Heavy Duty Maintanaice Gas Turbine Frame 9

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GE Power Systems Heavy-Duty Gas Turbine Operating and Maintenance Considerations Robert Hoeft, Jamison Janawitz, and Richard Keck GE Energy Services Atlanta, GA GER-3620J

description

Heavy duty maintenance Gas Turbine Frame 9

Transcript of Heavy Duty Maintanaice Gas Turbine Frame 9

Page 1: Heavy Duty Maintanaice Gas Turbine Frame 9

GE Power Systems

Heavy-Duty GasTurbine Operating andMaintenanceConsiderations

Robert Hoeft, Jamison Janawitz, and Richard KeckGE Energy ServicesAtlanta, GA

GER-3620J

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Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Maintenance Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Gas Turbine Design Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Borescope Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Major Factors Influencing Maintenance and Equipment Life. . . . . . . . . . . . . . . . . . . . . . . . . 4

Starts and Hours Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Service Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Firing Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Steam/Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Cyclic Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Hot Gas Path Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Rotor Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Combustion Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Off Frequency Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Inlet Fogging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Maintenance Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Standby Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Running Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Load vs. Exhaust Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Vibration Level . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Fuel Flow and Pressure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Exhaust Temperature and Spread Variation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Start-Up Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Coast-Down Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Combustion Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Hot-Gas-Path Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Major Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Parts Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Inspection Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Manpower Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

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IntroductionMaintenance costs and availability are two ofthe most important concerns to the equipmentowner. A maintenance program that optimizesthe owner's costs and maximizes equipmentavailability must be instituted. For a mainte-nance program to be effective, owners mustdevelop a general understanding of the rela-tionship between their operating plans and pri-orities for the plant, the skill level of operatingand maintenance personnel, and the manufac-turer's recommendations regarding the num-ber and types of inspections, spare parts plan-ning, and other major factors affecting compo-nent life and proper operation of the equip-ment.

In this paper, operating and maintenance prac-tices will be reviewed, with emphasis placed ontypes of inspections plus operating factors thatinfluence maintenance schedules. A well-planned maintenance program will result inmaximum equipment availability and optimalmaintenance costs.

Note: The operating and maintenance discus-sions presented in this paper are generallyapplicable to all GE heavy-duty gas turbines; i.e.,MS3000, 5000, 6000, 7000 and 9000. For pur-poses of illustration, the MS7001EA was chosen.Specific questions on a given machine shouldbe directed to the local GE Energy Services rep-resentative.

Maintenance PlanningAdvance planning for maintenance is a necessi-ty for utility, industrial and cogeneration plantsin order to minimize downtime. Also the cor-rect performance of planned maintenance andinspection provides direct benefits in reducedforced outages and increased starting reliability,which in turn reduces unscheduled repairdowntime. The primary factors which affect themaintenance planning process are shown inFigure 1 and the owners' operating mode willdetermine how each factor is weighted.

Parts unique to the gas turbine requiring themost careful attention are those associated with

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Figure 1. Key factors affecting maintenance planning

Manufacturer’sRecommended

MaintenanceProgram

DesignFeatures

DutyCycle

Cost ofDowntime

Type ofFuel

ReplacementParts

Availability/Investment

ReserveRequirements

EnvironmentUtilization

Need

On-SiteMaintenance

Capability

ReliabilityNeed

Diagnostics &Expert Systems Maintenance

Planning

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the combustion process together with thoseexposed to high temperatures from the hotgases discharged from the combustion system.They are called the hot-gas-path parts andinclude combustion liners, end caps, fuel noz-zle assemblies, crossfire tubes, transition pieces,turbine nozzles, turbine stationary shrouds andturbine buckets.

The basic design and recommended mainte-nance of GE heavy-duty gas turbines are orient-ed toward:

■ Maximum periods of operationbetween inspection and overhauls

■ In-place, on-site inspection andmaintenance

■ Use of local trade skills to disassemble,inspect and re-assemble

In addition to maintenance of the basic gas tur-bine, the control devices, fuel metering equip-ment, gas turbine auxiliaries, load package, andother station auxiliaries also require periodicservicing.

It is apparent from the analysis of scheduledoutages and forced outages (Figure 2) that theprimary maintenance effort is attributed to fivebasic systems: controls and accessories, com-bustion, turbine, generator and balance-of-plant. The unavailability of controls and acces-sories is generally composed of short-durationoutages, whereas conversely the other four sys-tems are composed of fewer, but usually longer-duration outages.

The inspection and repair requirements, out-lined in the Maintenance and InstructionsManual provided to each owner, lend them-selves to establishing a pattern of inspections. Inaddition, supplementary information is provid-ed through a system of Technical InformationLetters. This updating of information, con-tained in the Maintenance and InstructionsManual, assures optimum installation, opera-tion and maintenance of the turbine. Many ofthe Technical Information Letters contain advi-sory technical recommendations to resolveissues and improve the operation, mainte-

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Figure 2. Plant level - top five systems contributions to downtime

Total S.C. PlantGas Turbine

– Turbine Section– Combustion Section– Compressor Section– Bearings

Controls & AccessoriesGeneratorBalance of S.C. Plant

1 2 3 4 5 6 7

FOF = Forced OutageSOF = Scheduled Outage

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nance, safety, reliability or availability of the tur-bine. The recommendations contained inTechnical Information Letters should bereviewed and factored into the overall mainte-nance planning program.

For a maintenance program to be effective,from both a cost and turbine availability stand-point, owners must develop a general under-standing of the relationship between their oper-ating plans and priorities for the plant and themanufacturer's recommendations regardingthe number and types of inspections, spareparts planning, and other major factors affect-ing the life and proper operation of the equip-ment. Each of these issues will be discussed asfollows in further detail.

Gas Turbine Design MaintenanceFeaturesThe GE heavy-duty gas turbine is designed towithstand severe duty and to be maintainedonsite, with off-site repair required only on cer-tain combustion components, hot-gas-pathparts and rotor assemblies needing specializedshop service. The following features aredesigned into GE heavy-duty gas turbines tofacilitate on-site maintenance:

■ All casings, shells and frames are spliton machine horizontal centerline.Upper halves may be lifted individuallyfor access to internal parts.

■ With upper-half compressor casingsremoved, all stator vanes can be slidcircumferentially out of the casings forinspection or replacement withoutrotor removal. On most designs, thevariable inlet guide vanes (VIGVs) canbe removed radially with upper half ofinlet casing removed.

■ With the upper-half of the turbine

shell lifted, each half of the first stagenozzle assembly can be removed forinspection, repair or replacementwithout rotor removal. On some units,upper-half, later-stage nozzleassemblies are lifted with the turbineshell, also allowing inspection and/orremoval of the turbine buckets.

■ All turbine buckets are moment-weighed and computer charted in setsfor rotor spool assembly so that theymay be replaced without the need toremove or rebalance the rotorassembly.

■ All bearing housings and liners aresplit on the horizontal centerline sothat they may be inspected andreplaced, when necessary. The lowerhalf of the bearing liner can beremoved without removing the rotor.

■ All seals and shaft packings areseparate from the main bearinghousings and casing structures andmay be readily removed and replaced.

■ On most designs, fuel nozzles,combustion liners and flow sleeves canbe removed for inspection,maintenance or replacement withoutlifting any casings.

■ All major accessories, including filtersand coolers, are separate assembliesthat are readily accessible forinspection or maintenance. They mayalso be individually replaced asnecessary.

Inspection aid provisions have been built intoGE heavy-duty gas turbines to facilitate con-ducting several special inspection procedures.These special procedures provide for the visualinspection and clearance measurement of some

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of the critical internal turbine gas-path compo-nents without removal of the gas turbine outercasings and shells. These procedures includegas-path borescope inspection and turbine noz-zle axial clearance measurement.

Borescope InspectionsGE heavy-duty gas turbines incorporate provi-sions in both compressor casings and turbineshells for gas-path visual inspection of interme-diate compressor rotor stages, first, second andthird-stage turbine buckets and turbine nozzlepartitions by means of the optical borescope.These provisions, consisting of radially alignedholes through the compressor casings, turbineshell and internal stationary turbine shrouds,are designed to allow the penetration of an opti-cal borescope into the compressor or turbineflow path area, as shown in Figure 3.

An effective borescope inspection program canresult in removing casings and shells from a tur-bine unit only when it is necessary to repair orreplace parts. Figure 4 provides a recommendedinterval for a planned borescope inspectionprogram following initial base line inspections.It should be recognized that these borescope

inspection intervals are based on average unitoperating modes. Adjustment of theseborescope intervals may be made based onoperating experience and the individual unitmode of operation, the fuels used and theresults of previous borescope inspections.

The application of a monitoring program utiliz-ing a borescope will allow scheduling outagesand pre-planning of parts requirements, result-ing in lower maintenance costs and higher avail-ability and reliability of the gas turbine.

Major Factors InfluencingMaintenance and Equipment LifeThere are many factors that can influenceequipment life and these must be understoodand accounted for in the owner's maintenanceplanning. As indicated in Figure 5, starting cycle,power setting, fuel and level of steam or waterinjection are key factors in determining themaintenance interval requirements as these fac-tors directly influence the life of critical gas tur-bine parts.

In the GE approach to maintenance planning,a gas fuel unit operating continuous duty, withno water or steam injection, is established as thebaseline condition which sets the maximumrecommended maintenance intervals. For oper-ation that differs from the baseline, mainte-nance factors are established that determinethe increased level of maintenance that isrequired. For example, a maintenance factor oftwo would indicate a maintenance interval thatis half of the baseline interval.

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Figure 3. MS7001E gas turbine borescope inspectionaccess locations

Figure 4. Borescope inspection programming

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Starts and Hours CriteriaGas turbines wear in different ways for differentservice-duties, as shown in Figure 6. Thermalmechanical fatigue is the dominant limiter oflife for peaking machines, while creep, oxida-tion, and corrosion are the dominant limiters oflife for continuous duty machines. Interactionsof these mechanisms are considered in the GEdesign criteria, but to a great extent are secondorder effects. For that reason, GE bases gas tur-bine maintenance requirements on independ-ent counts of starts and hours. Whichever crite-ria limit is first reached determines the mainte-nance interval. A graphical display of the GE

approach is shown in Figure 7. In this figure, theinspection interval recommendation is definedby the rectangle established by the starts andhours criteria. These recommendations forinspection fall within the design life expecta-tions and are selected such that componentsverified to be acceptable for continued use atthe inspection point will have low risk of failureduring the subsequent operating interval.

An alternative to the GE approach, which issometimes employed by other manufacturers,converts each start cycle to an equivalent num-ber of operating hours (EOH) with inspectionintervals based on the equivalent hours count.For the reasons stated above, GE does not agreewith this approach. This logic can create theimpression of longer intervals, while in realitymore frequent maintenance inspections arerequired. Referring again to Figure 7, the startsand hours inspection "rectangle" is reduced inhalf as defined by the diagonal line from thestarts limit at the upper left hand corner to thehours limit at the lower right hand corner.Midrange duty applications, with hours per startratios of 30-50, are particularly penalized by thisapproach.

This is further illustrated in Figure 8 for theexample of an MS7001EA gas turbine operatingon gas fuel, at base load conditions with nosteam or water injection or trips from load. Theunit operates 4000 hours and 300 starts peryear. Following GE's recommendations, theoperator would perform the hot gas pathinspection after four years of operation, withstarts being the limiting condition. Performingmaintenance on this same unit based on anequivalent hours criteria would require a hotgas path inspection after 2.4 years. Similarly, fora continuous duty application operating 8000hours and 160 starts per year, the GE recom-mendation would be to perform the hot gas

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

Figure 5. Maintenance cost and equipment life areinfluenced by key service factors

Figure 6. Causes of wear - Hot-Gas-Path components

• Cyclic Effects

• Firing Temperature

• Fuel

• Steam/Water Injection

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path inspection after three years of operationwith the operating hours being the limitingcondition for this case. The equivalent hourscriteria would set the hot gas path inspectionafter 2.1 years of operation for this application.

Service FactorsWhile GE does not ascribe to the equivalency ofstarts to hours, there are equivalencies within awear mechanism that must be considered. Asshown in Figure 9, influences such as fuel type

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

Figure 7. GE bases gas turbine maintenance requirements on independent counts of starts and hours

Figure 8. Hot-gas-path maintenance interval comparisons. GE method vs. EOH method

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and quality, firing temperature setting, and theamount of steam or water injection are consid-ered with regard to the hours-based criteria.Startup rate and the number of trips are con-

sidered with regard to the starts-based criteria.In both cases, these influences may act toreduce the maintenance intervals. When theseservice or maintenance factors are involved in aunit's operating profile, the hot-gas-path main-tenance "rectangle" that describes the specificmaintenance criteria for this operation isreduced from the ideal case, as illustrated inFigure 10. The following discussion will take acloser look at the key operating factors and howthey can impact maintenance intervals as well asparts refurbishment/replacement intervals.

Fuel Fuels burned in gas turbines range from cleannatural gas to residual oils and impact mainte-nance, as illustrated in Figure 11. Heavier hydro-carbon fuels have a maintenance factor rangingfrom three to four for residual fuel and two tothree for crude oil fuels. These fuels generallyrelease a higher amount of radiant thermalenergy, which results in a subsequent reduction

in combustion hardware life, and frequentlycontain corrosive elements such as sodium,potassium, vanadium and lead that can lead toaccelerated hot corrosion of turbine nozzlesand buckets. In addition, some elements inthese fuels can cause deposits either directly orthrough compounds formed with inhibitorsthat are used to prevent corrosion. Thesedeposits impact performance and can lead to aneed for more frequent maintenance.

