The power oil system operates the turbine steam admission and governor valves.

Reason: On any de-pressurisation or complete failure of the lubricating oil system, the turbine valves will immediately slam shut to protect and minimise damage to turbine/generator bearings and the overall generating unit.

Diagrammatic layout to indicate the basic principle of operation of spring loaded steam admission and governor valves

Power oil pressure opens steam admission and governor valves. Reducing lubricating oil pressure or failure of oil pressure for any reason, spring loading immediately shuts all turbine steam admission and governor valves thus protecting the turbine generator unit as far as possible (see Fig 6).

Fig 6: Illustration basic principle of operation of spring loaded steam admission and governor valves

STG Section 1 – steam turbine/generator/exciter unit jacking oil

Essential basics: STG shafts are very heavy – depending on unit MW size and design, generator rotors can weigh between 60 and 80 t.

Turbo-generator shafts cannot be turned unless these heavy shafts are lifted from the white metal lined journal bearings and an adequate lubrication oil supply is established.

High pressure (HP) (1000 psig) lubricating oil from the Shaft Jacking Oil pump station is used to hydraulically lift the turbo-generator shafts in the bearings prior to manual turning or prior to engaging the turbo-generator shaft turning gear or barring gear (B/G) facility – thereby establishing an adequate oil film around the shaft before the shaft can be turned for any reason or before starting the turbo-generator turning or B/G.

Schematic layout gas turbine generator (GTG) and STG journal bearings showing jacking oil inlet to each bearing to raise shafts prior to any rotation

The oil emerges at HP from machined orifices in the white metal lining of the bearing at the bearing ‘bottom dead centre’ line, thereby lifting the heavy turbo-generator shafts and creating an oil film of sufficient thickness between the shaft and the bearing white metal prior to rotating the machine for any reason maintenance, operational or otherwise. The establishment of a sufficient oil film reduces the chances of the bearing surface being damaged during initial turbo-generator shaft turning on B/G and subsequent turbo-generator machine start-up or during turbo-generator unit shutdown (at 25–50 rpm) before turbine/generator/exciter shafts come to rest [15–17] (see Fig 7).

Fig 7: Schematic jacking oil inlet to each bearing to raise shafts prior to any rotation

STG Section 1 – ST generator seal oil

Essential basics: After extensive research, when generator unit sizes jumped to 100–120 MW mark and above, hydrogen was chosen as the prime generator coolant because:

  • (a) it had a thermal conductivity equivalent to almost seven times that of air – allowing faster heat transfer and an enhanced cooling capability;
  • (b) pure hydrogen will not support combustion – hence there is a reduced fire risk within the pure hydrogen filled generator;
  • (c) hydrogen will not support corona – this increases the life of generator insulation;
  • (d) the exclusion of air (moisture/humidity/dirt/atmospheric pollutants) also increases the life expectancy of generator stator and rotor insulation materials;
  • (e) increased hydrogen pressure has been found to suppress partial discharges within the generator thus further reducing maintenance and increasing insulation life expectancy;
  • (f) hydrogen being lighter than air – reduces generator rotor friction and windage losses.

Lubricating oil was selected for hydrogen sealing within large output generators because:

  1. it was the most obvious, most suitable, and readily available hydrodynamic sealing material available on a turbo-generating unit;
  2. seal oil systems use turbo-generator lubricating oil (suitably treated) as the sealing medium;
  3. large output generators run with hydrogen pressures within the range of 3–5 bar (g) max 43.5–72.5 psig max (300–500 kPa max) for effective cooling;
  4. seal oil pressures are automatically regulated to ensure a seal oil pressure ‘differential’ is created to always be above hydrogen (H 2) pressures. Seal oil pressure is always greater than H 2 pressure;
  5. the generator shaft exits from the stator frame (at both the front and rear ends) and must be sealed close to, and just inboard of, the bearing journals where the shaft diameter is at a minimum – but where the shaft surface speed can be considerable. This is too fast for any form of contact or rubbing seal – thus, a lube-oil hydrodynamic seal was fixed upon [18].

