ger-3620f

GER-3620F

HEAVY-DUTY GAS TURBINE OPERATINGAND MAINTENANCE CONSIDERATIONS

Robert Hoeft & Eric GebhardtGE Energy Services

Atlanta, GA

INTRODUCTIONMaintenance costs and availability are two of the

most important concerns to the equipment owner. Amaintenance program that optimizes the owner's costsand maximizes equipment availability must be insti-tuted. For a maintenance program to be effective, theowner must develop a general understanding of therelationship between his operating plans and priori-ties for the plant, the skill level of operating andmaintenance personnel, and the manufacturer's rec-ommendations regarding the number and types ofinspections, spare parts planning, and the major fac-tors affecting component life and proper operation ofthe equipment.

In this paper, operating and maintenance practiceswill be reviewed, with emphasis placed on types ofinspections plus operating factors that influencemaintenance schedules. A well-planned maintenanceprogram will result in maximum equipment avail-ability and optimal maintenance costs.

Note: The operating and maintenance discussionspresented in this paper are generally applicable to all

GE heavy-duty gas turbines; i.e., MS3000, 5000,6000, 7000 and 9000. For purposes of illustration,the MS7001EA was chosen. Specific questions on agiven machine should be directed to the local GE En-ergy Services representative.

MAINTENANCE PLANNINGAdvance planning for maintenance is a necessity

for utility, industrial and cogeneration plants in orderto minimize downtime. Also the correct performanceof planned maintenance and inspection provides di-rect benefits in reduced forced outages and increasedstarting reliability, which in turn reduces unscheduledrepair downtime. The primary factors which affectthe maintenance planning process are shown in Fig-ure 1 and the owners' operating mode will determinehow each factor is weighted.

Parts unique to the gas turbine requiring the mostcareful attention are those associated with the com-bustion process together with those exposed to hightemperatures from the hot gases discharged from thecombustion system. They are called the hot-gas-path

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Manufacturer’sRecommendedMaintenance

Program

Diagnostics &Expert Systems

ReliabilityNeed

On-SiteMaintenance

Capability

DesignFeatures

UtilizationNeed

DutyCycle

Environment

Cost ofDowntime

ReserveRequirements

ReplacementParts

Availability/Investment

Type ofFuel

MaintenancePlanning

Figure 1. Key factors affecting maintenance planning

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parts and include combustion liners, end caps, fuelnozzle assemblies, cross-fire tubes, transition pieces,turbine nozzles, turbine stationary shrouds and tur-bine buckets.

The basic design and recommended maintenanceof GE heavy-duty gas turbines are oriented toward:

• Maximum periods of operation between inspec-tion and overhauls

• In-place, on-site inspection and maintenance• Use of local trade skills to disassemble, inspect

and re-assembleIn addition to maintenance of the basic gas turbine,

the control devices, fuel metering equipment, gas tur-bine auxiliaries, load package, and other station aux-iliaries also require periodic servicing.

It is apparent from the analysis of scheduled out-ages and forced outages (Figure 2) that the primarymaintenance effort is attributed to five basic systems:controls and accessories, combustion, turbine, gen-erator and balance-of-plant. The unavailability ofcontrols and accessories is generally composed ofshort-duration outages, whereas conversely the otherfour systems are composed of fewer, but usuallylonger-duration outages.

The inspection and repair requirements, outlined inthe Maintenance and Instructions Manual providedto each owner, lend themselves to establishing a pat-tern of inspections. In addition, supplementary infor-mation is provided through a system of TechnicalInformation Letters. This updating of information,contained in the Maintenance and Instructions Man-ual, assures optimum installation, operation andmaintenance of the turbine. Many of the TechnicalInformation Letters contain advisory technical rec-ommendations to resolve issues and improve the op-eration, maintenance, safety, reliability or availabilityof the turbine. The recommendations contained inTechnical Information Letters should be reviewedand factored into the overall maintenance planningprogram.

For a maintenance program to be effective, fromboth a cost and turbine availability standpoint, theowner must develop a general understanding of therelationship between his operating plans and priori-ties for the plant and the manufacturer's recommen-dations regarding the number and types of inspec-tions, spare parts planning, and other major factorsaffecting the life and proper operation of his equip-

GT26078.ppt

Total S.C. PlantGas Turbine

– Turbine Section

– Combustion Section – Compressor Section

– BearingsControls & AccessoriesGeneratorBalance of S.C. Plant

1 2 3 4 5 6 7% Unavailability

FOF = Forced OutageSOF = Schedule Outage

Figure 2. Plant level-top 5 systems contribution to downtime

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ment. Each of these issues will be discussed as fol-lows in further detail.

GAS TURBINE DESIGNMAINTENANCE FEATURESThe GE heavy-duty gas turbine is designed to

withstand severe duty and to be maintained on-site,with off-site repair required only on certain hot-gas-path parts and rotor assemblies needing specializedshop service. The following features are designed intoGE heavy-duty gas turbines to facilitate on-sitemaintenance:

• All casings, shells and frames are split on ma-chine horizontal centerline. Upper halves maybe lifted individually for access to internalparts.

• With upper-half compressor casings removed,all stator vanes can be slid circumferentially outof the casings for inspection or replacementwithout rotor removal. On most designs, thevariable inlet guide vanes (VIGVs) can be re-moved radially with upper half of inlet casingremoved.

• With the upper-half of the turbine shell lifted,each half of the first-stage nozzle assembly canbe removed for inspection, repair or replace-ment without rotor removal. On some units, up-per-half, later-stage nozzle assemblies are liftedwith the turbine shell, also allowing inspectionand/or removal of the turbine buckets.

• All turbine buckets are moment-weighed andcomputer charted in sets for rotor spool assem-bly so that they may be replaced without theneed to remove or rebalance the rotor assembly.

•· All bearing housings and liners are split on thehorizontal centerline so that they may be in-spected and replaced, when necessary. Thelower half of the bearing liner can be removedwithout removing the rotor.

• All seals and shaft packings are separate fromthe main bearing housings and casing structuresand may be readily removed and replaced.

• Fuel nozzles, combustion liners and flowsleeves can be removed for inspection, mainte-nance or replacement without lifting any cas-ings.

• All major accessories, including filters andcoolers, are separate assemblies that are readilyaccessible for inspection or maintenance. Theymay also be individually replaced as necessary.

Inspection aid provisions have been built into GEheavy-duty gas turbines to facilitate conducting sev-eral special inspection procedures. These special pro-cedures provide for the visual inspection and clear-ance measurement of some of the critical internal tur-bine gas-path components without removal of the gasturbine outer casings and shells. These proceduresinclude gas-path borescope inspection and turbinenozzle axial clearance measurement.

Borescope InspectionsGE heavy-duty gas turbines incorporate provisions

in both compressor casings and turbine shells for gas-path visual inspection of intermediate compressorrotor stages, first-, second- and third-stage turbinebuckets and turbine nozzle partitions by means of theoptical borescope. These provisions, consisting ofradially aligned holes through the compressor cas-ings, turbine shell and internal stationary turbineshrouds, are designed to allow the penetration of anoptical borescope into the compressor or turbineflow-path area, as shown in Figure 3.

An effective borescope inspection program can

result in removing casings and shells from a tur-

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Figure 3. MS7001E gas turbine borescopeinspection access location

At Combustion Inspectionor Annually, WhicheverOccurs First

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At Combustion Inspectionor Semiannually,Whichever Occurs First

Gas and DistillateFuel Oil

Heavy Fuel Oil

Borescope

Figure 4. Borescope inspection programming

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bine unit only when it is necessary to repair or re-place parts. Figure 4 provides a recommended inter-val for a planned borescope inspection program fol-lowing initial base line inspections. It should be rec-ognized that these borescope inspection intervals arebased on average unit operating modes. Adjustmentof these borescope intervals may be made based onoperating experience and the individual unit mode ofoperation, the fuels used and the results of previousborescope inspections.

The application of a monitoring program utilizinga borescope will allow scheduling outages and pre-planning of parts requirements, resulting in lowermaintenance costs and higher availability and reli-ability of the gas turbine.

MAJOR FACTORSINFLUENCING MAINTENANCE

AND EQUIPMENT LIFEThere are many factors that can influence equip-

ment life and these must be understood and accountedfor in the owner's maintenance planning. As indicatedin Figure 5, starting cycle, power setting, fuel andlevel of steam or water injection are key factors indetermining the maintenance interval requirements asthese factors directly influence the life of critical gasturbine parts.

In the GE approach to maintenance planning, agas fuel unit operating continuous duty, with no wa-ter or steam injection, is established as the baselinecondition which sets the maximum recommendedmaintenance intervals. For operation that differs fromthe baseline, maintenance factors are established thatdetermine the increased level of maintenance that isrequired. For example, a maintenance factor of twowould indicate a maintenance interval that is half ofthe baseline interval.

Starts and Hours CriteriaGas turbines wear in different ways for different

service-duties, as shown in Figure 6. Thermal me-chanical fatigue is the dominant limiter of life forpeaking machines, while creep, oxidation, and corro-sion are the dominant limiters of life for continuousduty machines. Interactions of these mechanisms areconsidered in the GEdesign criteria, but to a greatextent are second order effects. For that reason, GEbases gas turbine maintenance requirements on inde-pendent counts of starts and hours. Whichever crite-ria limit is first reached determines the maintenanceinterval. A graphical display of the GEapproach isshown in Figure 7. In this figure, the inspection inter-

GT23699E.ppt

• Cyclic Effects

• Firing Temperature

• Fuel

• Steam/Water Injection

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

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Figure 7. GE bases gas turhine maintenance require-ments on independent counts of starts and hours

• Continuous Duty Application- Rupture- Creep Deflection- High-Cycle Fatigue- Corrosion- Oxidation- Erosion- Rubs/Wear- Foreign Object Damage

• Cyclic Duty Application- Thermal Mechanical Fatigue- High-Cycle Fatigue- Rubs/Wear- Foreign Object Damage

GT20313B

Figure 6. Causes of wear - hot gas path components

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val recommendation is defined by the rectangle es-tablished by the starts and hours criteria. These rec-ommendations for inspection fall within the designlife expectations and are selected such that compo-nents verified to be acceptable for continued use atthe inspection point will have low risk of failure dur-ing the subsequent operating interval.