Distillates, as refined, do not generally containhigh levels of these corrosive elements, butharmful contaminants can be present in thesefuels when delivered to the site. Two commonways of contaminating number two distillatefuel oil are: salt water ballast mixing with thecargo during sea transport, and contaminationof the distillate fuel when transported to site intankers, tank trucks or pipelines that were pre-viously used to transport contaminated fuel,chemicals or leaded gasoline. From Figure 11, itcan be seen that GE’s experience with distillatefuels indicates that the hot gas path mainte-nance factor can range from as low as one(equivalent to natural gas) to as high as three.Unless operating experience suggests other-wise, it is recommended that a hot gas path

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

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Figure 9. Maintenance factors - hot-gas-path (bucketsand nozzles)

�0

�4

�8

�12

�16

�20

�24

�28

1,400��

1,200��

1,000��

800��

600��

400��

200��

0

�Thousands of Fired Hours

Sta

rts

Maintenance Factors Reduce Maintenance Interval

Hours Factors

• Firing Temperature• Steam/Water Injection• Fuel Type

Starts Factors• Trips• Fasts Starts

Figure 10. GE maintenance interval for hot-gas inspections

Typical Max Inspection Intervals (MS6B/MS7EA)Hot Gas Path Inspection 24,000 hrs or 1200 startsMajor Inspection 48,000 hrs or 2400 starts

Criterion is Hours or Starts (Whichever Occurs First)

Factors Impacting Maintenance

Hours Factors• Fuel Gas 1

Distillate 1.5Crude 2 to 3Residual 3 to 4

• Peak Load• Water/Steam Injection

Dry Control 1 (GTD-222)Wet Control 1.9 (5% H2O GTD-222)

Starts Factors• Trip from Full Load 8• Fast Load 2• Emergency Start 20

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maintenance factor of 1.5 be used for operationon distillate oil. Note also that contaminants inliquid fuels can affect the life of gas turbine aux-iliary components such as fuel pumps and flowdividers.

As shown in Figure 11, gas fuels, which meet GEspecifications, are considered the optimum fuelwith regard to turbine maintenance and areassigned no negative impact. The importanceof proper fuel quality has been amplified withDry Low NOx (DLN) combustion systems.Proper adherence to GE fuel specifications inGEI-41040 is required to allow proper combus-tion system operation, and to maintain applica-ble warranties. Liquid hydrocarbon carryovercan expose the hot-gas-path hardware to severeovertemperature conditions and can result insignificant reductions in hot-gas-path parts livesor repair intervals. Owners can control thispotential issue by using effective gas scrubbersystems and by superheating the gaseous fuelprior to use to provide a nominal 50°F (28°C)

of superheat at the turbine gas control valveconnection.

The prevention of hot corrosion of the turbinebuckets and nozzles is mainly under the controlof the owner. Undetected and untreated, a sin-gle shipment of contaminated fuel can causesubstantial damage to the gas turbine hot gaspath components. Potentially high mainte-nance costs and loss of availability can be mini-mized or eliminated by:

■ Placing a proper fuel specification onthe fuel supplier. For liquid fuels, eachshipment should include a report thatidentifies specific gravity, flash point,viscosity, sulfur content, pour pointand ash content of the fuel.

■ Providing a regular fuel qualitysampling and analysis program. Aspart of this program, an online waterin fuel oil monitor is recommended,as is a portable fuel analyzer that, as a

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

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Figure 11. Estimated effect of fuel type on maintenance

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minimum, reads vanadium, lead,sodium, potassium, calcium andmagnesium.

■ Providing proper maintenance of thefuel treatment system when burningheavier fuel oils and by providingcleanup equipment for distillate fuelswhen there is a potential forcontamination.

In addition to their presence in the fuel, con-taminants can also enter the turbine via theinlet air and from the steam or water injectedfor NOx emission control or power augmenta-tion. Carryover from evaporative coolers isanother source of contaminants. In some cases,these sources of contaminants have been foundto cause hot-gas-path degradation equal to thatseen with fuel-related contaminants. GE specifi-cations define limits for maximum concentra-tions of contaminants for fuel, air andsteam/water.

Firing Temperatures

Significant operation at peak load, because ofthe higher operating temperatures, will requiremore frequent maintenance and replacementof hot-gas-path components. For an MS7001EAturbine, each hour of operation at peak load fir-ing temperature (+100°F/56°C) is the same,from a bucket parts life standpoint, as six hoursof operation at base load. This type of operationwill result in a maintenance factor of six. Figure 12 defines the parts life effect correspon-ding to changes in firing temperature. Itshould be noted that this is not a linear rela-tionship, as a +200°F/111°C increase in firingtemperature would have an equivalency of sixtimes six, or 36:1.

Higher firing temperature reduces hot-gas-pathparts lives while lower firing temperature

increases parts lives. This provides an opportu-nity to balance the negative effects of peak loadoperation by periods of operation at part load.However, it is important to recognize that thenonlinear behavior described above will notresult in a one for one balance for equal mag-nitudes of over and under firing operation.Rather, it would take six hours of operation at -100°F/56°C under base conditions to compen-sate for one hour operation at +100°F/56°Cover base load conditions.

It is also important to recognize that a reduc-tion in load does not always mean a reductionin firing temperature. In heat recovery applica-tions, where steam generation drives overallplant efficiency, load is first reduced by closingvariable inlet guide vanes to reduce inlet airflowwhile maintaining maximum exhaust tempera-ture. For these combined cycle applications, fir-ing temperature does not decrease until load isreduced below approximately 80% of rated out-put. Conversely, a turbine running in simplecycle mode maintains full open inlet guidevanes during a load reduction to 80% and willexperience over a 200°F/111°C reduction in fir-ing temperature at this output level. The hot-gas-path parts life effects for these different

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1

10

100

0 50 100 150

Delta Firing Temperature

Ma

inte

na

nc

e F

ac

tor

F Class

E Class

E classPeak Rating life Factor 6x

6

1

10

100

0 50 100 150

Delta Firing Temperature

Ma

inte

na

nc

e F

ac

tor

F Class

E Class

E classPeak Rating life Factor 6x

6

Figure 12. Bucket life firing temperature effect

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modes of operation are obviously quite differ-ent. This turbine control effect is illustrated inFigure 13. Similarly, turbines with DLN combus-tion systems utilize inlet guide vane turndown aswell as inlet bleed heat to extend operation oflow NOx premix operation to part load condi-tions.

Firing temperature effects on hot gas path main-tenance, as described above, relate to cleanburning fuels, such as natural gas and light dis-tillates, where creep rupture of hot gas pathcomponents is the primary life limiter and is themechanism that determines the hot gas pathmaintenance interval impact. With ash-bearingheavy fuels, corrosion and deposits are the pri-mary influence and a different relationship withfiring temperature exists. Figure 14 illustrates thesensitivity of hot gas path maintenance factor tofiring temperature for a heavy fuel operation. Itcan be seen that while the sensitivity to firingtemperature is less, the maintenance factor itselfis higher due to issues relating to the corrosiveelements contained in these fuels.

Steam/Water InjectionWater (or steam) injection for emissions con-trol or power augmentation can impact partslives and maintenance intervals even when thewater or steam meets GE specifications. This

relates to the effect of the added water on thehot-gas transport properties. Higher gas con-ductivity, in particular, increases the heat trans-fer to the buckets and nozzles and can lead tohigher metal temperature and reduced partslives as shown in Figure 15.

Parts life impact from steam or water injectionis related to the way the turbine is controlled.The control system on most base load applica-tions reduces firing temperature as water orsteam is injected. This counters the effect of thehigher heat transfer on the gas side and results

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 10

Figure 13. Firing temperature and load relationship -heat recovery vs. simple cycle operation

Figure 14. Heavy fuel maintenance factors

Figure 15. Steam/water injection and bucket nozzle life

Page 15: Heavy Duty Maintanaice Gas Turbine Frame 9

in no impact on bucket life. On some installa-tions, however, the control system is designed tomaintain firing temperature constant withwater injection level. This results in additionalunit output but it decreases parts life as previ-ously described. Units controlled in this way aregenerally in peaking applications where annualoperating hours are low or where operatorshave determined that reduced parts lives arejustified by the power advantage. GE describesthese two modes of operation as dry controlcurve operation and wet control curve opera-tion, respectively. Figure 16 illustrates the wetand dry control curve and the performance dif-ferences that result from these two differentmodes of control.

An additional factor associated with water orsteam injection relates to the higher aerody-namic loading on the turbine components thatresults from the injected water increasing thecycle pressure ratio. This additional loading canincrease the downstream deflection rate of thesecond- and third-stage nozzles, which wouldreduce the repair interval for these compo-nents. However, the introduction of GTD-222, anew high creep strength stage two and threenozzle alloy, has minimized this factor.

Maintenance factors relating to water injectionfor units operating on dry control range from

one (for units equipped with GTD-222 second-stage and third-stage nozzles) to a factor of 1.5for units equipped with FSX-414 nozzles andinjecting 5% water. For wet control curve oper-ation, the maintenance factor is approximatelytwo at 5% water injection for GTD-222 and fourfor FSX-414.

Cyclic EffectsIn the previous discussion, operating factorsthat impact the hours-based maintenance crite-ria were described. For the starts-based mainte-nance criteria, operating factors associated withthe cyclic effects produced during startup, oper-ation and shutdown of the turbine must be con-sidered. Operating conditions other than thestandard startup and shutdown sequence canpotentially reduce the cyclic life of the hot gaspath components and rotors, and, if present,will require more frequent maintenance andparts refurbishment and/or replacement.

Hot Gas Path PartsFigure 17 illustrates the firing temperaturechanges occurring over a normal startup andshutdown cycle. Light-off, acceleration, loading,unloading and shutdown all produce gas tem-perature changes that produce correspondingmetal temperature changes. For rapid changesin gas temperature, the edges of the bucket or

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 11

Figure 16. Exhaust temperature control curve - dry vs.wet control MS7001EA

Figure 17. Turbine start/stop cycle - firing temperaturechanges

Page 16: Heavy Duty Maintanaice Gas Turbine Frame 9

nozzle respond more quickly than the thickerbulk section, as pictured in Figure 18. These gra-dients, in turn, produce thermal stresses that,when cycled, can eventually lead to cracking.Figure 19 describes the temperature strain histo-ry of an MS7001EA stage 1 bucket during a nor-mal startup and shutdown cycle. Light-off andacceleration produce transient compressivestrains in the bucket as the fast responding lead-ing edge heats up more quickly than the thick-

er bulk section of the airfoil. At full load condi-tions, the bucket reaches its maximum metaltemperature and a compressive strain producedfrom the normal steady state temperature gra-dients that exist in the cooled part. At shut-down, the conditions reverse where the fasterresponding edges cool more quickly than thebulk section, which results in a tensile strain atthe leading edge.

Thermal mechanical fatigue testing has foundthat the number of cycles that a part can with-stand before cracking occurs is strongly influ-enced by the total strain range and the maxi-mum metal temperature experienced. Anyoperating condition that significantly increasesthe strain range and/or the maximum metaltemperature over the normal cycle conditionswill act to reduce the fatigue life and increasethe starts-based maintenance factor. For exam-ple, Figure 20 compares a normal operatingcycle with one that includes a trip from fullload. The significant increase in the strainrange for a trip cycle results in a life effect thatequates to eight normal start/stop cycles, asshown. Trips from part load will have a reduced

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 12

Figure 18. First stage bucket transient temperaturedistribution

Figure 19. Bucket low cycle fatigue (LCF)

Page 17: Heavy Duty Maintanaice Gas Turbine Frame 9

impact because of the lower metal temperaturesat the initiation of the trip event. Figure 21 illus-trates that while a trip from loads greater than80% has an 8:1 maintenance factor, a trip fromfull speed no load would have a maintenancefactor of 2:1.

Similarly to trips from load, emergency startsand fast loading will impact the starts-basedmaintenance interval. This again relates to theincreased strain range that is associated withthese events. Emergency starts where units arebrought from standstill to full load in less thanfive minutes will have a parts life effect equal to

20 normal start cycles and a normal start withfast loading will produce a maintenance factorof two.

While the factors described above will decreasethe starts-based maintenance interval, part loadoperating cycles would allow for an extension ofthe maintenance interval. Figure 22 is a guide-line that could be used in considering this typeof operation. For example, two operating cyclesto maximum load levels of less than 60% wouldequate to one start to a load greater than 60%or, stated another way, would have a mainte-nance factor of .5.

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

Figure 20. Low cycle fatigue life sensitivities - first stage bucket

0

2

4

6

8

10

20 40 60 80 100% Load

Base

FSNL

Note:For Trips During Start-up AccelAssume Trip Severity Factor = 2

0

F Class and E Classunits with Inlet

Bleed Heat

Units WithoutInlet Bleed Heat

aT-

Trip

Sev

erit

y F

acto

r

Figure 21. Maintenance factor - trips from loadFigure 22. Maintenance factor - effect of start cycle

maximum load level

GE Power Systems ■ GER-3620J ■ (01/03) 13

Page 18: Heavy Duty Maintanaice Gas Turbine Frame 9

Rotor PartsIn addition to the hot gas path components, therotor structure maintenance and refurbishmentrequirements are impacted by the cyclic effectsassociated with startup, operation and shut-down. Maintenance factors specific to an appli-cation's operating profile and rotor design mustbe determined and incorporated into the oper-ators maintenance planning. Disassembly andinspection of all rotor components is requiredwhen the accumulated rotor starts reach theinspection limit. (See Figure 45 and Figure 46 inInspection Intervals Section.)