Owing to hydrogen entrainment in sealing lube-oil – the seal oil treatment packages include seal oil filtration, de-watering and hydrogen detraining and removal from the closed-loop seal oil system.

  • Note 1: The seal oil system has its own dedicated AC seal oil pumps, back-up DC seal oil pumps and generally there is an additional turbine lubricating oil emergency seal oil supply system with seal oil regulating control valves to always keep seal oil pressures above generator hydrogen pressure within the correct differential pressure ratio.
  • Note 2: Always the seal oil pressure must be above the hydrogen gas pressure in the generator stator frame. As hydrogen pressure is increased for generator full power output, so an automatic increase of seal oil pressure to maintain the seal tightness is regulated and maintained.
  • Note 3: The operation of hydrogen-cooled generators requires very careful attention, since hydrogen and oxygen (air) is an explosive mixture – the air initially in the generator is purged with inert carbon dioxide (CO 2) which is then purged with hydrogen.

To perform maintenance anywhere within the pressure parts system of the generator demands the hydrogen be purged with inert CO2 which is then removed by air. Hydrogen and CO 2 fixed and portable monitors are used to ensure it is safe to work on generator seals or any other generator internals.

Diagrammatic layout H 2-cooled generator seal oil system

To ensure lubricating oil quality, the turbo-generator lubricating oil installation carries permanent oil purification equipment, permanent oil filtration banks and also magnetic oil filters, thus maintaining as far as possible, the quality of lubricating oil supplied to the generator seal oil system and hydrogen seals (see Fig 8).

Fig 8: Diagrammatic layout H2 cooled generator seal oil system

STG Section 2 – layout positions – ST HP and IP turbine steam admission and governor control valves

See Fig 9.

Fig 9: Layout positions – turbine steam admission and governor control valves

STG Section 3–5 – HP, IP and LP turbines

Illustration – small output combined cycle STG. Smaller, single cylinder steam turbine (say) circa 1.5–40 MW generator units accept combined cycle steam from their HRSG steam outlets and through appropriate steam admission and governor valve installations admit steam into the smaller steam turbine/generator/exciter unit (see Fig 10).

Fig 10: Illustration – small output CC STG layout

Depending on design, the smaller turbine exhausts into either an under-slung or in-line condenser. The smaller turbine directly drives the air-cooled generator–exciter unit (see Fig 10).

Fig 11: Typical CC STG unit, 200–300 MW range

Steam turbine designs accommodating HRSG reheat facilities have their thrust bearings always positioned between the HP and IP turbines thus keeping thrust bearing sizes and lubricating oil, and lubricating oil cooling supplies, at minimum levels consistent with thorough and safe lubrication for mechanical thrust-bearing loads.

The advent of reheat in HRSG installations means a duplicate set of steam admission and governor valves (designed for reheat steam pressure and temperature conditions) for the IP turbine because of the considerable quantity of steam entrained in the reheater sections, which is more than enough to overspeed the steam turbine/generator shafts.

Typical outline – CC multi-cylinder STG unit, 200–300 MW range

Whereas gas turbines must rigidly adhere to running hours and number of starts maintenance regimes, HRSGs and combined cycle STGs and all associated balance of plant does not require quite such a rigid maintenance system (see Fig 11).

Steam turbines offer far better minor/major overhaul options. Clearly, workplace law, OEMs recommendations, national standards, power purchase agreement contracts intricacies and insurers requirements together with the plant owners’ requirements need review – and all things being equal – HRSG/combined cycle steam turbines/generator–exciter units and all their associated balance of plant can be inspected and maintained within gas turbine combustion inspection, hot gas path inspection and major inspection overhaul programmes. In CPA terms, the gas turbine repairs would occupy the critical path, all other maintenance would be completed by the time the GT work is completed. All would be re-commissioned together and the entire CCGT unit would be re-started.