An alternative to the GE approach, which issometimes employed by other manufacturers, con-verts each start cycle to an equivalent number of op-erating hours (EOH) with inspection intervals basedon the equivalent hours count. For the reasons statedabove, GE does not agree with this approach. Thislogic can create the impression of longer intervals,while in reality more frequent maintenance inspec-tions are required. Referring again to Figure 7, thestarts and hours inspection "rectangle" is reduced inhalf as defined by the diagonal line from the startslimit at the upper left hand corner to the hours limit atthe lower right hand corner. Midrange duty applica-

tions, with hours per start ratios of 30-50, are par-ticularly penalized by this approach.

This is further illustrated in Figure 8 for the ex-ample of an MS7001EA gas turbine operating on gasfuel, at base load conditions with no steam or waterinjection or trips from load. The unit operates 4000hours and 300 starts per year. Following GE's rec-ommendations, the operator would perform the hotgas path inspection after four years of operation, withstarts being the limiting condition. Performing main-tenance on this same unit based on an equivalenthours criteria would require a hot gas path inspectionafter 2.4 years. Similarly, for a continuous duty ap-plication operating 8000 hours and 160 starts peryear, the GE recommendation would be to performthe hot gas path inspection after three years of opera-tion with the operating hours being the limiting con-dition for this case. The equivalent hours criteriawould set the hot gas path inspection after 2.1 yearsof operation for this application.

Service FactorsWhile GE does not ascribe to the equivalency of

GT24399A

Figure 10. GE maintenance interval for hotgas inspections

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Figure 8. Hot gas path maintenance intervalcomparisons. GE method vs. EOH method

Typical Max Inspection Intervals (MS6B/MS7EA)Hot Gas Path Inspection 24,000 hrs or 1200 startsMajor Inspection 48,000 hrs or 2400 startsCriterion 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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Figure 9. Maintenance factors - hot gas path(buckets and nozzles)

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Figure 11. Estimated effect of fuel type on maintenance

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starts to hours, there are equivalencies within a wearmechanism that must be considered. As shown inFigure 9, influences such as fuel type and quality,firing temperature setting, and the amount of steamor water injection are considered with regard to thehours-based criteria. Start-up rate and the number oftrips are considered with regard to the starts-basedcriteria. In both cases, these influences may act toreduce the maintenance intervals. When these serviceor maintenance factors are involved in a unit's oper-ating profile, the hot gas path maintenance"rectangle" that describes the specific maintenancecriteria for this operation is reduced from the idealcase, as illustrated in Figure 10. The following dis-cussion will take a closer look at the key operatingfactors and how they can impact maintenance inter-vals as well as parts refurbishment/replacement in-tervals.

FuelFuels burned in gas turbines range from clean

natural gas to residual oils and impact maintenance,as illustrated in Figure 11. Heavier hydrocarbon fuelshave a maintenance factor ranging from three to fourfor residual fuel and two to three for crude oil fuels.These fuels generally release a higher amount of ra-diant thermal energy, which results in a subsequentreduction in combustion hardware life, and frequentlycontain corrosive elements such as sodium, potas-sium, vanadium and lead that can lead to acceleratedhot corrosion of turbine nozzles and buckets. In addi-tion, some elements in these fuels can cause depositseither directly or through compounds formed withinhibitors that are used to prevent corrosion. Thesedeposits impact performance and can lead to a needfor more frequent maintenance.

Distillates, as refined, do not generally containhigh levels of these corrosive elements, but harmfulcontaminants can be present in these fuels when de-livered to the site. Two common ways of contami-nating number two distillate fuel oil are: salt waterballast mixing with the cargo during sea transport,and contamination of the distillate fuel when trans-ported to site in tankers, tank trucks or pipelines thatwere previously used to transport contaminated fuel,chemicals or leaded gasoline. From Figure 11, it canbe seen that General Electric's experience with distil-late fuels indicates that the hot gas path maintenancefactor can range from as low as one (equivalent tonatural gas) to as high as three. Unless operating ex-perience suggests otherwise, it is recommended that a

hot gas path maintenance factor of 1.5 be used foroperation on distillate oil. Note also that contami-nants in liquid fuels can affect the life of gas turbineauxiliary components such as fuel pumps and flowdividers.

As shown in Figure 11, gas fuels, which meet GEspecifications, are considered the optimum fuel withregard to turbine maintenance and are assigned nonegative impact. The importance of proper fuel qual-ity has been amplified with Dry Low NOx (DLN)combustion systems. Proper adherence to GE fuelspecifications in GEI-41040 is required to allowproper combustion system operation, and to maintainapplicable warranties. Liquid hydrocarbon carryovercan expose the hot-gas-path hardware to severeovertemperature conditions and can result in signifi-cant reductions in hot-gas-path parts lives or repairintervals. Owners can control this potential problemby using effective gas scrubber systems and by su-perheating the gaseous fuel prior to use to provide anominal 50 F (28 C) of superheat at the turbine gascontrol valve connection.

The prevention of hot corrosion of the turbinebuckets and nozzles is mainly under the control of theowner. Undetected and untreated, a single shipmentof contaminated fuel can cause substantial damage tothe gas turbine hot gas path components. Potentiallyhigh maintenance costs and loss of availability can beminimized or eliminated by:

• Placing a proper fuel specification on the fuelsupplier. For liquid fuels, each shipment shouldinclude a report that identifies specific gravity,flash point, viscosity, sulfur content, pour pointand ash content of the fuel.

• Providing a regular fuel quality sampling andanalysis program. As part of this program, an

GT23685C

Figure 12. Bucket life firing temperature effectMS6001B/MS7001EA/MS9001E

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online water in fuel oil monitor is recommended,as is a portable fuel analyzer that, as a mini-mum, reads vanadium, lead, sodium, potassium,calcium and magnesium.

• Providing proper maintenance of the fuel treat-ment system when burning heavier fuel oils andby providing cleanup equipment for distillate fu-els when there is a potential for contamination.

In addition to their presence in the fuel, contami-nants can also enter the turbine via the inlet air andfrom the steam or water injected for NOx emissioncontrol or power augmentation. Carryover fromevaporative coolers is another source of contami-nants. In some cases, these sources of contaminantshave been found to cause hot-gas-path degradationequal to that seen with fuel-related contaminants. GEspecifications define limits for maximum concentra-tions of contaminants for fuel, air and steam/water.

Firing TemperatureSignificant operation at peak load, because of the

higher operating temperatures, will require more fre-quent maintenance and replacement of hot-gas-path

components. For an MS7001EA turbine, each hourof operation at peak load firing temperature (+100F/56C)is the same, from a bucket parts life stand-point, as six hours of operation at base load. Thistype of operation will result in a maintenance factorof six. Figure 12 defines the parts life effect corre-sponding to changes in firing temperature for theMS6001B/MS7001EA/ MS9001E. It should benoted that this is not a linear relationship, as a +200F/111C increase in firing temperature would have anequivalency of six times six, or 36:1.

Higher firing temperature reduces hot-gas-pathparts lives while lower firing temperature increasesparts lives. This provides an opportunity to balancethe negative effects of peak load operation by periodsof operation at part load. However, it is important torecognize that the nonlinear behavior described abovewill not result in a one for one balance for equalmagnitudes of over and under firing operation.Rather, it would take six hours of operation at -100F/56 C under base conditions to compensate for onehour operation at +100 F/56 C over base load condi-tions.

Parts Life Benefit at Reduced Load isLess in the Heat Recovery Mode

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

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It is also important to recognize that a reduction inload does not always mean a reduction in firing tem-perature. In heat recovery applications, where steamgeneration drives overall plant efficiency, load is firstreduced by reducing fuel and then closing variableinlet guide vanes to reduce inlet airflow while main-taining maximum exhaust temperature. For thesecombined cycle applications, firing temperature doesnot decrease until load is reduced below approxi-mately 80% of rated output. Conversely, a turbinerunning in simple-cycle mode maintains full openinlet guide vanes during a load reduction to 80% andwill experience over a 200 F/111 C reduction in fir-ing temperature at this output level. The hot-gas-pathparts life effects for these different modes of opera-

tion are obviously quite different. This turbine controleffect is illustrated in Figure 13.

Firing temperature effects on hot gas path mainte-nance, as described above, relate to clean burningfuels, such as natural gas and light distillates, wherecreep rupture of hot gas path components is the pri-mary life limiter and is the mechanism that deter-mines the hot gas path maintenance interval impact.With ash-bearing heavy fuels, corrosion and depositsare the primary influence and a different relationshipwith firing temperature exists. Figure 14 illustratesthe sensitivity of hot gas path maintenance factor tofiring temperature for a heavy fuel operation. It canbe seen that while the sensitivity to firing temperatureis less, the maintenance factor itself is higher due toissues relating to the corrosive elements contained inthese fuels.

Steam/Water InjectionWater (or steam) injection for emissions control or

power augmentation can impact parts lives andmaintenance intervals even when the water or steammeets GEspecifications. This relates to the effect ofthe added water on the hot-gas transport properties.Higher gas conductivity, in particular, increases theheat transfer to the buckets and nozzles and can leadto higher metal temperature and reduced parts livesas shown in Figure 15 .

Parts life impact from steam or water injection isrelated to the way the turbine is controlled. The con-trol system on most base load applications reducesfiring temperature as water or steam is injected. Thiscounters the effect of the higher heat transfer on thegas side and results in no impact on bucket life. Onsome installations, however, the control system isdesigned to maintain firing temperature constant withwater injection level. This results in additional unitoutput but it decreases parts life as previously de-scribed. Units controlled in this way are generally in

GT24393 .ppt

Resid.