For the rotor, the thermal condition when thestart-up sequence is initiated is a major factor indetermining the rotor maintenance intervaland individual rotor component life. Rotorsthat are cold when the startup commencesdevelop transient thermal stresses as the turbineis brought on line. Large rotors with theirlonger thermal time constants develop higherthermal stresses than smaller rotors undergoingthe same startup time sequence. High thermalstresses will reduce maintenance intervals andthermal mechanical fatigue life.

The steam turbine industry recognized theneed to adjust startup times in the 1950 to 1970time period when power generation marketgrowth led to larger and larger steam turbinesoperating at higher temperatures. Similar tothe steam turbine rotor size increases of the1950s and 1960s, gas turbine rotors have seen agrowth trend in the 1980s and 1990s as the tech-nology has advanced to meet the demand forcombined cycle power plants with high powerdensity and thermal efficiency.

With these larger rotors, lessons learned fromboth the steam turbine experience and themore recent gas turbine experience should befactored into the start-up control for the gas tur-bine and/or maintenance factors should be

determined for an application's duty cycle toquantify the rotor life reductions associatedwith different severity levels. The maintenancefactors so determined are used to adjust therotor component inspection, repair andreplacement intervals that are appropriate tothat particular duty cycle.

Though the concept of rotor maintenance fac-tors is applicable to all gas turbine rotors, onlyMS7001/9001F and FA rotors will be discussedin detail. The rotor maintenance factor for astartup is a function of the downtime followinga previous period of operation. As downtimeincreases, the rotor metal temperatureapproaches ambient conditions and thermalfatigue impact during a subsequent start-upincreases. Since the most limiting locationdetermines the overall rotor impact, the rotormaintenance factor is determined from theupper bound locus of the rotor maintenancefactors at these various features. For example,cold starts are assigned a rotor maintenance fac-tor of two and hot starts a rotor maintenancefactor of less than one due to the lower thermalstress under hot conditions.

Cold starts are not the only operating factorthat influences rotor maintenance intervals andcomponent life. Fast starts and fast loading,where the turbine is ramped quickly to load,increase thermal gradients and are more severeduty for the rotor. Trips from load and particu-larly trips followed by immediate restarts reducethe rotor maintenance interval as do hotrestarts within the first hour of a hot shutdown.Figure 23 lists recommended operating factorsthat should be used to determine the rotor'soverall maintenance factor for PG7241 andPG9351 design rotors. The factors to be usedfor other models are determined by applicableTechnical Information Letters.

The significance of each of these factors to themaintenance requirements of the rotor is

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 14

Page 19: Heavy Duty Maintanaice Gas Turbine Frame 9

dependent on the type of operation that theunit sees. There are three general categories ofoperation that are typical of most gas turbineapplications. These are peaking, cyclic and con-tinuous duty as described below:

■ Peaking units have a relatively highstarting frequency and a low numberof hours per start. Operation follows aseasonal demand. Peaking units willgenerally see a high percentage ofcold starts.

■ Cyclic duty units start daily withweekend shutdowns. Twelve to sixteenhours per start is typical which resultsin a warm rotor condition for a largepercentage of the starts. Cold starts aregenerally seen only following a startupafter a maintenance outage orfollowing a two day weekend outage.

■ Continuous duty applications see ahigh number of hours per start andmost starts are cold because outagesare generally maintenance driven.While the percentage of cold starts ishigh, the total number of starts is low.The rotor maintenance interval on

continuous duty units will bedetermined by service hours ratherthan starts.

Figure 24 lists operating profiles on the high endof each of these three general categories of gasturbine applications.

As can be seen in Figure 24, these duty cycleshave different combinations of hot, warm andcold starts with each starting condition having adifferent impact on rotor maintenance intervalas previously discussed. As a result, the startsbased rotor maintenance interval will dependon an applications specific duty cycle. In a latersection, a method will be described that allowsthe turbine operator to determine a mainte-

nance factor that is specific to the operation'sduty cycle. The application’s integrated mainte-nance factor uses the rotor maintenance factorsdescribed above in combination with the actualduty cycle of a specific application and can beused to determine rotor inspection intervals. Inthis calculation, the reference duty cycle thatyields a starts based maintenance factor equal toone is defined in Figure 25. Duty cycles differentfrom the Figure 25 definition, in particular dutycycles with more cold starts, or a high numberof trips, will have a maintenance factor greaterthan one.

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 15

Figure 23. Operation-related maintenance factors

7241/9351* Design

Figure 24. FA gas turbine typical operational profile

Peaking ~ Cyclic ~ Continuous

Page 20: Heavy Duty Maintanaice Gas Turbine Frame 9

Combustion PartsA typical combustion system contains transitionpieces, combustion liners, flow sleeves, head-endassemblies containing fuel nozzles and car-tridges, end caps and end covers, and assortedother hardware including cross-fire tubes, sparkplugs and flame detectors. In addition, therecan be various fuel and air delivery componentssuch as purge or check valves and flex hoses.GE provides several types of combustion systemsincluding standard combustors, Multi-NozzleQuiet Combustors (MNQC), IGCC combustorsand Dry Low NOx (DLN) combustors. Each ofthese combustion systems have unique operat-ing characteristics and modes of operation withdiffering responses to operational variablesaffecting maintenance and refurbishmentrequirements.

The maintenance and refurbishment require-ments of combustion parts are impacted bymany of the same factors as hot gas path partsincluding start cycle, trips, fuel type and quality,firing temperature and use of steam or waterinjection for either emissions control or poweraugmentation. However, there are other factorsspecific to combustion systems. One of these

factors is operating mode, which describes theapplied fueling pattern. The use of low loadoperating modes at high loads can reduce themaintenance interval significantly. An exampleof this is the use of DLN1 extended lean-leanmode at high loads, which can result in a main-tenance factor of 10. Another factor that canimpact combustion system maintenance isacoustic dynamics. Acoustic dynamics are pres-sure oscillations generated by the combustionsystem, which, if high enough in magnitude, canlead to significant wear and cracking. GE prac-tice is to tune the combustion system to levels ofacoustic dynamics low enough to ensure thatthe maintenance practices described here arenot compromised.

Combustion maintenance is performed, ifrequired, following each combustion inspection(or repair) interval. Inspection interval guide-lines are included in Figure 42. It is expectedand recommended that intervals be modifiedbased on specific experience. Replacementintervals are usually defined by a recommendednumber of combustion (or repair) intervals andare usually combustion component specific. Ingeneral, the replacement interval as a functionof the number of combustion inspection inter-vals is reduced if the combustion inspectioninterval is extended. For example, a compo-nent having an 8,000 hour combustion inspec-tion (CI) interval and a 6(CI) or 48,000 hourreplacement interval would have a replacementinterval of 4(CI) if the inspection interval wasincreased to 12,000 hours to maintain a 48,000hour replacement interval.

For combustion parts, the base line operatingconditions that result in a maintenance factor ofunity are normal fired start-up and shut-down tobase load on natural gas fuel without steam orwater injection. Factors that increase the hours-based maintenance factor include peaking duty,

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 16

Figure 25. Baseline for starts-based maintenancefactor definitions

Page 21: Heavy Duty Maintanaice Gas Turbine Frame 9

distillate or heavy fuels, steam or water injectionwith dry or wet control curves. Factors thatincrease starts-based maintenance factor includepeaking duty, fuel type, steam or water injection,trips, emergency starts and fast loading.

Off Frequency Operation GE heavy-duty single shaft gas turbines aredesigned to operate over a 95% to 105% speedrange. However, operation at other than ratedspeed has the potential to impact maintenancerequirements. Depending on the industrycode requirements, the specifics of the turbinedesign and the turbine control philosophyemployed, operating conditions can result thatwill accelerate life consumption of hot gas pathcomponents. Where this is true, the mainte-nance factor associated with this operationmust be understood and these speed eventsanalyzed and recorded so as to include in themaintenance plan for this gas turbine installa-tion.

Generator drive turbines operating in a powersystem grid are sometimes required to meetoperational requirements that are aimed atmaintaining grid stability under conditions ofsudden load or capacity changes. Most codesrequire turbines to remain on line in the eventof a frequency disturbance. For under-frequen-cy operation, the turbine output decrease thatwill normally occur with a speed decrease isallowed and the net impact on the turbine asmeasured by a maintenance factor is minimal.In some grid systems, there are more stringentcodes that require remaining on line whilemaintaining load on a defined schedule of loadversus grid frequency. One example of a morestringent requirement is defined by the NationalGrid Company (NGC). In the NGC code, con-ditions under which frequency excursions mustbe tolerated and/or controlled are defined asshown in Figure 26.

With this specification, load must be maintainedconstant over a frequency range of +/- 1%(+/- 0.5Hz in a 50 Hz grid system) with a onepercent load reduction allowed for every addi-tional one percent frequency drop down to aminimum 94% speed. Requirements stipulatethat operation between 95% to 104% speed canbe continuous but operation between 94% and95% is limited to 20 seconds for each event.These conditions must be met up to a maximumambient temperature of 25°C (77°F).

Under-frequency operation impacts mainte-nance to the degree that nominally controlledturbine output must be exceeded in order tomeet the specification defined output require-ment. As speed decreases, the compressor air-flow decreases, reducing turbine output. If thisnormal output fall-off with speed results in loadsless than the defined minimum, power augmen-tation must be applied. Turbine overfiring is themost obvious augmentation option but othermeans such as utilizing gas turbine water washhave some potential as an augmentation action.

Ambient temperature can be a significant factorin the level of power augmentation required.This relates to compressor operating marginthat may require inlet guide vane closure if com-pressor corrected speed reaches limiting condi-tions. For an FA class turbine, operation at 0°C

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 17

47 49.5 50.5

100% of ActivePower Output

95% of ActivePower Output

Frequency ~ Hz

Figure 26. The NGC requirement for outputvs. frequency capability overall ambients

less than 25°C (77°F)

Page 22: Heavy Duty Maintanaice Gas Turbine Frame 9

(32°F) would require no power augmentation tomeet NGC requirements while operation at25°C (77°F) would fall below NGC requirementswithout a substantial amount of power augmen-tation. As an example, Figure 27 illustrates theoutput trend at 25°C (77°F) for an FA class gasturbine as grid system frequency changes andwhere no power augmentation is applied.

In Figure 27, the gas turbine output shortfall atthe low frequency end (47.5Hz) of the NGCcontinuous operation compliance range wouldrequire a 160°F increase over base load firingtemperature to be in compliance. At this level ofover-fire, a maintenance factor exceeding 100xwould be applied to all time spent at these con-ditions. Overfiring at this level would haveimplications on combustion operability andemissions compliance as well as have majorimpact on hot gas path parts life. An alternativepower augmentation approach that has beenutilized in FA gas turbines for NGC code com-pliance utilizes water wash in combination withincreased firing temperature. As shown in Figure28, with water wash on, 50°F overfiring isrequired to meet NGC code for operating con-ditions of 25°C (77°F) ambient temperature andgrid frequency at 47.5 HZ. Under these condi-tions, the hours-based maintenance factor would

be 3x as determined by Figure 12. It is importantto understand that operation at over-frequencyconditions will not trade one-for-one for periodsat under-frequency conditions. As was discussedin the firing temperature section above, opera-tion at peak firing conditions has a nonlinear log-arithmic relationship with maintenance factor.

As described above, the NGC code requiresoperation for up to 20 seconds per event at anunder-frequency condition between 94% to95% speed. Grid events that expose the gas tur-bine to frequencies below the minimum contin-uous speed of 95% introduce additional mainte-nance and parts replacement considerations.Operation at speeds less than 95% requiresincreased over-fire to achieve compliance, butalso introduces an additional concern thatrelates to the potential exposure of the bladingto excitations that could result in blade resonantresponse and reduced fatigue life. Consideringthis potential, a starts-based maintenance factorof 60x is assigned to every 20-second excursionto grid frequencies less than 95% speed.

Over-frequency or high speed operation canalso introduce conditions that impact turbinemaintenance and part replacement intervals. Ifspeed is increased above the nominal rated

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 18

Output versus Grid Frequency

0.700

0.800

0.900

1.000

1.100

46 47 48 49 50 51 52

Frequency

No

rma

lize

d O

utp

ut NGC Requirement

Constant Tf Output Trend

Tamb = 25C (77F)

OutputShortfallWithout

Overfiring

Figure 27. Turbine output at under-frequency operation

Firing Temperature For NGC Compliance

-50

0

50

100

150

200

250

300

46 47 48 49 50 51 52

Frequency

Overfire To Meet NGC

Overfire

Waterwash on @49.5 Hz

Tamb = 25C (77F)

Del

ta F

irin

g Te

mpe

ratu

re ~

F

Figure 28. NGC code compliance TF required — FA class

Page 23: Heavy Duty Maintanaice Gas Turbine Frame 9

speed, the rotating components see an increasein mechanical stress proportional to the squareof the speed increase. If firing temperature isheld constant at the overspeed condition, thelife consumption rate of hot gas path rotatingcomponents will increase as illustrated in Figure29 where one hour of operation at 105% speedis equivalent to 2 hours at rated speed. If over-speed operation represents a small fraction of aturbine’s operating profile, this effect on partslife can sometimes be ignored. However, if sig-nificant operation at overspeed is expected andrated firing temperature is maintained, theaccumulated hours must be recorded andincluded in the calculation of the turbine’s over-all maintenance factor and the maintenanceschedule adjusted to reflect the overspeed oper-ation. An option that mitigates this effect is tounder fire to a level that balances the overspeedparts life effect. Some mechanical drive appli-cations have employed that strategy to avoid amaintenance factor increase.