Thus degrees of flexibility generally exist for STG plant and STG balance of plant to be maintained whenever scheduled gas turbine maintenance outages permit. Clearly, major unscheduled maintenance on STG plant can render GTG shutdown in certain circumstances and that is why on smaller CCGT installations, HRSGs can be shut down and their associated gas turbines can be run on open cycle for short periods subject to the national emissions approvals system [21].

It is worth noting that although the extremely reliable steam turbine/generator sizes leapt upwards, generally speaking their maintenance frequencies did not change substantially, if at all! – hence the beautiful machine name-tag!

Depending on OEM designs – steam turbine minor inspections and maintenance is generally conducted on an annual or bi-annual, short duration 8–16-day shut downs, whilst major inspections and overhauls last from 4 to 8 weeks and are performed once every 4–7 or even 8 years, depending on operational history, insurance, industry standards etc.

That said, steam turbine operation utilising GT exhaust powered HRSGs, means steam pressure raising rates and on-line running steam temperature and pressure control demands extreme operational care and attention. Extensive and intelligent use of steam tables is mandatory during start-up and shut down.

In a CCGT unit, gas turbine exhaust powers the HRSG which, in turn, provides the steam quantities and the steam pressures and temperatures required to match steam turbine start-up, running and shut down in all weathers, anywhere on the planet in hot, warm and cold machine thermal conditions:

  1. In CCGT units, steam turbine HP, IP and LP steam pressures and temperatures and quantities are primarily controlled by gas turbine exhaust temperature and gas mass flow.
  2. If steam temperatures are (say) too high (above ST rotor and casing metal temperatures) when starting the steam turbine train – in either the hot, warm or cold turbine conditions – severe heating of rotor and stator will subsequently occur and bring about severe rotor and casing metal expansions. Since the mass of the rotors are much lower than that of the associated casings, and since the rotors revolve in an atmosphere of steam they, (the rotors) absorb heat and expand more rapidly within their stator casings.
  3. This differential expansion between rotors and casings is a major control factor when running steam turbine trains. Both HP main steam and reheat IP steam temperatures must simultaneously be controlled to initially match the HP and IP rotor metal temperatures – but possess a sufficient degree of superheat to ensure condensation cannot occur inside the turbine casings. Steady, controlled heat input to the turbine rotors and casings are mandatory for controlling and minimising the differential expansion that occurs in every instance and on every occasion.
  4. HP and IP rotor expansions must be contained within their respective casings. Failure to control HP steam temperatures and reheat steam temperatures leads to HP and/or IP turbine axial ‘rotor rub’ with potentially disastrous consequences.
  5. As HP, IP and LP turbine casings and rotors expand simultaneously – overall turbine expansion occurs – and thus, gas turbine operation must be controlled in order to always contain steam turbine rotor expansions within their casings. See and study steam turbine OEM prescribed alarm settings for all differential expansion limits.
  6. Combined cycle and all other large output, multi-cylinder steam turbines require constant surveillance and attention to managing main and reheater steam temperature control in order to control HP and IP turbine differential expansion and to a lesser extent, simultaneously control LP turbine rotor and casing expansions.
  7. Combined cycle, large output, multi-cylinder LP turbines also experience differential expansions between the LP rotors and their casings, however the expansion travel limits are much greater than those of the HP and IP turbines. Constant differential expansion surveillance is required during all start-up and shut-down operations.
  8. Large output, multi-cylinder HP/IP/LP turbines/generator – exciter units are rotating machines. As such, shaft alignment, bearing oil inlet, outlet, bearing metal temperatures and bearing vibration levels are – together with turbine rotor eccentricity (within their casings) and differential expansion (within their casings) – of paramount importance and absolutely governs all steam turbine operation [19–21].

STG Sections – 6 and 7 generator and exciter units

Combined cycle steam turbines drive two basic types of generators:

  1. Air-cooled generators: These generators use air cooled exciters.
  2. Hydrogen-cooled generators: These also invariably use air-cooled exciters – only in rare exceptional circumstances are hydrogen-cooled exciters specified and used.
  1. Generally, STG sizes below 60 MW are air cooled. Larger air cool generator installations are used to a lesser extent. The filter/water cooler installations are generally located below the generator/exciter units.
  2. In general, STG sizes above 60 MW, hydrogen-cooled generators and air-cooled exciters are used. Historically, since hydrogen cooling came after air cooling, generator designs became very much more compact such that the hydrogen cooler installations became an integral part of the overall generator casings.