Crude

100

10

54

3

2

1-200 -150 -100 -50 500 F

0 C50100

Delta Firing Temperature

Mai

nten

ance

Fac

tor

Maximum HeavyFuel Firing

Temperature

MS6001B / 7001EA /9001E

Figure 14. Heavy fuel maintenance factors

• Water Affects Gas Transport Properties:kCP

µ

• This Increases Heat Transfer Coefficients:

• Which Increases Metal Temperature andDecreases Bucket Life

For Constant Firing Temperature

GT23687C .ppt

Steam/Water Injection Increases MetalTemperature of Hot-Gas-Path Components

- Thermal Conductivity- Specific Heat- Viscosity

Example (MS7001EA Stage 1 Bucket):3% Steam (25 ppm NOx)

HTMetal

Life

= +4% (Heat Transfer Coefficient)= +15 F (8 C)= – 33%

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

GT23688A .ppt

ExhaustTemperature

°F

Compressor Discharge Pressure (psig)

The Wet Control CurveMaintains Constant TF

Dry Control

Wet Control3% Steam Inj.

TF = 2020°F (1104°C)Load Ratio = 1.10

3% Steam Inj.TF = 1994°F (1090°C)

Load Ratio = 1.08

0% Steam Inj.TF = 2020°F (1104°C)

Load Ratio = 1.0

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

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peaking applications where annual operating hoursare low or where operators have determined that re-duced parts lives are justified by the power advan-tage. GEdescribes these two modes of operation asdry control curve operation and wet control curveoperation, respectively. Figure 16 illustrates the wetand dry control curve and the performance differ-ences that result from these two different modes ofcontrol.

An additional factor associated with water orsteam injection relates to the higher aerodynamicloading on the turbine components that results fromthe injected water increasing the cycle pressure ratio.This additional loading can increase the downstreamdeflection rate of the second- and third-stage nozzles,which would reduce the repair interval for these com-ponents. However, the introduction of GTD-222, anew high creep strength stage two and three nozzlealloy, has minimized this factor.

Maintenance factors relating to water injection forunits operating on dry control, range from one, forunits equipped with GTD-222 second-stage andthird-stage nozzles, to a factor of 1.5 for unitsequipped with FSX 414 nozzles and injecting 5%water. For wet control curve operation, the mainte-nance factor is approximately two at 5% water injec-tion for GTD-222 and four for FSX 414.

Cyclic EffectsIn the previous discussion, operating factors that

impact the hours-based maintenance criteria weredescribed. For the starts-based maintenance criteria,operating factors associated with the cyclic effectsproduced during startup, operation and shutdown ofthe turbine must be considered. Operating conditionsother than the standard startup and shutdown se-quence can potentially reduce the cyclic life of the hotgas path components and rotors, and, if present, willrequire more frequent maintenance and parts refur-bishment and/or replacement.

GT24394 .ppt

Base Load

Unload Ramp

Trip

Warm-up

Full SpeedNo Load

Load Ramp

Full SpeedNo Load

Fired Shutdown

Acceleration

Light-off

Startup ShutdownTime

Tem

pera

ture

Figure 17. Turbine start/stop cycle - firingtemperature changes

G T 0 6 2 6 7 A . p p t

H o t

C o ld

Figure 18. First-stage bucket transient temperature distribution

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Hot Gas Path PartsFigure 17 illustrates the firing temperature

changes occurring over a normal startup and shut-down cycle. Light-off, acceleration, loading, unload-ing and shutdown all produce gas temperaturechanges that produce corresponding metal tempera-ture changes. For rapid changes in gas temperature,the edges of the bucket or nozzle respond morequickly than the thicker bulk section, as pictured inFigure 18.These gradients, in turn, produce thermalstresses that, when cycled, can eventually lead to

cracking. Figure 19 describes the temperature strainhistory of an MS7001EA stage 1 bucket during anormal startup and shutdown cycle. Light-off andacceleration produce transient compressive strains inthe bucket as the fast responding leading edge heatsup more quickly than the thicker bulk section of theairfoil. At full load conditions, the bucket reaches itsmaximum metal temperature and a compressivestrain produced from the normal steady state tem-perature gradients that exist in the cooled part. Atshutdown, the conditions reverse where the fasterresponding edges cool more quickly than the bulksection, which results in a tensile strain at the leadingedge.

Thermal mechanical fatigue testing has found thatthe number of cycles that a part can withstand beforecracking occurs is strongly influenced by the totalstrain range and the maximum metal temperatureexperienced. Any operating condition that signifi-cantly increases the strain range and/or the maximummetal temperature over the normal cycle conditionswill act to reduce the fatigue life and increase thestarts-based maintenance factor. For example, Figure20 compares a normal operating cycle with one thatincludes a trip from full load. The significant increase

1 Trip Cycle = 8 Normal Shutdown Cycles

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

Key Parameters

• Max Strain Range

• Max Metal Temperature

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Figure 19. Bucket low cycle fatigue (LCF)

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in the strain range for a trip cycle results in a life ef-fect that equates to eight normal start/stop cycles, asshown. Trips from part load will have a reduced im-pact because of the lower metal temperatures at theinitiation of the trip event. Figure 21 illustrates thatwhile a trip from loads greater than 80% has an 8:1maintenance factor, a trip from full speed no loadwould have a maintenance factor of 2:1.

Similarly to trips from load, emergency starts andfast loading will impact the starts-based maintenanceinterval. This again relates to the increased strainrange that is associated with these events. Emergencystarts where units are brought from standstill to fullload in less than five minutes will have a parts lifeeffect equal to 20 normal start cycles and a normalstart with fast loading will produce a maintenancefactor of two.

While the factors described above will decrease thestarts-based maintenance interval, part load operatingcycles would allow for an extension of the mainte-nance interval. Figure 22 is a guideline that could beused in considering this type of operation. For exam-ple, two operating cycles to maximum load levels of

less than 60% would equate to one start to a loadgreater than 60% or, stated another way, would havea maintenance factor of .5.

Rotor PartsIn addition to the hot gas path components, the

rotor structure maintenance and refurbishment re-quirements are impacted by the cyclic effects associ-ated with start-up, operation and shutdown. Mainte-nance factors specific to an application's operatingprofile and rotor design must be determined and in-corporated into the operators maintenance planning.Disassembly and inspection of all rotor componentsis required when the accumulated rotor starts reachthe inspection limit. (See Figures 44 and 45 in In-spection Internal Section)

For the rotor, the thermal condition when the start-up sequence is initiated is a major factor in deter-mining the rotor maintenance interval and individualrotor component life. Rotors that are cold when thestartup commences develop transient thermal stressesas the turbine is brought on line. Large rotors withtheir longer thermal time constants develop higher

GT24396 .ppt

Base

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

FSNL

10

8

6

4

2

00 20 40 60 80 100 120

% Load

a T -

Trip

Sev

erity

Fac

tor

Figure 21. Maintenance factor - trips from load

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thermal stresses than smaller rotors undergoing thesame startup time sequence. High thermal stresseswill reduce maintenance intervals and thermal me-chanical fatigue life.

The steam turbine industry recognized the need toadjust start-up times in the 1950 to 1970 time periodwhen power generation market growth led to largerand larger steam turbines operating at higher tem-peratures. Similar to the steam turbine rotor size in-creases of the 1950s and 1960s, gas turbine rotorshave seen a growth trend in the 1980s and 1990s asthe technology has advanced to meet the demand forcombined cycle power plants with high power densityand thermal efficiency.

With these larger rotors, lessons learned fromboth the steam turbine experience and the more recentgas turbine experience should be factored into thestart-up control for the gas turbine and/or mainte-nance factors should be determined for an applica-tion's duty cycle to quantify the rotor life reductionsassociated with different severity levels. The mainte-nance factors so determined are used to adjust therotor component inspection, repair and replacement

intervals that are appropriate to that particular dutycycle.

Though the concept of rotor maintenance factorsis applicable to all gas turbine rotors, onlyMS7001/9001F and FA rotors will be discussed indetail. The rotor maintenance factor for a start-up isa function of the downtime following a previous pe-riod of operation. As downtime increases, the rotormetal temperature approaches ambient conditions andthermal fatigue impact during a subsequent start-upincreases. Since the most limiting location determinesthe overall rotor impact, the rotor maintenance factoris determined from the upper bound locus of the rotormaintenance factors at these various features. Forexample, cold starts are assigned a rotor maintenancefactor of two and hot starts a rotor maintenance fac-tor of less than one due to the lower thermal stressunder hot conditions.

Cold starts are not the only operating factor thatinfluences is rotor maintenance intervals and compo-nent life. Fast starts and fast loading, where the tur-bine is ramped quickly to load, increase thermal gra-dients and are more severe duty for the rotor. Tripsfrom load and particularly trips followed by immedi-

GT24397 .ppt

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.00 20 40 60 80 100

% Load

Mai

nt. F

acto

r

Figure 22. Maintenance factors - effect of start cycle maximum load level

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ate restarts reduce the rotor maintenance interval asdo hot restarts within the first hour of a hot shut-down. Figure 23 lists recommended operating factorsthat should be used to determine the rotor's overallmaintenance factor for PG7241 and PG9351 designrotors. The factors to be used for other models aredetermined by applicable Technical Information Let-ters.

The significance of each of these factors to themaintenance requirements of the rotor is dependenton the type of operation that the unit sees. There arethree general categories of operation that are typicalof most gas turbine applications. These are peaking,cyclic and continuous duty as described below:

• Peaking units have a relatively high starting fre-quency and a low number of hours per start.Operation follows a seasonal demand. Peakingunits will generally see a high percentage of coldstarts.

• Cyclic duty units start daily with only weekendshutdowns. Twelve to sixteen hours per start istypical which results in a warm rotor conditionfor a large percentage of the starts. Cold starts

are generally seen only following a startup aftera maintenance outage or following a two dayweekend outage.