The frequency-sensitive discussion abovedescribes code requirements related to turbineoutput capability versus grid frequency, wheremaintenance factors within the continuousoperating speed range are hours-based. Thereare other considerations related to turbines

operating in grid frequency regulation mode. Infrequency regulation mode, turbines are dis-patched to operate at less than full load andstand ready to respond to a frequency distur-bance by rapidly picking up load. NGC require-ments for units in frequency regulation modeinclude being equipped with a fast-acting pro-portional speed governor operating with anoverall speed droop of 3-5%. With this control,a gas turbine will provide a load increase that isproportional to the size of the grid frequencychange. For example, a turbine operating withfive percent droop would pick up 20% load inresponse to a .5 Hz (1%) grid frequency drop.

The rate at which the turbine picks up load inresponse to an under-frequency condition isdetermined by the gas turbine design and theresponse of the fuel and compressor airflow con-trol systems, but would typically yield a less thanten-second turbine response to a step change ingrid frequency. Any maintenance factor associ-ated with this operation depends on the magni-tude of the load change that occurs. A turbinedispatched at 50% load that responded to a 2%frequency drop would have parts life and main-tenance impact on the hot gas path as well as therotor structure. More typically, however, tur-bines are dispatched at closer to rated loadwhere maintenance factor effects may be lesssevere. The NGC requires 10% plant output in10 seconds in response to a .5Hz (1%) underfrequency condition. In a combined cycle instal-lation where the gas turbine alone must pick upthe transient loading, a load change of 15% in10 seconds would be required to meet thatrequirement. Maintenance factor effects relatedto this would be minimal for the hot gas pathbut would impact the rotor maintenance factor.For an FA class rotor, each frequency excursionwould be counted as an additional factored startin the numerator of the maintenance factor cal-culation described in Figure 45. A further

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 19

Over Speed OperationConstant Tfire

1.0

10.0

1.00 1.01 1.02 1.03 1.04 1.05

% Speed

Ma

inte

na

nc

e F

ac

tor

(MF

)

MF = 2

Figure 29. Maintenance factor for overspeed operation ~ constant TF

Page 24: Heavy Duty Maintanaice Gas Turbine Frame 9

requirement for the rotor is that it must be inhot running condition prior to being dispatchedin frequency regulation mode.

Air Quality Maintenance and operating costs are also influ-enced by the quality of the air that the turbineconsumes. In addition to the deleterious effectsof airborne contaminants on hot-gas-path com-ponents, contaminants such as dust, salt and oilcan also cause compressor blade erosion, corro-sion and fouling. Twenty-micron particles enter-ing the compressor can cause significant bladeerosion. Fouling can be caused by submicrondirt particles entering the compressor as well asfrom ingestion of oil vapor, smoke, sea salt andindustrial vapors.

Corrosion of compressor blading causes pittingof the blade surface, which, in addition toincreasing the surface roughness, also serves aspotential sites for fatigue crack initiation. Thesesurface roughness and blade contour changeswill decrease compressor airflow and efficiency,which in turn reduces the gas turbine outputand overall thermal efficiency.

Generally, axial flow compressor deterioration isthe major cause of loss in gas turbine output andefficiency. Recoverable losses, attributable to com-pressor blade fouling, typically account for 70 to85 of the performance losses seen. As Figure 30illustrates, compressor fouling to the extent thatairflow is reduced by 5%, will reduce output by13% and increase heat rate by 5.5%. Fortunately,much can be done through proper operationand maintenance procedures to minimize foul-ing type losses. On-line compressor wash systemsare available that are used to maintain compres-sor efficiency by washing the compressor while atload, before significant fouling has occurred. Off-line systems are used to clean heavily fouled com-pressors. Other procedures include maintainingthe inlet filtration system and inlet evaporative

coolers as well as periodic inspection and promptrepair of compressor blading.

There are also non-recoverable losses. In thecompressor, these are typically caused by non-deposit-related blade surface roughness, ero-sion and blade tip rubs. In the turbine, nozzlethroat area changes, bucket tip clearanceincreases and leakages are potential causes.Some degree of unrecoverable performancedegradation should be expected, even on a well-maintained gas turbine.

The owner, by regularly monitoring and record-ing unit performance parameters, has a veryvaluable tool for diagnosing possible compres-sor deterioration.

Inlet Fogging One of the ways some users increase turbineoutput is through the use of inlet foggers.Foggers inject a large amount of moisture in theinlet ducting, exposing the forward stages ofthe compressor to a continuously moist envi-ronment. Operation of a compressor in suchan environment may lead to long-term degra-dation of the compressor due to fouling, mate-rial property degradation, corrosion and ero-sion. Experience has shown that depending on

GE Power Systems ■ GER-3620J ■ (01/03) 20

Figure 30. Deterioration of gas turbine performancedue to compressor blade fouling

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

Page 25: Heavy Duty Maintanaice Gas Turbine Frame 9

the quality of water used, the inlet silencer andducting material, and the condition of the inletsilencer, fouling of the compressor can besevere with inlet foggers. Evaporative coolercarryover and excessive water washing can pro-duce similar effects. Figure 31 shows the long-term material property degradation resultingfrom operating the compressor in a wet envi-ronment. The water quality standard thatshould be adhered to is found in GEK-101944B.

For turbines with 403SS compressor blades, thepresence of moisture will reduce blade fatiguestrength by as much as 30% as well as subjectthe blades to corrosion. Further reductions infatigue strength will result if the environment isacidic and if pitting is present on the blade.Pitting is corrosion-induced and blades with pit-ting can see material strength reduced to 40%of its virgin value. The presence of moisturealso increases the crack propagation rate in ablade if a flaw is present.

Uncoated GTD-450 material is relatively resistantto corrosion while uncoated 403SS is quite sus-ceptible. Relative susceptibility of various com-pressor blade materials and coatings is shown inFigure 32. As noted in GER-3569F, Al coatings aresusceptible to erosion damage leading to unpro-

tected sections of the blade. Because of this, theGECC-1 coating was created to combine theeffects of an Al coating to prevent corrosion anda ceramic topcoat to prevent erosion.

Water droplets, in excess of 25 microns in diam-eter, will cause leading edge erosion on the firstfew stages of the compressor. This erosion, ifsufficiently developed, may lead to blade fail-ure. Additionally, the roughened leading edgesurface lowers the compressor efficiency andunit performance.

It is recommended to check for erosion and pit-ting of the compressor blades after every 100hours of water wash. Utilization of inlet foggingor evaporative cooling may also introduce watercarryover or water ingestion into the compres-sor, resulting in R0 erosion. Although thedesign intent of evaporative coolers and inletfoggers should be to fully vaporize all coolingwater prior to its ingestion into the compressor,evidence suggests that on some systems thewater is not being fully vaporized (e.g., streak-ing discoloration on the inlet duct or bellmouth). If this is the case, then the unit shouldbe inspected every 100 hours of combinedwater wash, inlet fogger, and evaporative cooleroperation.

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 21

CORROSION DUE TO ENVIRONMENT AGGRAVATES PROBLEM• REDUCES VANE MATERIAL ENDURANCE STRENGTH•PITTING PROVIDES LOCALIZED STRESS RISERS

FATIGUE SENSITIVITY TO ENVIRONMENT

0.0

0.10.2

0.30.4

0.5

0.60.7

0.80.91.0

ESTIMATED FATIGUE STRENGTH (10 7 CYCLES) FOR AISI 403 BLADES

AL

TE

RN

AT

ING

ST

RE

SS

R

AT

IO

SOUND BLADE RT

SOUND BLADE 200°F

WET STEAM RT

ACID H2O 180 °F

PITTED IN AIR

Figure 31. Long term material property degradationin a wet environment

Bare

Al Slurry Coatings

NiCd + Topcoats

Ceramic

NiCd

Bare

0 2 4 6 8 10

Worst Best

GTD-450

AISI 403

Relative Corrosion Resistance

Figure 32. Relative susceptibility of compressorblade materials and coatings

Page 26: Heavy Duty Maintanaice Gas Turbine Frame 9

Maintenance InspectionsMaintenance inspection types may be broadlyclassified as standby, running and disassemblyinspections. The standby inspection is performedduring off-peak periods when the unit is notoperating and includes routine servicing of acces-sory systems and device calibration. The runninginspection is performed by observing key operat-ing parameters while the turbine is running. Thedisassembly inspection requires opening the tur-bine for inspection of internal components and isperformed in varying degrees. Disassemblyinspections progress from the combustion inspec-tion to the hot-gas-path inspection to the majorinspection as shown in Figure 33. Details of each ofthese inspections are described below.

Standby Inspections

Standby inspections are performed on all gasturbines but pertain particularly to gas turbinesused in peaking and intermittent-duty servicewhere starting reliability is of primary concern.This inspection includes routinely servicing thebattery system, changing filters, checking oil andwater levels, cleaning relays and checking devicecalibrations. Servicing can be performed in off-peak periods without interrupting the availabili-ty of the turbine. A periodic startup test run is an

essential part of the standby inspection.

The Maintenance and Instructions Manual, aswell as the Service Manual Instruction Books,contain information and drawings necessary toperform these periodic checks. Among themost useful drawings in the Service ManualInstruction Books for standby maintenance arethe control specifications, piping schematic andelectrical elementaries. These drawings providethe calibrations, operating limits, operatingcharacteristics and sequencing of all controldevices. This information should be used regu-larly by operating and maintenance personnel.Careful adherence to minor standby inspectionmaintenance can have a significant effect onreducing overall maintenance costs and main-taining high turbine reliability. It is essentialthat a good record be kept of all inspectionsmade and of the maintenance work performedin order to ensure establishing a sound mainte-nance program.

Running InspectionsRunning inspections consist of the general andcontinued observations made while a unit isoperating. This starts by establishing baselineoperating data during initial startup of a newunit and after any major disassembly work. This

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 22

Figure 33. MS7001EA heavy-duty gas turbine - shutdown inspection

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baseline then serves as a reference from whichsubsequent unit deterioration can be measured.

Data should be taken to establish normal equip-ment start-up parameters as well as key steadystate operating parameters. Steady state isdefined as conditions at which no more than a5°F/3°C change in wheelspace temperatureoccurs over a 15-minute time period. Data mustbe taken at regular intervals and should berecorded to permit an evaluation of the turbineperformance and maintenance requirements asa function of operating time. This operatinginspection data, summarized in Figure 34,includes: load versus exhaust temperature,vibration, fuel flow and pressure, bearing metaltemperature, lube oil pressure, exhaust gas tem-peratures, exhaust temperature spread varia-tion and startup time. This list is only a mini-mum and other parameters should be used asnecessary. A graph of these parameters will helpprovide a basis for judging the conditions of thesystem. Deviations from the norm help pinpointimpending trouble, changes in calibration ordamaged components.

Load vs. Exhaust Temperature The general relationship between load and

exhaust temperature should be observed andcompared to previous data. Ambient temperatureand barometric pressure will have some effectupon the absolute temperature level. Highexhaust temperature can be an indicator of dete-rioration of internal parts, excessive leaks or afouled air compressor. For mechanical drive appli-cations, it may also be an indication of increasedpower required by the driven equipment.

Vibration Level The vibration signature of the unit should beobserved and recorded. Minor changes willoccur with changes in operating conditions.However, large changes or a continuouslyincreasing trend give indications of the need toapply corrective action.

Fuel Flow and Pressure

The fuel system should be observed for the gen-eral fuel flow versus load relationship. Fuel pres-sures through the system should be observed.Changes in fuel pressure can indicate the fuelnozzle passages are plugged, or that fuel meter-ing elements are damaged or out of calibration.

Exhaust Temperature and Spread Variation The most important control function to be

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GE Power Systems ■ GER-3620J ■ (01/03) 23

Figure 34. Operating inspection data parameters

• Speed• Load• Fired Starts• Fired Hours• Site Barometric Reading• Temperatures

– Inlet Ambient– Compressor Discharge– Turbine Exhaust– Turbine Wheelspace– Lube Oil Header– Lube Oil Tank– Bearing Metal– Bearing Drains– Exhaust

• Pressures– Compressor Discharge– Lube Pump(s)– Bearing Header– Cooling Water– Fuel– Filters (Fuel, Lube, Inlet Air)

• Vibration Data for Power Train• Generator

– Output Voltage – Field Voltage– Phase Current – Field Current– VARS – Stator Temp.– Load – Vibration

• Start-Up Time• Coast-Down Time

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observed is the exhaust temperature fuel over-ride system and the back-up over temperaturetrip system. Routine verification of the opera-tion and calibration of these functions will min-imize wear on the hot-gas-path parts.

The variations in turbine exhaust temperaturespread should be measured and monitored ona regular basis. Large changes or a continuous-ly increasing trend in exhaust temperaturespread indicate combustion system deteriora-tion or fuel distribution problems. If the prob-lem is not corrected, the life of downstream hot-gas-path parts will be reduced.

Start-Up Time Start-up time is an excellent reference againstwhich subsequent operating parameters can becompared and evaluated. A curve of the startingparameters of speed, fuel signal, exhaust tem-perature and critical sequence bench marks ver-sus time from the initial start signal will providea good indication of the condition of the con-trol system. Deviations from normal conditionshelp pinpoint impending trouble, changes incalibration or damaged components.

Coast-Down Time Coast-down time is an excellent indicator ofbearing alignment and bearing condition. Thetime period from when the fuel is shut off on anormal shutdown until the rotor comes to astandstill can be compared and evaluated.

Close observation and monitoring of theseoperating parameters will serve as the basis foreffectively planning maintenance work andmaterial requirements needed for subsequentshutdown periods.

Combustion Inspection The combustion inspection is a relatively shortdisassembly shutdown inspection of fuel noz-zles, liners, transition pieces, crossfire tubes andretainers, spark plug assemblies, flame detec-

tors and combustor flow sleeves. This inspec-tion concentrates on the combustion liners,transition pieces, fuel nozzles and end capswhich are recognized as being the first torequire replacement and repair in a good main-tenance program. Proper inspection, mainte-nance and repair (Figure 35) of these items willcontribute to a longer life of the downstreamparts, such as turbine nozzles and buckets.