Cooled hydrogen from the H 2 coolers which are embodied within the generator casing is circulated into and throughout the generator stator and rotor windings; heated hydrogen is channel back to generator water coolers for cooling before re-circulation back into the generator stator and rotor windings. Generator rotor shaft mounted LP fans continuously circulate hydrogen gas throughout the generator stator and rotor windings.

Hydrogen under pressure in the generator casings has to be sealed within the generator casings and this is accomplished by hydraulic sealing arrangements utilising turbo-generator lubricating oil [ 22 ].

The essential basics is listed in the final Part 4 of this CCGT asset management overview which deals specifically with generator/exciter units.


  1. GEGB modern power station practice’ (1963), vol. 3, p. 10.
  2. GEGB modern power station practice’ (1964), vol. 5, p. 10.
  3. http://en.wikipedia.org/wiki/Nuclear_Power_in_the_United_Kingdom.
  4. https://en.wikipedia.org/wiki/Castle_Peak_Power_Station.
  5. http://www.eskom.co.za/sites/heritage/Pages/Duvha.aspx.
  6. CEGB modern power station practice’ (1963), vol. 2, p. 129 Table 6.
  7. CEGB modern power station practice’ (1963), vol. 3, p. 83.
  8. CEGB modern power station practice’ (1964), vol. 5, p. 195.
  9. http://www.power-eng.com/articles/print/volume-113/issue-7/features/supercritical-plants-to-come-online-in-2009.html.
  10. ‘Super-critical’ coal fired boiler/steam turbine/generator units. Available at https://en.wikipedia.org/wiki/Supercritical_steam_generator.
  11. http://www.hse.gov.uk/comah/sragtech/techmeaspermit.htm.
  12. www.theiet.org/factfiles/health/hsb33-page.cfm?type=pdf.
  13. https://en.wikipedia.org/wiki/Permit_To_Work.
  14. The Directorate of Human Resources. Available at https://www.brookes.ac.uk/services/hr/health_safety/permit_to_work/procedure.html.
  15. https://canteach.candu.org/Content%20Library/20051017.pdf.
  16. http://www.marineinsight.com/tech/generator/starting-procedure-for-turbine-generator-on-ship/.
  17. https://www.quora.com/How-turbine-oil-system-work-in-power-plant.
  18. CEGB modern power station practice’ (1963), vol. 3 – Table 4; Also Table 7, pp. 212, 230. item 18.8 Future Trends.
  19. http://www.aph.gov.au/About_Parliament/Parliamentary_Departments/Parliamentary_Library/pubs/BN/1011/PerformanceStandardsemissions.
  20. https://www3.epa.gov/ttncatc1/dir1/gasturb.pdf.
  21. http://www2.dmu.dk/atmosphericenvironment/expost/database/docs/elv_combustion.pdf.
  22. CEGB modern power station practice’ (1963) vol. 3, Table 4; also p. 212, Table 7, p. 230 sector and 18.8 Future Trends. Available at https://en.wikipedia.org/wiki/Turbo_generator.
Go to the profile of Doug Hutchinson

Doug Hutchinson

Director, Power Generation Services Pty Ltd

Career achievement, - working as Power Company Operations Manager on the US$ 540 million, 700 MW, joint venture, Shajiao 'B' power generation project in Guangdong Province PRC, the World Bank / IFC came to study the project and Doug was later asked to write and present a paper to The World Bank / USAID organisations for their " Private Sector Power in Asia" conference held in Kuala Lumpur, Malaysia, on 27 - 29 October 1992 covering the private power experience in China. Author – Central Electricity Generating Board – A Method Study Approach to Power Station Operation. Author - IET Eng/Ref - Overview, Asset Management, Gas Turbine Power Stations. STEM Ambassador – UK

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