• Continuous duty applications see a high numberof hours per start and most starts are cold be-cause outages are generally maintenance driven.While the percentage of cold starts is high, thetotal number of starts is low. The rotor mainte-nance interval on continuous duty units will bedetermined by service hours rather than starts.

Figure 24 lists operating profiles on the high endof each of these three general categories of gas tur-bine applications.

As can be seen in Figure 24, these duty cycleshave different combinations of hot, warm and coldstarts with each starting condition having a differentimpact on rotor maintenance interval as previouslydiscussed. As a result, the starts based rotor mainte-nance interval will depend on an applications specificduty cycle. In a later section, a method will be de-scribed that allows the turbine operator to determinea maintenance factor that is specific to his operation'sduty cycle. This maintenance factor uses the rotor

GT26007A.ppt

PG7241/PG9351* DesignRotor Maintenance Factors

Fast Load Normal Load

Hot Start Factor**(1-4 Hrs. Down)

Warm 1 Start Factor(4-20 Hrs. Down)

Warm 2 Start Factor(20-40 Hrs. Down)

Cold Start Factor(>40 Hrs. Down)

Trip From Load Factor

Hot Start Factor (0-1 Hr Down)

• Factors Are a Function of Machine Thermal Condition at Start-Up• Trips From Load and Fast Starts Reduce Maintenance Intervals

1.0

1.8

2.8

4.0

4.0

4.0

0.5

0.9

1.4

2.0

4.0

2.0

*Other Factors May Apply to Early 9351 Units**For restarts less than 1 hour after a trip from load, use cold factors

Figure 23. Operation related maintenance factors

GER-3620F

14

maintenance factors described above in combinationwith the actual duty cycle of a specific applicationand can be used to determine rotor inspection inter-vals. In this calculation, the reference duty cycle thatyields a starts based maintenance factor equal to oneis defined in Figure 25. Duty cycles different from theFigure 25 definition, in particular duty cycles withmore cold starts, or a high number of trips, will havea maintenance factor greater than one.

Air QualityMaintenance and operating costs are also influ-

enced by the quality of the air that the turbine con-sumes. In addition to the deleterious effects of air-borne contaminants on hot-gas-path components,contaminants such as dust, salt and oil can also causecompressor blade erosion, corrosion and fouling.Twenty-micron particles entering the compressor cancause significant blade erosion. Fouling can becaused by submicron dirt particles entering the com-pressor as well as from ingestion of oil vapor, smoke,sea salt and industrial vapors. Corrosion of compres-sor blading causes pitting of the blade surface, which,in addition to increasing the surface roughness, also

serves as potential sites for fatigue crack initiation.These surface roughness and blade contour changeswill decrease compressor airflow and efficiency,which in turn reduces the gas turbine output andoverall thermal efficiency.

Generally, axial-flow compressor deterioration isthe major cause of loss in gas turbine output and effi-ciency. Recoverable losses, attributable to compres-sor blade fouling, typically account for 70 to 85 ofthe performance losses seen. As Figure 26 illustrates,compressor fouling to the extent that airflow is re-duced by 5%, will reduce output by 13% and in-crease heat rate by 5.5% Fortunately, much can bedone through proper operation and maintenance pro-cedures to minimize fouling-type losses. On-linecompressor wash systems are available that are usedto maintain compressor efficiency by washing thecompressor while at load, before significant foulinghas occurred. Off-line systems are used to cleanheavily-fouled compressors. Other procedures includemaintaining the inlet filtration system and inletevaporative coolers as well as periodic inspection andprompt repair of compressor blading.

GT26008.ppt

Peaking ~ Cyclic ~ Continuous

• Operational Profile Is Application Specific• Inspection Interval Is Application Specific

Peaking Cyclic

Hot Start (Down <4 Hr.)

Warm 1 Start (Down 4-20 Hr.)

Warm 2 Start (Down 20-40 Hr.)

Cold Start (Down >40 Hr.)

Hours/Start

Hours/Year

Starts per Year

Percent Trips

Number of Trips per Year

Continuous

3%

10%

37%

50%

4

600

150

3%

5

1%

82%

13%

4%

16

4800

300

1%

3

10%

5%

5%

80%

400

8200

21

20%

4

Typical Maintenance Factor(Starts Based)

1.7 1.0 NA

Figure 24. Gas turbine typical operational profile

GER-3620F

15

There are also non-recoverable losses. In the com-pressor, these are typically caused by non-deposit-

related blade surface roughness, erosion and blade tiprubs. In the turbine, nozzle throat area changes,bucket tip clearance increases and leakages are po-tential causes. Some degree of unrecoverable per-formance degradation should be expected, even on awell-maintained gas turbine.

The owner, by regularly monitoring and recordingunit performance parameters, has a very valuabletool for diagnosing possible compressor deterioration.

MAINTENANCE INSPECTIONSMaintenance inspection types may be broadly

classified as standby, running and disassembly in-spections. The stand-by inspection is performed dur-ing off-peak periods when the unit is not operatingand includes routine servicing of accessory systemsand device calibration. The running inspection is per-formed by observing key operating parameters whilethe turbine is running. The disassembly inspectionrequires opening the turbine for inspection of internalcomponents and is performed in varying degrees.Disassembly inspections progress from the combus-

GT26009A.ppt

Baseline Unit Achieves Maintenance Factor = 1

Baseline Unit

Starts/WeekHours/StartOutage/Year MaintenanceWeeks/YearHours/YearStarts/YearTrips/YearMaintenance Factor

Cold Starts/Year (Down >40 Hr.)Warm 2 Starts/Year (Down 20-40 Hr.)Warm 1 Starts/Year (Down 4-20 Hr.)Hot Starts per Year

Cyclic Duty

616450

4800300

01

1239

2463

4%13%82%

1%

Figure 25. Baseline for starts-based maintenance factor definition

GT16664B .ppt

Heat RateIncrease

%

OutputDecrease

%

-6

-10

-8

-4

-2

0

2

4

6

8

Pressure Ratio Decrease - %

-1 -2 -8-7-6-5-4-3

-12

-14

5% Loss ofAirflow

Fouling

Fouling

Figure 26. Deterioration of gas turbine performancedue to compressor blade fouling

GER-3620F

16

tion inspection to the hot-gas-path inspection to themajor inspection as shown in Figure 27. Details ofeach of these inspections are described below.

Stand-By InspectionsStand-by inspections are performed on all gas tur-

bines but pertain particularly to gas turbines used inpeaking and intermittent-duty service where startingreliability is of primary concern. This inspection in-cludes routinely servicing the battery system, chang-ing filters, checking oil and water levels, cleaningrelays and checking device calibrations. Servicingcan be performed in off-peak periods without inter-rupting the availability of the turbine. A periodicstart-up test run is an essential part of the stand-byinspection.

The Maintenance and Instructions Manual, as well asthe Service Manual Instruction Books, contain infor-mation and drawings necessary to perform these periodicchecks. Among the most useful drawings in the ServiceManual Instruction Books for stand-by maintenance arethe control specifications, piping schematic and electricalelementaries. These drawings provide the calibrations,operating limits, operating characteristics and sequenc-ing of all control devices. This information should beused regularly by operating and maintenance personnel.Careful adherence to minor stand-by inspection mainte-nance can have a significant effect on reducing overallmaintenance costs and maintaining high turbine reliabil-ity. It is essential that a good record be kept of all in-spections made and of the maintenance work performedin order to ensure establishing a sound maintenance pro-gram.

Running InspectionsRunning inspections consist of the general and

continued observations made while a unit is operat-ing. This starts by establishing baseline operatingdata during initial start-up of a new unit and after anymajor disassembly work. This baseline then serves asa reference from which subsequent unit deteriorationcan be measured.

Data should be taken to establish normal equip-ment start-up parameters as well as key steady-stateoperating parameters. Steady-state is defined as con-ditions at which no more than a 5 F/3 C change inwheelspace temperature occurs over a 15-minute timeperiod.

Data must be taken at regular intervals and shouldbe recorded to permit an evaluation of the turbineperformance and maintenance requirements as afunction of operating time. This operating inspectiondata, summarized in Figure 28, includes: load versusexhaust temperature, vibration, fuel flow and pres-sure, lube oil pressure, exhaust gas temperatures,exhaust temperature spread variation and start-uptime. This list is only a minimum and other parame-ters should be used as necessary. A graph of theseparameters will help provide a basis for judging theconditions of the system. Deviations from the normhelp pinpoint impending trouble, changes in calibra-tion or damaged components.

Load Versus Exhaust TemperatureThe general relationship between load and exhaust

temperature should be observed and compared toprevious data. Ambient temperature and barometricpressure will have some effect upon the absolutetemperature level. High exhaust temperature can bean indicator of deterioration of internal parts, exces-sive leaks or a fouled air compressor. For mechanicaldrive applications, it may also be an indication ofincreased power required by the driven equipment.

Vibration LevelThe vibration signature of the unit should be ob-

served and recorded. Minor changes will occur withchanges in operating conditions. However, largechanges or a continuously increasing trend give indi-cations of the need to apply corrective action.

Fuel Flow and PressureThe fuel system should be observed for the general

fuel flow versus load relationship. Fuel pressuresthrough the system should be observed. Changes in

GT19877B .ppt

Major Inspection

Hot-Gas-PathInspection

CombustionInspection

Figure 27. MS7001EA heavy-duty gas turbine -shutdown inspections

GER-3620F

17

fuel pressure can indicate the fuel nozzle passages areplugged, or that fuel metering elements are damagedor out of calibration.

Exhaust Temperature and Spread VariationThe most important control function to be ob-

served is the exhaust temperature fuel override sys-tem and the back-up overtemperature trip system.Routine verification of the operation and calibrationof these functions will minimize wear on the hot-gas-path parts.