Figure 33 illustrates the section of an MS7001EAunit that is disassembled for a combustioninspection. The combustion liners, transitionpieces and fuel nozzle assemblies should beremoved and replaced with new or repairedcomponents to minimize downtime. Theremoved liners, transition pieces and fuel noz-zles can then be cleaned and repaired after theunit is returned to operation and be availablefor the next combustion inspection interval.Typical combustion inspection requirementsfor MS6001B/7001EA/9001E machines are:

■ Inspect and identify combustionchamber components.

■ Inspect and identify each crossfiretube, retainer and combustion liner.

■ Inspect combustion liner for TBCspallation, wear and cracks. Inspectcombustion system and dischargecasing for debris and foreign objects.

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Figure 35. Combustion inspection - key elements

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■ Inspect flow sleeve welds for cracking.

■ Inspect transition piece for wear andcracks.

■ Inspect fuel nozzles for plugging attips, erosion of tip holes and safetylock of tips.

■ Inspect all fluid, air, and gas passagesin nozzle assembly for plugging,erosion, burning, etc.

■ Inspect spark plug assembly forfreedom from binding, checkcondition of electrodes andinsulators.

■ Replace all consumables and normalwear-and-tear items such as seals,lockplates, nuts, bolts, gaskets, etc.

■ Perform visual inspection of first-stageturbine nozzle partitions andborescope inspect (Figure 3) turbinebuckets to mark the progress of wearand deterioration of these parts. Thisinspection will help establish theschedule for the hot-gas-pathinspection.

■ Perform borescope inspection ofcompressor.

■ Enter the combustion wrapper andobserve the condition of blading inthe aft end of axial-flow compressorwith a borescope.

■ Visually inspect the compressor inletand turbine exhaust areas, checkingcondition of IGVs, IGV bushings, last-stage buckets and exhaust systemcomponents.

■ Verify proper operation of purge andcheck valves. Confirm proper settingand calibration of the combustioncontrols.

After the combustion inspection is completeand the unit is returned to service, the removedcombustion liners and transition pieces can bebench inspected and repaired, if necessary, byeither competent on-site personnel, or off-siteat a qualified GE Combustion Service Center.The removed fuel nozzles can be cleaned on-site and flow tested on-site, if suitable test facili-ties are available. For F Class gas turbines it isrecommended that repairs and fuel nozzle flowtesting be performed at qualified GE ServiceCenters.

Hot-Gas-Path Inspection

The purpose of a hot-gas-path inspection is toexamine those parts exposed to high tempera-tures from the hot gases discharged from thecombustion process. The hot-gas-path inspec-tion outlined in Figure 36 includes the full scopeof the combustion inspection and, in addition,a detailed inspection of the turbine nozzles, sta-tionary stator shrouds and turbine buckets. Toperform this inspection, the top half of the tur-bine shell must be removed. Prior to shellremoval, proper machine centerline supportusing mechanical jacks is necessary to assureproper alignment of rotor to stator, obtain accu-rate half-shell clearances and prevent twisting ofthe stator casings. The MS7001EA jacking pro-cedure is illustrated in Figure 37.

For inspection of the hot-gas-path (Figure 33),all combustion transition pieces and the first-stage turbine nozzle assemblies must beremoved. Removal of the second- and third-stage turbine nozzle segment assemblies isoptional, depending upon the results of visualobservations and clearance measurement. Thebuckets can usually be inspected in place. Also,it is usually worthwhile to fluorescent penetrant

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inspect (FPI) the bucket vane sections to detectany cracks. In addition, a complete set of inter-nal turbine radial and axial clearances (open-ing and closing) must be taken during any hot-gas-path inspection. Re-assembly must meetclearance diagram requirements to ensureagainst rubs and to maintain unit performance.Typical hot gas-path inspection requirementsfor all machines are:

■ Inspect and record condition of first-,second- and third-stage buckets. If it isdetermined that the turbine buckets

should be removed, follow bucketremoval and condition recordinginstructions. Buckets with protectivecoating should be evaluated forremaining coating life.

■ Inspect and record condition of first-,second- and third-stage nozzles.

■ Inspect and record condition oflater-stage nozzle diaphragmpackings.

■ Check seals for rubs and deteriorationof clearance.

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Figure 37. Stator tube jacking procedure - MS7001EA

Figure 36. Hot-gas-path inspection - key elements

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■ Record the bucket tip clearances.

■ Inspect bucket shank seals forclearance, rubs and deterioration.

■ Check the turbine stationary shroudsfor clearance, cracking, erosion,oxidation, rubbing and build-up.

■ Check and replace any faultywheelspace thermocouples.

■ Enter compressor inlet plenum andobserve the condition of the forwardsection of the compressor. Pay specificattention to IGVs, looking forcorrosion, bushing wear evidenced byexcessive clearance and vane cracking.

■ Enter the combustion wrapper and,with a borescope, observe thecondition of the blading in the aft endof the axial flow compressor.

■ Visually inspect the turbine exhaustarea for any signs of cracking ordeterioration.

The first-stage turbine nozzle assembly isexposed to the direct hot-gas discharge fromthe combustion process and is subjected to thehighest gas temperatures in the turbine section.Such conditions frequently cause nozzle crack-ing and oxidation and, in fact, this is expected.The second- and third-stage nozzles areexposed to high gas bending loads which, incombination with the operating temperatures,can lead to downstream deflection and closureof critical axial clearances. To a degree, nozzledistress can be tolerated and criteria have beenestablished for determining when repair isrequired. These limits are contained in theMaintenance and Instruction Books previouslydescribed. However, as a general rule, first stagenozzles will require repair at the hot-gas pathinspection. The second- and third-stage nozzles

may require refurbishment to re-establish theproper axial clearances. Normally, turbine nozzles can be repaired several times to extendlife and it is generally repair cost versus replacement cost that dictates the replacementdecision.

Coatings play a critical role in protecting thebuckets operating at high metal temperaturesto ensure that the full capability of the highstrength superalloy is maintained and that thebucket rupture life meets design expectations.This is particularly true of cooled bucketdesigns that operate above 1985°F (1085°C) fir-ing temperature. Significant exposure of thebase metal to the environment will acceleratethe creep rate and can lead to prematurereplacement through a combination ofincreased temperature and stress and a reduc-tion in material strength, as described in Figure38. This degradation process is driven by oxida-tion of the unprotected base alloy. In the past,on early generation uncooled designs, surfacedegradation due to corrosion or oxidation wasconsidered to be a performance issue and not afactor in bucket life. This is no longer the caseat the higher firing temperatures of currentgeneration designs.

Given the importance of coatings, it must berecognized that even the best coatings availablewill have a finite life and the condition of thecoating will play a major role in determiningbucket replacement life. Refurbishmentthrough stripping and recoating is an optionfor extending bucket life, but if recoating isselected, it should be done before the coatinghas breached to expose base metal. Normally,for turbines in the MS7001EA class, this meansthat recoating will be required at the hot-gas-path inspection. If recoating is not performedat the hot-gas-path inspection, the runout life ofthe buckets would generally extend to the

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

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major inspection, at which point the bucketswould be replaced. For F class gas turbinesrecoating of the first stage buckets is recom-mended at each hot gas path inspection.

Visual and borescope examination of the hotgas-path parts during the combustion inspec-tions as well as nozzle-deflection measurementswill allow the operator to monitor distress pat-terns and progression. This makes part-life pre-dictions more accurate and allows adequatetime to plan for replacement or refurbishmentat the time of the hot-gas-path inspection. It isimportant to recognize that to avoid extendingthe hot-gas-path inspection, the necessary spareparts should be on site prior to taking the unitout of service.

Major Inspection

The purpose of the major inspection is to exam-ine all of the internal rotating and stationarycomponents from the inlet of the machinethrough the exhaust section of the machine. Amajor inspection should be scheduled in accor-dance with the recommendations in the owner'sMaintenance and Instructions Manual or asmodified by the results of previous borescope

and hot-gas-path inspection. The work scopeshown in Figure 39 involves inspection of all ofthe major flange-to-flange components of thegas turbine which are subject to deteriorationduring normal turbine operation. This inspec-tion includes previous elements of the combus-tion and hot-gas-path inspections, in addition tolaying open the complete flange-to-flange gasturbine to the horizontal joints, as shown inFigure 40, with inspections being performed onindividual items.

Prior to removing casings, shells and frames,the unit must be properly supported. Propercenterline support using mechanical jacks andjacking sequence procedures are necessary toassure proper alignment of rotor to stator,obtain accurate half shell clearances and to pre-vent twisting of the casings while on the halfshell.

Typical major inspection requirements for allmachines are:

■ All radial and axial clearances arechecked against their original values(opening and closing).

■ Casings, shells and frames/ diffusersare inspected for cracks and erosion.

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GE Power Systems ■ GER-3620J ■ (01/03) 28

Figure 38. Stage 1 bucket oxidation and bucket life

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■ Compressor inlet and compressor flow-path are inspected for fouling, erosion,corrosion and leakage. The IGVs areinspected, looking for corrosion,bushing wear and vane cracking.

■ Rotor and stator compressor blades arechecked for tip clearance, rubs, impactdamage, corrosion pitting, bowing andcracking.

■ Turbine stationary shrouds arechecked for clearance, erosion,rubbing, cracking, and build-up.

■ Seals and hook fits of turbine nozzlesand diaphragms are inspected for rubs,

erosion, fretting or thermaldeterioration.

■ Turbine buckets are removed and anon-destructive check of bucketsand wheel dovetails is performed(first stage bucket protective coatingshould be evaluated for remainingcoating life). Buckets that were notrecoated at the hot-gas-pathinspection should be replaced.

■ Rotor inspections recommended inthe maintenance and inspectionmanual or by Technical InformationLetters should be performed.

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GE Power Systems ■ GER-3620J ■ (01/03) 29

Figure 39. Gas turbine major inspection - key elements

Figure 40. Major inspection work scope

Major InspectionHot Gas Path Inspection Work Scope – Plus:

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■ Bearing liners and seals are inspectedfor clearance and wear.

■ Inlet systems are inspected forcorrosion, cracked silencers and looseparts.

■ Exhaust systems are inspected forcracks, broken silencer panels orinsulation panels.

■ Check alignment - gas turbine togenerator/gas turbine to accessorygear.

Comprehensive inspection and maintenanceguidelines have been developed by GE and areprovided in the Maintenance and InstructionsManual to assist users in performing each of theinspections previously described.

Parts Planning Lack of adequate on-site spares can have amajor effect on plant availability; therefore,prior to a scheduled disassembly type of inspec-tion, adequate spares should be on site. Aplanned outage such as a combustion inspec-tion, which should only take two to five days,could take weeks. GE will provide recommen-dations regarding the types and quantities ofspare parts needed; however, it is up to theowner to purchase these spare parts on aplanned basis allowing adequate lead times.

Early identification of spare parts requirementsensures their availability at the time theplanned inspections are performed. There aretwo documents which support the ordering ofgas turbine parts by catalog number. The first isthe Renewal Parts Catalog - Illustrations andText. This document contains generic illustra-tions which are used for identifying parts. Thesecond document, the Renewal Parts CatalogOrdering Data Manual, contains unit site-spe-cific catalog ordering data.

Additional benefits available from the renewalparts catalog data system are the capability toprepare recommended spare parts lists for thecombustion, hot-gas-path and major inspec-tions as well as capital and operational spares.

Furthermore, interchangeability lists may beprepared for multiple units. The informationcontained in the Catalog Ordering DataManual can be provided as a computer print-out, on microfiche or on a computer disc. Asthe size of the database grows, and as genericillustrations are added, the usefulness of thistool will be continuously enhanced.

Typical expectations for estimated repair cyclesfor some of the major components are shown inAppendix D. These tables assume that operationof the unit has been in accordance with all of themanufacturer's specifications and instructions.Maintenance inspections and repairs are alsoassumed to be done in accordance with themanufacturer's specifications and instructions.The actual repair and replacement cycles for anyparticular gas turbine should be based on theuser's operating procedures, experience, main-tenance practices and repair practices. Themaintenance factors previously described canhave a major impact on both the componentrepair interval and service life. For this reason,the intervals given in Appendix D should only beused as guidelines and not certainties for longrange parts planning. Owners may want toinclude contingencies in their parts planning.

The expected repair and replacement cycle val-ues reflect current production hardware. Toachieve these lives, current production partswith design improvements and newer coatingsare required. With earlier production hard-ware, some of these lives may not be achieved.Operating factors and experience gained dur-ing the course of recommended inspection and

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maintenance procedures will be a more accu-rate predictor of the actual intervals.

Appendix D shows expected repair and replace-ment intervals based on the recommendedinspection intervals shown in Figure 42. Theapplication of inspection (or repair) intervalsother than those shown in Figure 42 can result indifferent replacement intervals (as a function ofthe number of repair intervals) than thoseshown in Appendix D. See your GE representa-tive for details on a specific system.

It should be recognized that, in some cases, theservice life of a component is reached when it isno longer economical to repair any deteriora-tion as opposed to replacing at a fixed interval.This is illustrated in Figure 41 for a first stagenozzle, where repairs continue until either thenozzle cannot be restored to minimum accept-ance standards or the repair cost exceeds orapproaches the replacement cost. In othercases, such as first-stage buckets, repair optionsare limited by factors such as irreversible mate-rial damage. In both cases, users should followGE recommendations regarding replacementor repair of these components.

While the parts lives shown in Appendix D areguidelines, the life consumption of individual

parts within a parts set can have variations. Therepair versus replacement economics shown inFigure 41 may lead to a certain percentage of"fallout", or scrap, of parts being repaired.Those parts that fallout during the repairprocess will need to be replaced by new parts.The amount of fallout of parts depends on theunit operating environment history, the specificpart design, and the current state-of-the-art forrepair technology.

Inspection Intervals

Figure 42 lists the recommended combustion,hot-gas-path and major inspection intervals forcurrent production GE turbines operatingunder ideal conditions of gas fuel, base load,and no water or steam injection. Consideringthe maintenance factors discussed previously, anadjustment from these maximum intervals maybe necessary, based on the specific operatingconditions of a given application. Initially, thisdetermination is based on the expected opera-tion of a turbine installation, but this should bereviewed and adjusted as actual operating andmaintenance data are accumulated. Whilereductions in the maximum intervals will resultfrom the factors described previously, increasesin the maximum interval can also be considered

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Figure 41. First-stage nozzle wear-preventive maintenance gas fired - continuous duty - base load

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where operating experience has been favorable.The condition of the hot-gas-path parts providesa good basis for customizing a program ofinspection and maintenance.

GE can assist operators in determining theappropriate maintenance intervals for their par-ticular application. Equations have been devel-oped that account for the factors described ear-lier and can be used to determine applicationspecific hot-gas-path and major inspectionintervals. The hours-based hot-gas-path criteri-on is determined from the equation given inFigure 43. With this equation, a maintenancefactor is determined that is the ratio of factoredoperating hours and actual operating hours.The factored hours consider the specifics of theduty cycle relating to fuel type, load setting andsteam or water injection. Maintenance factorsgreater than one reduce the hot gas pathinspection interval from the 24,000 hour idealcase for continuous base load, gas fuel and nosteam or water injection. To determine theapplication specific maintenance interval, themaintenance factor is divided into 24,000, asshown in Figure 43.

The starts-based hot-gas-path criterion is deter-mined from the equation given in Figure 44. Aswith the hours-based criteria, an applicationspecific starts-based hot gas path inspectioninterval is calculated from a maintenance factorthat is determined from the number of tripstypically being experienced, the load level andloading rate.

As previously described, the hours and startsoperating spectrum for the application is evalu-ated against the recommended hot gas path

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MS3002KMS5001PA / MS5002C,D MS6B MS7E/EA MS9E MS6FA MS7F/FA/FA+ MS7FA+e MS9F/FA/FA+ MS9FA+e MS7FB

Non-DLN 24,000/400 12,000/800* 12,000/1,200** 8,000/900 8,000/900 - - - - - -DLN - 8,000/400 12,000/450 12,000/450 12,000/450 8,000/450 8,000/450 12,000/450 8,000/450 8,000/450 8,000/450***

24,000/1,200 Eliminated/1,200 24,000/1,200 24,000/1,200 24,000/900 24,000/900 24,000/900 24,000/900 24,000/900 24,000/900 24,000/90048,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400 48,000/2,400Major

Combustion System

Factored Hours / Factored StartsType of Inspection

Combustion

Hot Gas Path

Figure 42. Base line recommended inspection intervals: base load - gas fuel - dry

Figure 43. Hot gas path inspection: hours-based criterion

* Units with Lean Head End liners have a 400 starts combustion inspection interval.** Machines with 6581 and 6BeV combustion hardware have a 12,000/600 combustion inspection interval.*** The goal is to increase the Combustion Inspection Interval from 8,000/450 to 12,000/450. This will

be accomplished with new hardware designs.Note: Hours/Starts intervals include an allowance for nominal trip maintenance factor effects.

Factors That Can Reduce Maintenance Intervals• Fuel • Trips• Load Setting • Start Cycle• Steam/Water Injection • Hardware Design• Peak Load TF Operation

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intervals for starts and for hours. The limitingcriterion (hours or starts) determines the main-tenance interval. An example of the use of theseequations for the hot gas path is contained inthe appendix.

The starts-based rotor maintenance interval isdetermined from the equation given in Figure45. Adjustments to the rotor maintenance inter-val are determined from rotor-based operatingfactors as were described previously. In the cal-culation for the starts-based rotor maintenanceinterval, equivalent starts are determined forcold, warm, and hot starts over a defined timeperiod by multiplying the appropriate cold,warm and hot start operating factor times andnumber of cold, warm and hot starts respective-ly. In this calculation, the type of start must beconsidered. Additionally, equivalent starts fortrips from load are added. The equivalent starttotal is divided by the actual number of starts toyield the maintenance factor. The rotor starts-based maintenance interval for a specific appli-cation is determined by dividing the baselinerotor maintenance interval of 5000 starts by thecalculated maintenance factor. As indicated inFigure 45, the rotor maximum maintenanceinterval is 5000 starts. Calculated maintenance

factors that are less than one are not con-sidered.

Figure 46 describes the procedure to determinethe hours-based maintenance criterion. Peakload operation is the primary maintenance fac-tor for the Frame MS7001/9001F and FA classrotors and will act to increase the hours-basedmaintenance factor and to reduce the rotormaintenance interval. Hours on turning gearare also considered as an equivalent hoursadder as noted in Figure 46.

When the rotor reaches the limiting inspectioninterval determined from the equationsdescribed in Figures 45 and 46, a disassembly ofthe rotor is required so that a complete inspec-tion of the rotor components in both the com-pressor and turbine can be performed. Itshould be expected that some rotor compo-nents will require replacement at this inspec-tion point, and depending on the extent ofrefurbishment and part replacement, subse-quent inspections may be required at a reducedinterval. In cyclic applications where time onturning gear can be significant, the hours basedinspection requirement (Figure 46) should beinterpreted to require a careful inspection of

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Figure 44. Hot gas path inspection starts-based condition

MS6001/7001/9001

Maintenance Interval =(Starts)

Where:Maintenance Factor =

Factored Starts = (0.5 NA + NB + 1.3NP + 20E + 2F + aTI TI)

Actual Starts = (NA + NB + NP + E + F + T)

Factored StartsActual Starts η

Σi - 1

SMaintenance Factor

S = Maximum Starts-Based Maintenance Interval (Model Size Dependent)NA = Annual Number of Part Load Start/Stop Cycles (<60% Load)NB = Annual Number of Normal Base Load Start/Stop CyclesNP = Annual Number of Peak Load Start/Stop CyclesE = Annual Number of Emergency StartsF = Annual Number of Fast Load StartsT = Annual Number of TripsaT = Trip Severity Factor = f (Load) (See Figure 21)

η = Number of Trip Categories (i.e., Full Load, Part Load, etc.)

Model Series SMS6B/MS7EA 1,200MS6FA 900

Model Series SMS9E 900MS7F/7FA/9F/9FA 900

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the turbine rotor dovetails for conditions ofwear, galling or fretting.

For rotors other than Frame MS7001/9001Fand FA, rotor maintenance should be per-formed at intervals recommended by GEthrough issued Technical Information Letters.Where no recommendations have been made,rotor inspection should be performed at 5,000starts or 200,000 hours.

Equations have been developed that accountfor the earlier mentioned factors affecting com-bustion maintenance intervals. These equa-

tions represent a generic set of maintenancefactors that provide general guidance on main-tenance planning. As such, these equations donot represent the specific capability of any givencombustion system. They do provide, however,a generalization of combustion system experi-ence. See your GE representative for mainte-nance factors and limitations of specific com-bustion systems. For combustion parts, the baseline operating conditions that result in a main-tenance factor of unity are normal fired start-upand shut-down (no trip) to base load on naturalgas fuel without steam or water injection.Application of the ExtendorTM CombustionSystem Wear Kit has the potential to significant-ly increase maintenance intervals.

An hours-based combustion maintenance fac-tor can be determined from the equations givenin Figure 47 as the ratio of factored-hours toactual operating hours. Factored-hours consid-ers the effects of fuel type, load setting andsteam or water injection. Maintenance factorsgreater than one reduce recommended com-bustion inspection intervals from those shownin Figure 42 representing baseline operatingconditions. To obtain a recommended inspec-

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Figure 45. Rotor maintenance factor for starts-based criterion

Figure 46. Rotor maintenance factor for hours-basedcriterion

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tion interval for a specific application, themaintenance factor is divided into the recom-mended base line inspection interval.

A starts-based combustion maintenance factorcan be determined from the equations given inFigure 48 and considers the effect of fuel type,load setting, emergency starts, fast loadingrates, trips and steam or water injection. Anapplication specific recommended inspectioninterval can be determined from the baselineinspection interval in Figure 42 and the mainte-nance factor from Figure 48.

Appendix B shows six example maintenance fac-tor calculations using the above hours and startsmaintenance factors equations.

Manpower Planning It is essential that advanced manpower plan-ning be conducted prior to an outage. It shouldbe understood that a wide range of experience,productivity and working conditions existaround the world. However, based upon main-tenance inspection man-hour assumptions,such as the use of an average crew of workers in

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Figure 47. Combustion inspection hours-based maintenance factors

Figure 48. Combustion inspection starts-based maintenance factors

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the United States with trade skill (but not nec-essarily direct gas turbine experience), with allneeded tools and replacement parts (no repairtime) available, an estimate can be made. Theseestimated craft labor man-hours should includecontrols and accessories and the generator. Inaddition to the craft labor, additional resourcesare needed for technical direction of the craftlabor force, specialized tooling, engineeringreports, and site mobilization/de-mobilization.

Inspection frequencies and the amount ofdowntime varies within the gas turbine fleet dueto different duty cycles and the economic needfor a unit to be in a state of operational readi-ness. It can be demonstrated that an 8000-hourinterval for a combustion inspection with mini-mum downtime can be achievable based on theabove factors. Contact your local GE EnergyServices representative for the specific man-hours and recommended crew size for your spe-cific unit.

Depending upon the extent of work to be doneduring each maintenance task, a cooldown peri-od of 4 to 24 hours may be required. This timecan be utilized productively for job move-in,correct tagging and locking equipment out-of-service and general work preparations. At theconclusion of the maintenance work and sys-tems check out, a turning gear time of two toeight hours is normally allocated prior to start-ing the unit. This time can be used for jobclean-up and arranging for any repairs requiredon removed parts.

Local GE field service representatives are avail-able to help plan your maintenance work toreduce downtime and labor costs. This plannedapproach will outline the renewal parts thatmay be needed and the projected work scope,showing which tasks can be accomplished inparallel and which tasks must be sequential.

Planning techniques can be used to reducemaintenance cost by optimizing lifting equip-ment schedules and manpower requirements.Precise estimates of the outage duration,resource requirements, critical-path schedul-ing, recommended replacement parts, andcosts associated with the inspection of a specificinstallation may be obtained from the local GEfield services office.

Conclusion

GE heavy-duty gas turbines are designed to havean inherently high availability. To achieve maxi-mum gas turbine availability, an owner mustunderstand not only the equipment, but thefactors affecting it. This includes the training ofoperating and maintenance personnel, follow-ing the manufacturer's recommendations, reg-ular periodic inspections and the stocking ofspare parts for immediate replacement. Therecording of operating data, and analysis ofthese data, are essential to preventative andplanned maintenance. A key factor in achievingthis goal is a commitment by the owner to pro-vide effective outage management and full uti-lization of published instructions and the avail-able service support facilities.

It should be recognized that, while the manu-facturer provides general maintenance recom-mendations, it is the equipment user who hasthe major impact upon the proper maintenanceand operation of equipment. Inspection inter-vals for optimum turbine service are not fixedfor every installation, but rather are developedthrough an interactive process by each user,based on past experience and trends indicatedby key turbine factors. In addition, throughapplication of a Contractual Service Agreementto a particular turbine, GE can work with a user

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 36

Page 41: Heavy Duty Maintanaice Gas Turbine Frame 9

to establish a maintenance program that maydiffer from general recommendations but willbe consistent with contractual responsibilities.

The level and quality of a rigorous mainte-nance program have a direct impact on equip-ment reliability and availability. Therefore, arigorous maintenance program which opti-

mizes both maintenance cost and availability isvital to the user. A rigorous maintenance pro-gram will minimize overall costs, keep outagedowntimes to a minimum, improve startingand running reliability and provide increasedavailability and revenue earning ability for GEgas turbine users.

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 37

References Jarvis, G., “Maintenance of Industrial Gas Turbines,” GE Gas Turbine State of the Art Engineering

Seminar, paper SOA-24-72, June 1972.

Patterson, J. R., “Heavy-Duty Gas Turbine Maintenance Practices,” GE Gas Turbine ReferenceLibrary, GER 2498, June 1977.

Moore, W. J., Patterson, J.R, and Reeves, E.F., “Heavy-Duty Gas Turbine Maintenance Planning andScheduling,” GE Gas Turbine Reference Library, GER 2498; June 1977, GER 2498A, June 1979.

Carlstrom, L. A., et al., “The Operation and Maintenance of General Electric Gas Turbines,”numerous maintenance articles/authors reprinted from Power Engineering magazine, GeneralElectric Publication, GER 3148; December 1978.

Knorr, R. H., and Reeves, E. F., “Heavy-Duty Gas Turbine Maintenance Practices,” GE Gas TurbineReference Library, GER 3412; October 1983; GER 3412A, September 1984; and GER 3412B,December 1985.

Freeman, Alan, “Gas Turbine Advance Maintenance Planning,” paper presented at Frontiers ofPower, conference, Oklahoma State University, October 1987.

Hopkins, J. P, and Osswald, R. F., “Evolution of the Design, Maintenance and Availability of a LargeHeavy-Duty Gas Turbine,” GE Gas Turbine Reference Library, GER 3544, February 1988 (neverprinted).