The variations in turbine exhaust temperaturespread should be measured and monitored on a regu-lar basis. Large changes or a continuously increasingtrend in exhaust temperature spread indicate com-bustion system deterioration or fuel distributionproblems. If the problem is not corrected, the life ofdownstream hot-gas-path parts will be reduced.

Start-Up TimeStart-up time is an excellent reference against

which subsequent operating parameters can be com-pared and evaluated. A curve of the starting parame-ters of speed, fuel signal, exhaust temperature andcritical sequence bench marks versus time from theinitial start signal will provide a good indication of

the condition of the control system. Deviations fromnormal conditions help pinpoint impending trouble,changes in calibration or damaged components.

Coast-Down TimeCoast-down time is an excellent indicator of bear-

ing alignment and bearing condition. The time periodfrom when the fuel is shut off on a normal shutdownuntil the rotor comes to a standstill can be comparedand evaluated.

Close observation and monitoring of these operat-ing parameters will serve as the basis for effectivelyplanning maintenance work and material require-ments needed for subsequent shutdown periods.

Combustion InspectionThe combustion inspection is a relatively short

disassembly shutdown inspection of fuel nozzles, lin-ers, transition pieces, crossfire tubes and retainers,spark plug assemblies, flame detectors and combus-tor flow sleeves. This inspection concentrates on thecombustion liners, transition pieces fuel nozzles andend caps which are recognized as being the first torequire replacement and repair in a good maintenanceprogram. Proper inspection, maintenance and repair

• 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 Drains

− Exhaust Spread

GT05418E .ppt

• Pressures

− Compressor Discharge

− Lube Pump(s)

− Bearing Heading

− Cooling Water

− Fuel

− Filters (Fuel, Lube, Inlet Air)

• Vibration Data for Power Train

• Generator

− Output Voltage

− Phase Current

− VARS

− Load

• Start-Up Time

• Coast-Down Time

− Field Voltage

− Field Current

− Stator Temp.

− Vibration

Figure 28. Operating inspection data parameters

GER-3620F

18

(Figure 29) of these items will contribute to a longerlife of the downstream parts, such as turbine nozzlesand buckets.

Figure 27 illustrates the section of an MS7001EAunit that is disassembled for a combustion inspection.The combustion liners, transition pieces and fuel noz-zle assemblies should be removed and replaced withnew or repaired components to minimize downtime.The removed liners, transition pieces and fuel nozzlescan then be cleaned and repaired after the unit is re-turned to operation and be available for the nextcombustion inspection interval. Typical combustioninspection requirements forMS6001B/7001EA/9001E machines are:

• Inspect and identify combustion chamber com-ponents.

• Inspect and identify each crossfire tube, retainerand combustion liner.

• Inspect combustion chamber interior for debrisand foreign objects.

• Inspect flow sleeve welds for cracking.• Inspect transition piece for wear and cracks.• Inspect fuel nozzles for plugging at tips, erosion

of tip holes and safety lock of tips.

• Inspect all fluid, air, and gas passages in nozzleassembly for plugging, erosion, burning, etc.

• Inspect spark plug assembly for freedom frombinding, check condition of electrodes and in-sulators.

• Replace all consumables and normal wear-and-tear items such as seals, lockplates, nuts, bolts,gaskets, etc.

• Perform visual inspection of first-stage turbinenozzle partitions and borescope inspect (Figure3) turbine buckets to mark the progress of wearand deterioration of these parts. This inspectionwill help establish the schedule for the hot-gas-path inspection.

• Perform borescope inspection of compressor.•· Enter the combustion wrapper and observe the

condition of blading in the aft end of axial-flowcompressor with a borescope.

• Visually inspect the compressor inlet and tur-bine exhaust areas, checking condition of IGVs,IGV bushings, last-stage buckets and exhaustsystem components.

• Verify proper operation of purge and checkvalves. Confirm proper setting and calibrationof the combustion controls.

GT23690C.ppt

Criteria• Op. & Instr. Manual• TIL’s• GE Field Engineer

• Combustion Liners• Combustion End Covers• Fuel Nozzles

• End Caps• Transition Pieces• Cross Fire Tubes• Flow Sleeves

• Purge Valves• Check Valves• Spark Plugs• Flame Detectors

• Flex Hoses

• Foreign Objects• Abnormal Wear• Cracking

• Liner Cooling Hole Plugging• TBC Coating Condition• Oxidation/Corrosion/Erosion• Hot Spots/Burning

• Missing Hardware• Clearance Limits• Borescope Compressor and

Turbine

• Repair/Refurbishment• Liners

Cracking/Erosion/Wear TBC Repair

• Transition Pieces Wear TBC Repair Distortion

• Fuel Nozzles Plugging Wear/Erosion

• Cross Fire Tubes Wear/Burning

Combustion Inspection

Inspect For:

Inspection Methods• Visual• LP• Borescope

Key Hardware Potential Actions:

Availability of On-SiteSpares Is Key to

Minimizing Downtime

Figure 29. Combustion inspection - key elements

GER-3620F

19

After the combustion inspection is complete andthe unit is returned to service, the removed combus-tion liners and transition pieces can be bench-inspected and repaired, if necessary, by either com-petent on-site personnel, or off-site at a qualified GECombustion Service Center. The removed fuel noz-zles can be cleaned on-site and flow tested on-site, ifsuitable test facilities are available. For F Class gasturbines it is recommended that repairs and fuel noz-zle flow testing be performed at qualified GE ServiceCenters.

Hot-Gas-Path InspectionThe purpose of a hot-gas-path inspection is to ex-

amine those parts exposed to high temperatures fromthe hot gases discharged from the combustion proc-ess. The hot-gas-path inspection outlined in Figure 30includes the full scope of the combustion inspectionand, in addition, a detailed inspection of the turbinenozzles, stationary stator shrouds and turbine buck-

ets. To perform this inspection, the top half of theturbine shell must be removed. Prior to shell removal,proper machine centerline support using mechanicaljacks is necessary to assure proper alignment of rotorto stator, obtain accurate half-shell clearances andprevent twisting of the stator casings. TheMS7001EA jacking procedure is illustrated in Figure31.

For inspection of the hot-gas-path (Figure 27), allcombustion transition pieces and the first-stage tur-bine nozzle assemblies must be removed. Removal ofthe second- and third-stage turbine nozzle segmentassemblies is optional, depending upon the results ofvisual observations and clearance measurement. Thebuckets can usually be inspected in place. Also, it isusually worthwhile to fluorescent penetrant inspect(FPI) the bucket vane sections to detect any cracks.In addition, a complete set of internal turbine radialand axial clearances (opening and closing) must betaken during any hot-gas-path inspection. Typicalhot-gas-path inspection requirements for all machinesare:

• Inspect and record condition of first-, second-and third-stage buckets. If it is determined thatthe turbine buckets should be removed, followbucket removal and condition recording in-structions. The first-stage bucket protectivecoating should be evaluated for remainingcoating life.

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

• Inspect and record condition of later-stage noz-

GT26077.ppt

Figure 31. Stator tube jacking procedure - MS7001EA

GT23691A .ppt


Nozzles (1,2,3)

Buckets (1,2,3)

Stator Shrouds

IGVs & Bushings

Compressor Blading(Borescope)

• Foreign Object Damage• Oxidation/Corrosion/Erosion

• Cracking• Cooling Hole Plugging• Remaining Coating Life

• Nozzle Deflection/Distortion• Abnormal Deflection/Distortion• Abnormal Wear

• Missing Hardware• Clearance Limits

Repair/Refurbishment/Replace• Nozzles

Weld Repair Reposition Recoat

• Buckets Strip & Recoat

Weld Repair Blend Creep Life Limit Top Shroud Deflection

Hot Gas Path Inspection

Inspect For:

Inspection Methods• Visual• LP• Borescope


Availability of On-SiteSpares Is Key to

Minimizing Downtime

Figure 30. Hot gas path inspection - key elements

GER-3620F

20

zle diaphragm packings. Check seals for rubsand deterioration of clearance.

• Record the bucket tip clearances. Inspect bucketshank seals for clearance, rubs and deteriora-tion.

• Check the turbine stationary shrouds for clear-ance, cracking, erosion, oxidation, rubbing andbuild-up.

• Check and replace any faulty wheelspace ther-mocouples.

• Enter compressor inlet plenum and observe thecondition of the forward section of the compres-sor. Pay specific attention to IGVs, looking forcorrosion, bushing wear evidenced by excessiveclearance and vane cracking.

• Enter the combustion wrapper and, with aborescope, observe the condition of the bladingin the aft end of the axial-flow compressor.

• Visually inspect the turbine exhaust area forany signs of cracking or deterioration.

The first-stage turbine nozzle assembly is exposedto the direct hot-gas discharge from the combustionprocess and is subjected to the highest gas tempera-tures in the turbine section. Such conditions fre-quently cause nozzle cracking and oxidation and, infact, this is expected. The second- and third-stagenozzles are exposed to high gas bending loads which,in combination with the operating temperatures, canlead to downstream deflection and closure of criticalaxial clearances. To a degree, nozzle distress can betolerated and criteria have been established for de-termining when repair is required. These limits arecontained in the Maintenance and Instruction Bookspreviously described. However, as a general rule,first-stage nozzles will require repair at the hot-gas-path inspection. The second- and third-stage nozzlesmay require refurbishment to re-establish the properaxial clearances. Normally, turbine nozzles can berepaired several times to extend life and it is generallyrepair cost versus replacement cost that dictates thereplacement decision.

Coatings play a critical role in protecting the first-stage buckets to ensure that the full capability of thehigh strength superalloy is maintained and that thebucket rupture life meets design expectations. This isparticularly true of cooled bucket designs that operateabove 1985 F (1085 C) firing temperature. Signifi-cant exposure of the base metal to the environmentwill accelerate the creep rate and can lead to prema-ture replacement through a combination of increasedtemperature and stress and a reduction in material

strength, as described in Figure 32. This degradationprocess is driven by oxidation of the unprotected basealloy. In the past, on early generation uncooled de-signs, surface degradation due to corrosion or oxida-tion was considered to be a performance issue andnot a factor in bucket life. This is no longer the caseat the higher firing temperatures of current generationdesigns.