Freeman, M. A., and Walsh, E. J., “Heavy-Duty Gas Turbine Operating and MaintenanceConsiderations,” GE Gas Turbine Reference Library, GER 3620A.

GEI-41040E, “Fuel Gases for Combustion in Heavy-Duty Gas Turbines.”

GEK-101944B, “Requirements for Water/Steam Purity in Gas Turbines.”

GER-3569F, “Advanced Gas Turbine Materials and Coatings.”

Acknowledgments

The efforts of Thomas Farrell, Kevin Spengler, Mark Duer, Roointon Pavri, and Keith Belsom tocontribute to the development of this document are very much appreciated.

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GE Power Systems ■ GER-3620J ■ (01/03) 38

AppendixA) Example—Maintenance Interval

Calculation

An MS7001EA user has accumulated operatingdata since the last hot gas path inspection andwould like to estimate when the next oneshould be scheduled. The user is aware fromGE publications that the normal HGP interval is24,000 hours if operating on natural gas, nowater or steam injection, base load. Also, thereis a 1200 start interval, based on normal start-ups, no trips, no emergency starts. The actualoperation of the unit since the last hot gas pathinspection is much different from the GE “base-line case.”

Annual hours on natural gas, base load = G = 3200 hr/yr

Annual hours on light distillate = D = 350 hr/yr

Annual hours on peak load = P = 120 hr/yr

Steam injection rate = I = 2.4%

Also, since the last hot gas path inspection,

The annual number of normal starts is = NB = 100/yr

The annual number of peak load starts = NP = 0/yr

The annual number of part load starts = NA = 40/yr

The annual number of emergency starts = E = 2/yr

The annual number of fast load starts = F = 5/yr

The annual number of trips from load (aT = 8)= T = 20/yr

For this particular unit, the second and third-stage nozzles are FSX-414 material. The unitoperates on “dry control curve.”

From Figure 43, at a steam injection rate of2.4%, the value of “M” is .18, and “K” is .6.

From the hours-based criteria, the mainte-nance factor is determined from Figure 43.

MF =[.6 + .18(2.4)] x [3200 + 1.5(350) +6(120)]

(3200 + 350 + 120)

MF = 1.25

The hours-based adjusted inspection interval istherefore,

H = 24,000/1.25

H = 19,200 hours [Note, since total annualoperating hours is 3670,the estimated time toreach 19,200 hours is 5.24years (19,200/3670).]

From the starts-based criteria, the maintenancefactor is determined from Figure 43.

MF = [100 + .5(40) + 20(2) + 2(5) + 8(20)]

(100 + 40 + 2 + 5 + 20)

MF = 2.0

The adjusted inspection interval based onstarts is,

S = 1200/2.0

S = 600 starts [Note, since the total annualnumber of starts is 167, theestimated time to reach 600starts is 600/167 = 3.6 years.]

In this case, the starts-based maintenance fac-tor is greater than the hours maintenance fac-tor and therefore the inspection interval is setby starts. The hot gas path inspection intervalis 600 starts (or 3.6 years).

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GE Power Systems ■ GER-3620J ■ (01/03) 39

C) Definitions

Reliability: Probability of not being forced outof service when the unit is needed—includesforced outage hours (FOH) while in service,while on reserve shutdown and while attempt-

ing to start normalized by period hours(PH)—units are %.

Reliability = (1-FOH/PH) (100)FOH = total forced outage hours PH = period hours

7EA DLN-1 Peaking Duty with Power Augmentation 7EA Standard Combustor Baseload on Crude Oil+50F Tfire Increase Gas Fuel No Tfire Increase Crude Oil Fuel3.5% Steam Augmentation 6 Hours/Start 1.0 Water/Fuel Ratio 220 Hours/StartStart with Fast Load Wet Control Curve Normal Start and Load Dry Control CurveNormal Shut Down (No Trip) Normal Shut Down (No Trip)Factored Hours = Ki * Afi * Api * ti = 34.5 Hours Factored Hours = Ki * Afi * Api * ti = 788.3 HoursHours Maintenance Factor = (34.5/6) 5.8 Hours Maintenance Factor = (788.3/220) 3.6

Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) Wet Where Ki = 1.43 Max(1.0, exp(1.80(1.00-0.80))) DryAfi = 1.00 Gas Fuel Afi = 2.50 Crude Oil, Std (Non-DLN)Api = 2.46 exp(0.018(50)) Peaking Api = 1.00 Baseloadti = 6.0 Hours/Start ti = 220.0 Hours/Start

Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.2 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.9 StartsStarts Maintenance Factor = (5.2/1) 5.2 Starts Maintenance Factor = (5.9/1) 5.9

Where Ki = 2.77 Max(1.0, exp(0.34(3.50-0.50))) Wet Where Ki = 2.94 Max(1.0, exp(1.80(1.00-0.40))) DryAfi = 1.00 Gas Fuel Afi = 2.00 Crude Oil, Std (Non-DLN)Ati = 1.00 No Trip at Load Ati = 1.00 No Trip at LoadApi = 1.57 exp(0.009(50)) Peaking Api = 1.00 BaseloadAsi = 1.20 Start with Fast Load Asi = 1.00 Normal StartNi 1.0 Considering Each Start Ni 1.0 Considering Each Start

7FA+e DLN 2.6 Baseload on Distillate 7FA+e DLN 2.6 Baseload on Gas with Trip @ LoadNo Tfire Increase Distillate Fuel No Tfire Increase Gas Fuel1.1 Water/Fuel Ratio 220 Hours/Start No Steam/Water Injection 168 Hours/StartNormal Start Dry Control Curve Normal Start and Load Dry Control CurveNormal Shut Down (No Trip) Trip @ 60% Load Factored Hours = Ki * Afi * Api * ti = 943.8 Hours Factored Hours = Ki * Afi * Api * ti = 168.0 HoursHours Maintenance Factor = (943.8/220) 4.3 Hours Maintenance Factor = (168.0/168) 1.0

Where Ki = 1.72 Max(1.0, exp(1.80(1.10-0.80))) Dry Where Ki = 1.00 No InjectionAfi = 2.50 Distillate Fuel, DLN Afi = 1.00 Gas FuelApi = 1.00 Baseload Api = 1.00 Baseloadti = 220.0 Hours/Start ti = 168.0 Hours/Start

Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.3 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 2.6 StartsStarts Maintenance Factor = (5.3/1) 5.3 Starts Maintenance Factor = (2.6/1) 2.6

Where Ki = 3.53 Max(1.0, exp(1.80(1.10-0.40))) Dry Where Ki = 1.00 No InjectionAfi = 1.50 Distillate Fuel, DLN Afi = 1.00 Gas FuelAti = 1.00 No Trip at Load Ati = 2.62 0.5+exp(0.0125*60) for TripApi = 1.00 Baseload Api = 1.00 BaseloadAsi = 1.00 Normal Start Asi = 1.00 Normal StartNi 1.0 Considering Each Start Ni 1.0 Considering Each Start

7EA DLN 1 Combustor Baseload on Distillate 7FA+e DLN 2.6 Peak Load on Gas with Emergency StartsNo Tfire Increase Distillate Fuel +35F Tfire Increase Gas Fuel0.9 Water/Fuel Ratio 500 Hours/Start 3.5% Steam Augmentation 4 Hours/StartNormal Start Dry Control Curve Emergency Starts Dry Control CurveNormal Shut Down (No Trip) Normal Shut Down (No Trip) Factored Hours = Ki * Afi * Api * ti = 1496.5 Hours Factored Hours = Ki * Afi * Api * ti = 12.5 HoursHours Maintenance Factor = (1496.5/500) 3.0 Hours Maintenance Factor = (12.5/4) 3.1

Where Ki = 1.20 Max(1.0, exp(1.80(0.90-0.80))) Dry Where Ki = 1.67 Max(1.0, exp(0.34(3.50-2.00))) DryAfi = 2.50 Distillate Fuel, DLN Afi = 1.00 Gas FuelApi = 1.00 Part Load Api = 1.88 exp(0.018(35)) Peakingti = 500.0 Hours/Start ti = 4.0 Hours/Start

Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 3.7 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 9.6 StartsStarts Maintenance Factor = (3.7/1) 3.7 Starts Maintenance Factor = (9.6/1) 9.6

Where Ki = 2.46 Max(1.0, exp(1.80(0.90-0.40))) Dry Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) DryAfi = 1.50 Distillate Fuel, DLN Afi = 1.00 Gas FuelAti = 1.00 No Trip at Load Ati = 1.00 No Trip at LoadApi = 1.00 Part Load Api = 1.37 exp(0.009(35)) PeakingAsi = 1.00 Normal Start Asi = 3.00 Emergency StartNi 1.0 Considering Each Start Ni 1.0 Considering Each Start

B) Combustion Maintenance Interval Calculations

Figure B-1. Combustion maintenance interval calculations

Page 44: Heavy Duty Maintanaice Gas Turbine Frame 9

Availability: Probability of being available,independent of whether the unit is needed—includes all unavailable hours (UH) – normal-ized by period hours (PH) – units are %:

Availability = (1-UH/PH) (100)

UH = total unavailable hours (forced out-age, failure to start, scheduled main-tenance hours, unscheduled mainte-nance hours)

PH = period hours

Equivalent Reliability: Probability of a multi-shaft combined-cycle power plant not beingtotally forced out of service when the unit isrequired includes the effect of the gas andsteam cycle MW output contribution to plantoutput — units are %.

Equivalent Reliability =GT FOH HRSG FOH ST FOH

GT PH B PH ST PH

GT FOH = Gas Turbine Forced OutageHours

GT PH = Gas Turbine Period Hours HRSG FOH = HRSG Forced Outage HoursB PH = HRSG Period Hours ST FOH = Steam Turbine Forced Outage

Hours

ST PH = Steam Turbine Period Hours

B = Steam Cycle MW OutputContribution (normally 0.30)

Equivalent Availability: Probability of a multi-shaft combined-cycle power plant being avail-able for power generation—independent ofwhether the unit is needed—includes allunavailable hours—includes the effect of thegas and steam cycle MW output contributionto plant output; units are %.

Equivalent Availability =GT UH HRSG UH ST UH

GT PH GT PH ST PH

GT UH = Gas Turbine UnavailableHours

GT PH = Gas Turbine Period Hours HRSG UH = HRSG Total Unavailable

HoursST UH = Steam Turbine Unavailable

Hours ST PH = Steam Turbine Forced Outage

HoursB = Steam Cycle MW Output

Contribution (normally 0.30)

MTBF–Mean Time Between Failure: Measure ofprobability of completing the current run.Failure events are restricted to forced outages(FO) while in service — units are service hours.

MTBF = SH/FO

SH = Service Hours

FO = Forced Outage Events from aRunning (On-line) Condition

Service Factor: Measure of operational use, usu-ally expressed on an annual basis — units are %.

SF = SH/PH x 100

SH = Service Hours on an annual basis

PH = Period Hours (8760 hours per year)

Operating Duty Definition:

FiredDuty Service Factor Hours/Start

Stand-by < 1% 1 to 4Peaking 1% - 17% 3 to 10Cycling 17% - 50% 10 to 50

Continuous > 90% >> 50

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 40

+ B + x 100][ ( )][1 –

+ B + x 100][ ( )][1 –

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 41

Figure D-1. Estimated repair and replacement cycles

MS3002K PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 2 (CI) 4 (CI)Transition Pieces CI / HGPI 2 (CI) 2 (HGPI)Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI)Stage 2 Nozzles MI 2 (MI) 2 (MI)Stage 1 Shrouds MI 2 (MI) 2 (MI)Stage 2 Shrouds MI 2 (MI) 2 (MI)Stage 1 Bucket - 1 (MI)(1)

3 (HGPI)Stage 2 Bucket - 1 (MI) 3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection IntervalMI = Major Inspection Interval(1) GE approved repair at 24,000 hours will extend life to 72,000 hours.

Figure D-2. Estimated repair and replacement cycles

MS5001PA / MS5002C,D PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 4 (CI) 3 (CI) / 4 (CI) (1)

Transition Pieces CI / HGPI 4 (CI)(2) 2 (HGPI)Stage 1 Nozzles HGPI / MI 2 (MI) 2 (HGPI)Stage 2 Nozzles HGPI / MI 2 (MI) 2 (HGPI) / 2 (MI) (3)

Stage 1 Shrouds MI 2 (MI) 2 (MI)Stage 2 Shrouds - 2 (MI) 2 (MI)Stage 1 Bucket - 1 (MI)(4)

3 (HGPI)Stage 2 Bucket - 1 (MI) 3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection IntervalMI = Major Inspection Interval(1) 3 (CI) for non-DLN units / (4) CI for DLN units(2) Repair interval is every 2 (CI).(3) 2 (HGPI) for MS5001PA / 2 (MI) for MS5002C,D(4) GE approved repair at 24,000 hours will extend life to 72,000 hours.