Given the importance of coatings, it must be rec-ognized that even the best coatings available willhave a finite life and the condition of the coating willplay a major role in determining bucket replacementlife. Refurbishment through stripping and recoating isan option for extending bucket life, but if recoating isselected, it should be done before the coating hasbreached to expose base metal. Normally, for tur-bines in the MS7001EA class, this means that re-coating will be required at the hot-gas-path inspec-tion. If recoating is not performed at the hot-gas-pathinspection, the runout life of the buckets would gen-erally extend to the major inspection, at which pointthe buckets would be replaced. For F class gas tur-bines recoating of the first stage buckets is recom-mended at each hot gas path inspection.

Recoating is not considered an option for bucketswith uncoated cooling holes. The economics of re-coating buckets must look at the cost to recoat versusthe cost to replace buckets at more frequent intervals.Economic evaluations of this trade-off suggest thatrecoating may make sense for the larger designs butless so for the smaller frame sizes.

Visual and borescope examination of the hot-gas-path parts during the combustion inspections as wellas nozzle-deflection measurements will allow the op-erator to monitor distress patterns and progression.This makes part-life predictions more accurate andallows adequate time to plan for replacement or re-furbishment at the time of the hot-gas-path inspec-tion. It is important to recognize that to avoid ex-

Increases Stress

−Reduced Load Carrying Cross Section

Increases Metal Temperature

−Surface Roughness Effects

Decreases Alloy Creep Strength

−Environmental Effects

GT23697 .ppt

Base Metal Oxidation

Reduces Bucket Creep Life

Figure 32. Stage 1 bucket: oxidation and bucket life

GER-3620F

21

tending the hot-gas-path inspection, the necessaryspare parts should be on site prior to taking the unitout of service.

Major InspectionThe purpose of the major inspection is to examine

all of the internal rotating and stationary componentsfrom the inlet of the machine through the exhaustsection of the machine. A major inspection should be

scheduled in accordance with the recommendations inthe owner's Maintenance and Instructions Manual oras modified by the results of previous borescope andhot-gas-path inspection. The work scope shown inFigure 33 involves inspection of all of the majorflange-to-flange components of the gas turbine whichare subject to deterioration during normal turbineoperation. This inspection includes previous elements

GT23692A .ppt


Compressor Blading

Turbine Wheels Dovetails

Journals and Seal Surfaces

Bearing, Seals

Inlet System

Exhaust System

• Foreign Object Damage

• Oxidation/Corrosion/Erosion

• Cracking

• Leaks

• Abnormal Wear

• Missing Hardware

• Clearance Limits

Repair/Refurbishment/Replace

• Stator ShroudsCracking/Oxidation/Erosion

• BucketsCoating DeteriorationFOD/Rubs/CrackingTip Shroud DeflectionCreep Life Limit

• NozzlesSevere Deterioration

• IGV BushingsWear

• Bearings/SealsScoring/Wear

• Compressor BladesCorrosion/ErosionRubs/FOD

Major Inspection

Inspect For:

Inspection Methods• Visual• LP• Ultrasonics• Borescope


Figure 33. Gas turbine major inspection - key elements

GT07094C .ppt

Figure 34. Major inspection work scope

GER-3620F

22

of the combustion and hot-gas-path inspections, inaddition to laying open the complete flange-to-flangegas turbine to the horizontal joints, as shown in Fig-ure 34, with inspections being performed on individ-ual items.

Prior to removing casings, shells and frames, theunit must be properly supported. Proper centerlinesupport using mechanical jacks and jacking sequenceprocedures are necessary to assure proper alignmentof rotor to stator, obtain accurate half shell clear-ances and to prevent twisting of the casings while onthe half shell.

Typical major inspection requirements for all ma-chines are:

• All radial and axial clearances are checked againsttheir original values (opening and closing).

• Casings, shells and frames/diffusers are in-spected for cracks and erosion.

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

• Rotor and stator compressor blades are checkedfor tip clearance, rubs, impact damage, corro-sion pitting, bowing and cracking.

• Turbine stationary shrouds are checked forclearance, erosion, rubbing, cracking, and build-up.

• Seals and hook fits of turbine nozzles and dia-phragms are inspected for rubs, erosion, frettingor thermal deterioration.

• Turbine buckets are removed and a non-destructive check of buckets and wheel dovetailsis performed (first-stage bucket protective coat-ing should be evaluated for remaining coatinglife). First-stage buckets that were not recoated

GT19795E

Figure 35. Estimated repair and replacement cycles (MS6001B/MS7001EA/MS9001E)

GER-3620F

23

at the hot-gas-path inspection should be re-placed.

• Rotor inspections recommended in the mainte-nance and inspection manual or by Technical In-formation Letters should be performed.

• Bearing liners and seals are inspected forclearance and wear.

• Inlet systems are inspected for corrosion,cracked silencers and loose parts.

• Exhaust systems are inspected for cracks, bro-ken silencer panels or insulation panels.

• Check alignment - gas turbine to generator/ gas

turbine to accessory gear.Comprehensive inspection and maintenance

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

PARTS PLANNINGLack of adequate on-site spares can have a major

effect on plant availability; therefore, prior to ascheduled disassembly type of inspection, adequatespares should be on site. A planned outage such as acombustion inspection, which should only take two tofive days, could take weeks. GE will provide recom-mendations regarding the types and quantities ofspare parts needed; however, it is up to the owner topurchase these spare parts on a planned basis allow-ing adequate lead times.

Early identification of spare parts requirements en-sures their availability at the time the planned inspec-tions are performed. There are two documents whichsupport the ordering of gas turbine parts by catalognumber. The first is the Renewal Parts Catalog - Il-lustrations and Text. This document contains genericillustrations which are used for identifying parts. Thesecond document, the Renewal Parts Catalog Order-

GT20310B .ppt

Without Repair

Severe Deterioration

2ndRepair

3rdRepair

Operating Hours

New NozzleAcceptance Standards

Repaired NozzleMin. AcceptanceStandard

1stRepair

Noz

zle

Con

ditio

n

Rep

air

Cos

t Exc

eeds

Rep

lace

men

t Cos

t

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

Figure 36. First-stage nozzle wear-preventative main-tenance: gas fired - continuous duty - base load

Figure 37. Estimated repair and replacement cycles

GER-3620F

24

ing Data Manual, contains unit site-specific catalogordering data.

Additional benefits available from the renewalparts catalog data system are the capability to pre-pare recommended spare parts lists for the combus-tion, hot-gas-path and major inspections as well ascapital and operational spares.

Furthermore, interchangeability lists may be pre-pared for multiple units. The information contained inthe Catalog Ordering Data Manual can be providedas a computer printout, on microfiche or on a com-puter disc. As the size of the data base grows, and asgeneric illustrations are added, the usefulness of thistool will be continuously enhanced.

Typical expectations for estimated repair cyclesfor some of the major components are shown in Fig-ure 35. Many engineering judgments are built intothis table, including base-load continuous-duty onnatural-gas fuel and operation of the unit in accor-dance with all of the manufacturer's specificationsand instructions. Maintenance inspections and repairsare also assumed to be done in accordance with themanufacturer's specifications and instructions. Theactual repair and replacement cycles for any particu-lar gas turbine should be based on the user's operat-ing procedures, experience, maintenance practicesand repair practices. The maintenance factors previ-

ously described can have a major impact on both thecomponent repair interval and service life. For thisreason, the intervals given in Figure 35 should onlybe used as guidelines and not certainties for longrange parts planning. Owners may want to includecontingencies in their parts planning.

Figures 37-40 show expected repair and replace-ment cycles for MS6001FA, MS7001F/FA andMS9001F/FA machines. These values reflect currentproduction hardware. To achieve these lives, currentproduction parts with design improvements andnewer coatings are required. With earlier productionhardware, some of these lives may not be achieved.Operating factors and experience gained during thecourse of recommended inspection and maintenanceprocedures will be a more accurate predictor of theactual intervals.

It should be recognized that, in some cases, theservice life of a component is reached when it is nolonger economical to repair any deterioration as op-posed to replacing at a fixed interval. This is illus-trated in Figure 36 for a first stage nozzle, where re-pairs continue until either the nozzle cannot be re-stored to minimum acceptance standards or the repaircost exceeds or approaches the replacement cost. Inother cases, such as first-stage buckets, repair op-tions are limited by factors such as irreversible mate-

GT26030A.ppt

PG7231FA PartsRepair Interval Replace Interval (Hours)

Combustion LinersCapsTransition PiecesFuel NozzlesCrossfire TubesStage 1 NozzlesStage 2 NozzlesStage 3 NozzlesStage 1 ShroudsStage 2 ShroudsStage 3 ShroudsExhaust DiffuserStage 1 BucketStage 2 BucketStage 3 Bucket

Replace Interval (Starts)CICICICICI

HGPIHGPIHGPIHGPIHGPIHGPIHGPIHGPIHGPIHGPI

5 (CI)(1)

5 (CI)(1)

5 (CI)(1)

3 (CI)3 (CI)

2 (HGPI)(2)

2 (HGPI)(2)

3 (HGPI)2 (HGPI)(2)

2 (HGPI)(2)

3 (HGPI)

3 (HGPI)(2)

3 (HGPI)(3)

2 (HGPI)

5 (CI)5 (CI)5 (CI)3 (CI)3 (CI)

2 (HGPI)(2)

2 (HGPI)(2)

3 (HGPI)2 (HGPI)(2)

2 (HGPI)(2)

3 (HGPI)

2 (HGPI)3 (HGPI)(3)

3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) Current hardware may not achieve this interval.(2) The goal is to increase to 3 (HGPI). Decision will be made based on fleet leader experience. Also requires a repair and recoat at every HGPI.(3) Recoating at 1st HGPI is required to achieve 3 HGPI replacement life.


GER-3620F

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rial damage. In both cases, users should follow GErecommendations regarding replacement or repair ofthese components.

While the parts lives for Figure 35 and Figures 37-40 are guidelines, the life consumption of individualparts within a parts set can have variations. The re-pair versus replacement economics shown in Figure36 may lead to a certain percentage of "fallout", orscrap, of parts being repaired. Those parts that fall-out during the repair process will need to be replacedby new parts. The amount of fallout of parts dependson the unit operating environment history, the specificpart design, and the current state-of-the-art for repairtechnology.

INSPECTION INTERVALSFigure 41 lists the recommended combustion, hot-

gas-path and major inspection intervals for currentproduction GEturbines operating under ideal condi-tions of gas fuel, base load, no water orsteam injection, and without a Dry Low NOxcombustor. Considering the maintenance factors dis-cussed previously, an adjustment from these maxi-mum intervals may be necessary, based on the spe-cific operating conditions of a given application. Ini-tially, this determination is based on the expected

operation of a turbine installation, but this should bereviewed and adjusted as actual operating and main-tenance data are accumulated. While reductions inthe maximum intervals will result from the factorsdescribed previously, increases in the maximum in-terval can also be considered where operating experi-ence has been favorable. The condition of the hot-gas-path parts provides a good basis for customizinga program of inspection and maintenance.

GEcan assist operators in determining the appro-priate maintenance intervals for their particular ap-plication. Equations have been developed that ac-count for the factors described earlier and can beused to determine application specific hot-gas-pathand major inspection intervals. The hours-based hot-gas-path criterion is determined from the equationgiven in Figure 42. With this equation, a maintenancefactor is determined that is the ratio of factored oper-ating hours and actual operating hours. The factoredhours consider the specifics of the duty cycle relatingto fuel type, load setting and steam or water injection.Maintenance factors greater than one reduce the hotgas path inspection interval from the 24,000 hourideal case for continuous base load, gas fuel and nosteam or water injection. To determine the applica-tion specific maintenance interval, the maintenancefactor is divided into 24,000, as shown in Figure 42.

GT26031A.ppt





5 (CI)5 (CI)5 (CI)3 (CI)3 (CI)

2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)

3 (HGPI)(1)

2 (HGPI)1 (HGPI)

5 (CI)5 (CI)5 (CI)3 (CI)3 (CI)

2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)

2 (HGPI)3 (HGPI)(2)

3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) The goal is to increase to 3 (HGPI). Decision will be made based on fleet leader experience. Also requires a repair and recoat at every HGPI.(2) Recoating at 1st HGPI is required to achieve 3 HGPI replacement life.


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26

The starts-based hot-gas-path criterion is deter-mined from the equation given in Figure 43. As withthe hours-based criteria, an application specificstarts-based hot gas path inspection interval is cal-culated from a maintenance factor that is determinedfrom the number of trips typically being experienced,the load level and loading rate.

The starts-based rotor maintenance interval is de-termined from the equation given in Figure 44. Ad-justments to the rotor maintenance interval are deter-mined from rotor-based operating factors as weredescribed previously. In the calculation for the starts-based rotor maintenance interval, equivalent startsare determined for cold, warm, and hot starts over adefined time period by multiplying the appropriatecold, warm and hot start operating factor times andnumber of cold, warm and hot starts respectively. Inthis calculation, the type of start must be considered.Additionally, equivalent starts for trips from load areadded. The equivalent start total is divided by theactual number of starts to yield the maintenance fac-tor. The rotor starts based maintenance interval for aspecific application is determined by dividing thebaseline rotor maintenance interval of 5000 starts bythe calculated maintenance factor. As indicated inFigure 44, the rotor maximum maintenance interval

is 5000 starts. Calculated maintenance factors thatare less than one are not considered.

Figure 45 describes the procedure to determine thehours-based maintenance criterion. Peak load opera-tion is the primary maintenance factor for the FrameMS7001/9001F and FA class rotors and will act toincrease the hours-based maintenance factor and toreduce the rotor maintenance interval. Hours onturning gear are also considered as an equivalenthours adder as noted in Figure 45.

For rotors other than Frame MS7001/9001F andFA, rotor maintenance should be performed at inter-

GT23693G.ppt

Factors That Can Reduce Maintenance Intervals

• Fuel

• Load Setting

• Steam/Water Injection

• Peak Load TF Operation

• Trips From Load

• Start Cycle

• HGP Hardware Design

Type ofInspection

MS32/51/52Uprates

MS6B

CombustionHot Gas PathMajor

12,000/800Eliminated/1,20048,000/2,400

12,000/1,20024,000/1,20048,000/2,400

MS7E/EA

8,000/80024,000/1,20048,000/2,400

9E

8,000/80024,000/90048,000/2,400

MS6F*/7F/9F

8,000/40024,000/90048,000/2,400

Hours/Starts

Rotor* 144,000/5,000

*Rotor inspection interval is not applicable for MS6F units

Figure 41. Base line recommended inspectionintervals: 3base load - gas fuel - dry

GT26045A.ppt





5 (CI)5 (CI)5 (CI)3 (CI)3 (CI)

2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)

3 (HGPI)(1)

1 (HGPI)1 (HGPI)

5 (CI)5 (CI)5 (CI)3 (CI)3 (CI)

2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)2 (HGPI)(1)

2 (HGPI)(1)

3 (HGPI)

2 (HGPI)3 (HGPI)(2)

3 (HGPI)

CI = Combustion Inspection IntervalHGPI = Hot Gas Path Inspection Interval(1) The goal is to increase to 3 (HGPI). Decision will be made based on fleet leader experience. Also requires a repair and recoat at every HGPI.(2) Recoating at 1st HGPI is required to achieve 3 HGPI replacement life.


GER-3620F

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vals recommended by GE through issued TechnicalInformation Letters. Where no recommendations havebeen made, rotor inspection should be performed at5,000 starts or 200,000 hours.

As previously described, the hours and starts op-erating spectrum for the application is evaluatedagainst the recommended hot gas path intervals forstarts and for hours. The limiting criterion (hours orstarts) determines the maintenance interval. An ex-ample of the use of these equations is contained in theappendix.

While the hot-gas-path and major inspection inter-val can be determined from the equations given inFigures 42-45, the combustion intervals have notbeen reduced to that form. Recommendations areprovided that are specific to the combustion hardwaredesign, fuel, type of diluent and emissions level. Rec-ommendations for combustion intervals for specific

application can be provided by the GE Energy Serv-ices representative.

As an example, Figure 46 describes the recom-mended combustion inspection intervals for theMS7001EA. As noted, application of the new Ex-tendor- Combustion System Wear Kit has the poten-tial to significantly increase the stated intervals.

MANPOWER PLANNING

It is essential that advanced manpower planning beconducted prior to an outage. It should be under-stood that a wide range of experience, productivityand working conditions exist around the world. How-ever, based upon maintenance inspection man-hourassumptions, such as the use of an average crew ofworkers in the United States with trade skill (but notnecessarily direct gas turbine experience), with all

GT23694D.ppt

Maintenance Interval = (Hours)

24000Maintenance Factor

Where: Maintenance Factor = Factored Hours = (K + M x I) x (G + 1.5D + AfH + 6P) Actual Hours = (G + D + H + P) G = Annual Base Load Operating Hours on Gas Fuel D = Annual Base Load Operating Hours on Distillate Fuel H = Annual Operating Hours on Heavy Fuel Af Heavy Fuel Severity Factor (Residual Af = 3 to 4, Crude Af = 2 to 3) P Annual Peak Load Operating Hours I Percent Water/Steam Injection Referenced to Inlet Air Flow M & K = Water/Steam Injection Constants

Factored HoursActual Hours

M 0 0.18.18.55

K 1 1.6 1 1

ControlDryDryDryWetWet

Steam Injection<2.2%>2.2%>2.2%>0%>0%

N2/N3 MaterialGTD-222/FSX-414

GTD-222FSX-414GTD-222FSX-414

==

=

Figure 42. Hot gas path inspection: hours-based criterion

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needed tools and replacement parts (no repair time)available, an estimate can be made. These estimatedcraft labor man-hours should include controls andaccessories and the generator. In addition to the craftlabor, additional resources are needed for technicaldirection of the craft labor force, specialized tooling,engineering reports, and site mobilization/de-mobilization.

Inspection frequencies and the amount of down-time varies within the gas turbine fleet due to differ-ent duty cycles and the economic need for a unit to bein a state of operational readiness. It can be demon-strated that an 8000 hour interval for a combustioninspection with minimum downtime (72 hours) isachievable based on the above factors. Contact yourlocal GE Energy Services representative for the spe-

cific man-hours and recommended crew size for yourspecific unit.

Depending upon the extent of work to be doneduring each maintenance task, a cooldown period of 4to 24 hours may be required. This time can be util-ized productively for job move-in, correct taggingand locking equipment out-of-service and generalwork preparations. At the conclusion of the mainte-nance work and systems check out, a turning geartime of two to eight hours is normally allocated priorto starting the unit. This time can be used for jobclean-up and arranging for any repairs required onremoved parts.

Local GE field service representatives are avail-able to help plan your maintenance work to reducedowntime and labor costs. This planned approachwill outline the renewal parts that may be needed and

GT23695B .ppt

Maintenance Interval =(Starts)

SMaintenance Factor

Where:

Maintenance Factor =

Factored Starts = (0.5 NA + NB + 1.3NP + 20E + 2F + Σ

Factored StartsActual Starts

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

aTi=1

ηTI I )

SNANBNPEFTaT

n

= Maximum Starts-Based Maintenance Interval (Model Size Dependent)= Annual Number of Part Load Start/Stop Cycles (<60% Load)= Annual Number of Normal Base Load Start/Stop Cycles= Annual Number of Peak Load Start/Stop Cycles= Annual Number of Emergency Starts= Annual Number of Fast Load Starts= Annual Number of Trips= Trip Severity Factor = f (Load) (See Figure 21)= Number of Trip Categories (i.e., Full Load, Part Load, etc.)