D) Repair and Replacement Cycles

Figure D-3. Estimated repair and replacement cycles

PG6581B / 6BeV PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 4 (CI) 4 (CI) / 5 (CI) (1)

Caps CI 4 (CI) 5 (CI)Transition Pieces CI 4 (CI) 4 (CI) / 5 (CI) (1)

Fuel Nozzles CI 2 (CI) 2 (CI) / 3 (CI) (2)

Crossfire Tubes CI 2 (CI) 2 (CI) / 3 (CI) (2)

Flow Divider (Distillate) CI 3 (CI) 3 (CI)Fuel Pump (Distillate) CI 3 (CI) 3 (CI)Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 3 (HGPI) 4 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 4 (HGPI)Stage 1 Bucket HGPI (3) 2 (HGPI) / 3 (HGPI) (4) 3 (HGPI)Stage 2 Bucket HGPI 1 (HGPI) / 2 (HGPI) (5) 4 (HGPI)Stage 3 Bucket HGPI 3 (HGPI) 4 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) 4 (CI) for non-DLN / 5 (CI) for DLN(2) 2 (CI) for non-DLN / 3 (CI) for DLN(3) When recoating, perform after one hours-based Hot Gas Path Interval(4) 3 HGPI for 6581 / 2 HGPI for 6BeV; Assumes strip, HIP, heat treat and recoat at HGPI(5) 1 HGPI for 6581 / 2 HGPI for 6BeV

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 42

Figure D-4. Estimated repair and replacement cycles

PG7001(EA) / PG9001(E) PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 3 (CI) / 5 (CI) (1) 5 (CI)Caps CI 3 (CI) 5 (CI)

Transition Pieces CI 4 (CI) / 6 (CI) (2) 6 (CI)Fuel Nozzles CI 2 (CI) / 3 (CI) (3) 3 (CI)

Crossfire Tubes CI 2 (CI) / 3 (CI) (3) 3 (CI)Flow Divider (Distillate) CI 3 (CI) 3 (CI)Fuel Pump (Distillate) CI 3 (CI) 3 (CI)Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 3 (HGPI) 4 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 4 (HGPI)Stage 1 Bucket HGPI (4) 2 (HGPI) / 3 (HGPI) (5) 3 (HGPI)Stage 2 Bucket HGPI 3 (HGPI) 4 (HGPI)Stage 3 Bucket HGPI 3 (HGPI) 4 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) 3 (CI) for DLN / 5 (CI) for non-DLN(2) 4 (CI) for DLN / 6 (CI) for non-DLN(3) 2 (CI) for DLN / 3 (CI) for non-DLN(4) When recoating, perform after one hours-based Hot Gas Path Interval(5) 2 Hot Gas Path Intervals without strip, HIP, heat treat and recoat; 3 Hot Gas Path Intervals with strip, HIP, heat treat and recoat

Figure D-5. Estimated repair and replacement cycles

PG6101(FA) PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 5 (CI)(1) 5 (CI)Caps CI 5 (CI)(1) 5 (CI)Transition Pieces CI 5 (CI)(1) 5 (CI)Fuel Nozzles CI 3 (CI) 3 (CI)Crossfire Tubes CI 2 (CI)(2) 2 (CI)(2)

End Covers 6 (CI)(1) 3 (CI)Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 2 (HGPI) 2 (HGPI)(3)

Stage 2 Bucket HGPI 1 (HGPI) 3 (HGPI)(4)

Stage 3 Bucket HGPI 3 (HGPI)(4) 3 (HGPI)(4)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Decision will be made based on fleet leader experience.(2) The goal is to increase this interval.(3) GE approved repair operations may be needed to meet expected life. Consult your Energy Services representative for details.(4) With welded hardface on shroud, recoating at 1st HGPI is required to achieve replacement life.

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 43

Figure D-6. Estimated repair and replacement cycles

PG7191(F) / PG9301(F) PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 5 (CI)(1) 5 (CI)Caps CI 5 (CI)(1) 5 (CI)Transition Pieces CI 5 (CI)(1) 5 (CI)Fuel Nozzles CI 3 (CI) 3 (CI)Crossfire Tubes CI 1 (CI) / 2 (CI) (2) 1 (CI) / 2 (CI) (2)

End Covers 6 (CI)(1) 3 (CI)Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 2 (HGPI) 2 (HGPI)Stage 2 Bucket HGPI 3 (HGPI)(3) 3 (HGPI)(3)

Stage 3 Bucket HGPI 3 (HGPI)(3) 3 (HGPI)(3)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Decision will be made based on fleet leader experience.(2) 2 (CI) for 7191 / 1 (CI) for 9301. The goal is to increase this interval.(3) With welded hardface on shroud, recoating at 1st HGPI may be required to achieve replacement life.

Figure D-7. Estimated repair and replacement cycles

PG7221(FA) / PG9311(FA) PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 5 (CI)(1) 5 (CI)Caps CI 5 (CI)(1) 5 (CI)Transition Pieces CI 5 (CI)(1) 5 (CI)Fuel Nozzles CI 3 (CI) 3 (CI)Crossfire Tubes CI 1 (CI) / 2 (CI) (2) 1 (CI) / 2 (CI) (2)

End Covers 6 (CI)(1) 3 (CI)Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 2 (HGPI) 2 (HGPI)(3)

Stage 2 Bucket HGPI 2 (HGPI) / 3 (HGPI) (4) 3 (HGPI)Stage 3 Bucket HGPI 3 (HGPI)(5) 3 (HGPI)(5)

Cl = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Decision will be made based on fleet leader experience.(2) 2 (Cl) for 7211 / 1 (Cl) for 9311. The goal is to increase this interval.(3) GE approved repair operations may be needed to meet expected life. Consult your Energy

Services representative for details.(4) 2 (HGPI) for 7211 / 3 (HGPI) for 9311(5) With welded hardface on shroud, recoating at 1st HGPI may be required to achieve

replacement life.

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 44

PG7231FA PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 5 (CI)(1) 5 (CI)Caps CI 5 (CI)(1)

5 (CI)Transition Pieces CI 5 (CI)(1) 5 (CI)Fuel Nozzles CI 3 (CI) 3 (CI)Crossfire Tubes CI 2 (CI)(2) 2 (CI)(2)

End Covers 6 (CI)(1) 3 (CI)Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI)Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 2 (HGPI) 1 (HGPI)(3)

Stage 2 Bucket HGPI 1 (HGPI)(4) 3 (HGPI)(5)

Stage 3 Bucket HGPI 2 (HGPI) 3 (HGPI)

Cl = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Decision will be made based on fleet leader experience.(2) The goal is to increase this interval.(3) GE approved repair operations may be needed to meet expected life. Consult your Energy

Services representative for details.(4) Interval can be increased to 2 (HGPI) by performing a repair operation. Consult your

Energy Services representative for details.(5) Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.

Figure D-8. Estimated repair and replacement cycles

Figure D-9. Estimated repair and replacement cycles

PG7241FA Parts

Repair Interval Replace Interval (Hours) Replace Interval (Starts)Combustion Liners Cl 2 (Cl)(1)(2) 5 (Cl)(2)

Caps Cl 3 (Cl)(2) 5 (Cl)(2)

Transition Pieces Cl 3 (Cl)(2) 5 (Cl)(2)

Fuel Nozzles Cl 3 (Cl)(2) 3 (Cl)(2)

Crossfire Tubes Cl 2 (Cl)(1)(2) 2 (Cl)(1)(2)

End Covers 4 (Cl)(2) 3 (Cl)(2)

Stage 1 Nozzles HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 2 Nozzles HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 2 Shrouds HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 3 (HGPI) 2 (HGPI)Stage 2 Bucket HGPI 1 (HGPI)(4) 2 (HGPI)(5)

Stage 3 Bucket HGPI 3 (HGPI)(6) 3 (HGPI)

Cl = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) The goal is to increase this interval.(2) Decision will be made based on fleet leader experience.(3) The goal is to increase to 3 (HGPI). Decision will be made based on fleet leader

experience.(4) Interval can be increased to 2 (HGPI) by performing a repair operation. Consult

your Energy Services representative for details.(5) Interval can be increased to 3 (HGPI) by performing a repair operation.

Recoating at 1st HGPI may be required to achieve 3 (HGPI) replacement life.Consult your Energy Services representative for details.

(6) GE approved repair procedure at 2nd HGPI is required to meet 3 (HGPI)replacement life.

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Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 45

Figure D-11. Estimated repair and replacement cycles

PG7251FB PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 3 (CI)(1) 3 (CI)(1)

Caps CI 3 (CI)(1) 3 (CI)(1)

Transition Pieces CI 3 (CI)(1) 3 (CI)(1)

Fuel Nozzles CI 3 (CI)(1) 3 (CI)(1)

Crossfire Tubes CI 3 (CI)(1) 3 (CI)(1)

End Covers 3 (CI)(1) 3 (CI)(1)

Stage 1 Nozzles HGPI 2 (HGPI)(2) 2 (HGPI)(2)

Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI)Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)Stage 2 Shrouds HGPI 2 (HGPI)(2) 2 (HGPI)(2)

Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 3 (HGPI)(2) 3 (HGPI)(2)

Stage 2 Bucket HGPI 3 (HGPI) 3 (HGPI)Stage 3 Bucket HGPI 3 (HGPI) 3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) The goal is to increase to 4 (CI).(2) Decision will be made based on fleet leader experience.

PG9351FA Parts

Repair Interval Replace Interval (Hours) Replace Interval (Starts)Combustion Liners Cl 5 (Cl)(1) 5 (Cl)Caps Cl 5 (Cl)(1) 5 (Cl)Transition Pieces Cl 5 (Cl)(1) 5 (Cl)Fuel Nozzles Cl 3 (Cl) 3 (Cl)Crossfire Tubes Cl 1 (Cl)(2) 1 (Cl)(2)

End Covers 6 (Cl)(1) 3 (Cl)Stage 1 Nozzles HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 2 Nozzles HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)Stage 1 Shrouds HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 2 Shrouds HGPI 2 (HGPI)(3) 2 (HGPI)(3)

Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)Exhaust Diffuser HGPIStage 1 Bucket HGPI 2 (HGPI)(3) 2 (HGPI)Stage 2 Bucket HGPI 1 (HGPI) 2 (HGPI)(4)

Stage 3 Bucket HGPI 2 (HGPI)(5) 3 (HGPI)

Cl = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Decision will be made based on fleet leader experience.(2) The goal is to increase this interval to 2 (Cl).(3) The goal is to increase to 3 (HGPI). Decision will be made based on fleet leader experi-

ence.(4) Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.(5) GE approved repair procedure at 1 (HGPI) is required to meet 2 (HGPI) replacement

life.

Figure D-10. Estimated repair and replacement cycles

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List of FiguresFigure 1. Key factors affecting maintenance planning

Figure 2. Plant level – top five systems contribution to downtime

Figure 3. MS7001E gas turbine borescope inspection access locations

Figure 4. Borescope inspection programming

Figure 5. Maintenance cost and equipment life are influenced by key service factors

Figure 6. Causes of wear – hot-gas-path components

Figure 7. GE bases gas turbine maintenance requirements on independent countsof starts and hours

Figure 8. Hot-gas-path maintenance interval comparisons. GE method vs. EOH method

Figure 9. Maintenance factors – hot gas path (buckets and nozzles)

Figure 10. GE maintenance interval for hot-gas inspections

Figure 11. Estimated effect of fuel type on maintenance

Figure 12. Bucket life firing temperature effect

Figure 13. Firing temperature and load relationship – heat recovery vs. simple cycle operation

Figure 14. Heavy fuel maintenance factors

Figure 15. Steam/water injection and bucket/nozzle life

Figure 16. Exhaust temperature control curve – dry vs. wet control MS7001EA

Figure 17. Turbine start/stop cycle – firing temperature changes

Figure 18. First stage bucket transient temperature distribution

Figure 19. Bucket low cycle fatigue (LCF)

Figure 20. Low cycle fatigue life sensitivities – first stage bucket

Figure 21. Maintenance factor – trips from load

Figure 22. Maintenance factor – effect of start cycle maximum load level

Figure 23. Operation-related maintenance factors

Figure 24. FA gas turbine typical operational profile

Figure 25. Baseline for starts-based maintenance factor definition

Figure 26. The NGC requirement for output versus frequency capability over all ambients lessthan 25°C (77°F)

Figure 27. Turbine output at under-frequency conditions

Figure 28. NGC code compliance TF required – FA class

Figure 29. Maintenance factor for overspeed operation ~constant TF

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 46

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Figure 30. Deterioration of gas turbine performance due to compressor blade fouling

Figure 31. Long term material property degradation in a wet environment

Figure 32. Susceptibility of compressor blade materials and coatings

Figure 33. MS7001EA heavy-duty gas turbine – shutdown inspections

Figure 34. Operating inspection data parameters

Figure 35. Combustion inspection – key elements

Figure 36. Hot-gas-path inspection – key elements

Figure 37. Stator tube jacking procedure – MS7001EA

Figure 38. Stage 1 bucket oxidation and bucket life

Figure 39. Gas turbine major inspection – key elements

Figure 40. Major inspection work scope

Figure 41. First-stage nozzle wear-preventive maintenance gas fired – continuous dry – base load

Figure 42. Base line recommended inspection intervals: base load—gas fuel—dry

Figure 43. Hot gas path inspection: hours-based criterion,

Figure 44. Hot gas path inspection starts-based condition

Figure 45. Rotor maintenance factor for starts-based criterion

Figure 46. Rotor maintenance factor for hours-based criterion

Figure 47. Combustion inspection hours-based maintenance factors

Figure 48. Combustion inspection starts-based maintenance factors

Figure B-1. Combustion maintenance interval calculations

Figure D-1. Estimated repair and replacement cycles

Figure D-2. Estimated repair and replacement cycles

Figure D-3. Estimated repair and replacement cycles

Figure D-4. Estimated repair and replacement cycles

Figure D-5. Estimated repair and replacement cycles

Figure D-6. Estimated repair and replacement cycles

Figure D-7. Estimated repair and replacement cycles

Figure D-8. Estimated repair and replacement cycles

Figure D-9. Estimated repair and replacement cycles

Figure D-10. Estimated repair and replacement cycles

Figure D-11. Estimated repair and replacement cycles

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 47

Page 52: Heavy Duty Maintanaice Gas Turbine Frame 9

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

GE Power Systems ■ GER-3620J ■ (01/03) 48