Model SeriesMS6B/MS7EAMS6FAMS9EMS7F/7FA/9F/9FA

S 1,2001,200

900900

Figure 43. Hot gas path inspection starts-based criterion

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the projected work scope, showing which tasks canbe accomplished in parallel and which tasks must besequential. Planning techniques can be used to reducemaintenance cost by optimizing lifting equipmentschedules and manpower requirements. Precise esti-mates of the outage duration, resource requirements,critical-path scheduling, recommended replacementparts, and costs associated with the inspection of aspecific installation may be obtained from the localGE field services office.

CONCLUSIONGE heavy-duty gas turbines are designed to have

an inherently high availability. To achieve maximumgas turbine availability, an owner must understandnot only his equipment, but the factors affecting it.This includes the training of operating and mainte-

nance personnel, following the manufacturer's rec-ommendations, regular periodic inspections and thestocking of spare parts for immediate replacement.The recording of operating data, and analysis of thesedata, are essential to preventative and planned main-tenance. A key factor in achieving this goal is acommitment by the owner to provide effective outagemanagement and full utilization of published instruc-tions and the available service support facilities.

It should be recognized that, while the manufac-turer provides general maintenance recommendations,it is the equipment user who has the major impactupon the proper maintenance and operation ofequipment. Inspection intervals for optimum turbineservice are not fixed for every installation, but ratherare developed through an interactive process by eachuser, based on past experience and trends indicatedby key turbine factors.

GT26010A .ppt

Starts Based Rotor Maintenance Interval Calculation


Rotor Maintenance Interval = 5000Maintenance Factor

( Fh*Nh + Fw1*Nw1 +Fw2*Nw2 +Fc*Nc + Ft*Nt )(Nh + Nw1 + Nw2 + Nc)

(Not to exceed 5000 starts)MF>=1

PG7241 & PG9351 Designs

Where:

Fh ~ Hot start factor (Down 1-4 hr)Fw1 ~ Warm1 start factor (Down 4-20 hr)Fw2 ~ Warm2 start factor (Down 20-40 hr)Fc ~ Cold start factor (Down >40hr)Ft ~ Trip from load factor

* For restarts within the first hour after a hot shutdown use cold

start rotor maintenance factor

Nh ~ Number of Hot StartsNw1 ~ Number of Warm1 startsNW2 ~ Number of Warm2 StartsNc ~ Number of Cold startsNt ~ Number of trips

1.01.82.84.04.0

0.50.91.42.04.0

Fas

tL

oad

Nor

mal

Loa

d

Figure 44. Rotor maintenance factor for starts based criterion

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The level and quality of a rigorous maintenanceprogram have a direct impact on equipment reliabilityand availability. Therefore, a rigorous maintenanceprogram which optimizes both maintenance cost andavailability is vital to the user. A rigorous mainte-nance program will minimize overall costs, keep out-age downtimes to a minimum, improve starting andrunning reliability and provide increased availabilityand revenue-earning ability for GE gas turbine users.

REFERENCES1. Jarvis, G., "Maintenance of Industrial Gas Tur-

bines," GE Gas Turbine State of the Art Engi-neering Seminar, paper SOA-24-72; June 1972.

2. Patterson, J. R., "Heavy-Duty Gas TurbineMaintenance Practices," GE Gas Turbine Refer-ence Library, GER-2498; June 1977.

3. Moore, W.J, Patterson, J.R.. and Reeves, E.F.,"Heavy-Duty Gas Turbine Maintenance Planningand Scheduling," GE Gas Turbine Reference Li-

brary, GER-2498; June 1977, GER-2498A; June1979.

4. Carlstrom, L.A., et al., "The Operation andMaintenance of General Electric Gas Turbines,"numerous maintenance articles/ authors reprintedfrom Power Engineering magazine; General Elec-tric Publication, GER-3148; December 1978.

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

6. Freeman, Alan, "Gas Turbine Advance Mainte-nance Planning," GE paper presented at "Frontiersof Power" Conference, Oklahoma State Univer-sity; October 1987.

7. Hopkins, J.P. and Osswald, R.F. "Evolution of theDesign, Maintenance and Availability of a LargeHeavy-Duty Gas Turbine," GE Gas Turbine Ref-erence Library, GER-3544; February, 1988(Never printed).

GT26011A.ppt

Hours Based Rotor Maintenance Interval Calculation


Rotor Maintenance Interval =

H + 2*P + 2*TGH + P

144000Maintenance Factor

Where: H ~ Base load hours P ~ Peak load hours TG ~ Hours on turning gear

Figure 45. Rotor maintenance factor for hours-based criterion

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8. Freeman, M.A. and Walsh, E.J., "Heavy-DutyGas Turbine Operating and Maintenance Consid-erations," GE Gas Turbine Reference Library,GER-3620A.

9. GEI 41040E, "Fuel Gases For Combustion InHeavy-Duty Gas Turbines".

APPENDIXA) Example - Maintenance Interval Calculation

An MS7001EA user has accumulated operatingdata since the last hot gas path inspection and wouldlike to estimate when the next one should be sched-uled. The user is aware from GE publications that thenormal HGP interval is 24,000 hours if operating onnatural gas, no water or steam injection, base load.Also, there is a 1200 start interval, based on normalstartups, no trips, no emergency starts.

The actual operation of the unit since the last hotgas path inspection is much different from the GE"baseline 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

CombustorDesign

NOxEmissions

Levelppm Diluent

GasHours/Starts

DistillateHours/Starts

Fuel

Standard Liner Dry 8,000/800 8,000/800

SteamWater

——

8,000/4006,500/300

65

SteamWater

8,000/4006,500/300

3,000/1501,500/100

42

Dry 8,000/400* —

SteamWater

——

6,000/3006,000/300

42

SteamWater

8,000/4008,000/400

——

25

25Dry Low NOx

Multi-NozzleQuiet Combustor

ExtendorTM Combustion System Wear Kit IncreasesCombustion Inspection to As Much As 24,000 Hours

GT24392A .ppt

Figure 46. Combustion inspection intervals - MS7001EA

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= E = 2/yrThe annual number of fast load starts

= F = 5/yrThe annual number of trips from load (aT = 8)

= T = 20/yr

For this particular unit, the second- and third-stagenozzles are FSX-414 material. The unit operates on"dry control curve."

From Figure 36, at a steam injection rate of 2.4%,the value of "M" is .18, and "K" is .6.

From the hours-based criteria, the maintenancefactor is determined from Figure 36.

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 = 24,000/1.25H = 19,200 hours [Note, since total annual op-

erating hours is 3670, the es-timated time to reach 19,200hours is 5.24 years(19,200/3670).]

From the starts-based criteria, the maintenancefactor is determined from Figure 37.

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

(100 + 40 + 2 + 5 + 20)

MF = 2.0

The adjusted inspection interval based on starts is,S = 1200/2.0S = 600 starts [Note, since the total annual num-

ber of starts is 167, the estimatedtime to reach 600 starts is 600/167= 3.6 years.]

In this case, the starts-based maintenance factor isgreater than the hours maintenance factor and there-fore the inspection interval is set by starts. The hotgas path inspection interval is 600 starts (or 3.6years).

B) DefinitionsReliability: Probability of not being forced out of

service when the unit is needed-includes forced out-age hours (FOH) while in service, while on reserveshutdown and while attempting to start-normalizedby period hours (PH)- units are %:

Reliability = (1-FOH/PH)(100)

FOH = total forced outage hoursPH = period hours

Availability: Probability of being available, inde-pendent of whether the unit is needed- includes allunavailable hours (UH)-normalized by period hours(PH)- units are %:

Availability = (1-UH/PH)(100)UH = total unavailable hours (forced outage,

failure to start, scheduled maintenance hours,unscheduled maintenance hours)

PH = period hours

Equivalent Reliability: Probability of a multi-shaft combined-cycle power plant not being totallyforced out of service when the unit is required - in-cludes the effect of the gas and steam cycle MW out-put contribution to plant output - units are %:

Equivalent Reliability =

GT FOH = Gas Turbine Forced Outage HoursGT PH = Gas Turbine Period HoursHRSG FOH = HRSG Forced Outage HoursB PH = HRSG Period HoursST FOH = Steam Turbine Forced Outage HoursST PH = Steam Turbine Period HoursB = Steam Cycle MW Output Contribu-

tion(normally 0.30)

Equivalent Availability: Probability of a multi-shaft combined-cycle power plant being available forpower generation-independent of whether the unit isneeded-includes all unavailable hours- includes theeffect of the gas and steam cycle MW output contri-bution to plant output-units are %:

Equivalent Availability =GT UH = Gas Turbine Unavailable HoursGT PH = Gas Turbine Period HoursHRSG UH = HRSG Total Unavailable HoursST UH = Steam Turbine Unavailable HoursST PH = Steam Turbine Forced Outage Hours

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B = Steam Cycle MW Output Contribu-tion(normally 0.30)

MTBF-Mean Time Between Failure: Measure ofprobability of completing the current run. Failureevents are restricted to forced outages (FO) while inservice - units are service hours:

MTBF = SH/FO

SH = Service HoursFO = Forced Outage Events from a Running (On-

line) ConditionService Factor: Measure of operational use, usu-

ally expressed on an annual basis-units are %:

SF = SH/PH x 100SH = Service Hours on an an-nual 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 150Continuous >90% >>150

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LIST OF FIGURES

Figure 1. Key factors affecting maintenance planningFigure 2. Plant level-top 5 systems contribution to downtimeFigure 3. MS7001E gas turbine borescope inspection access locationsFigure 4. Borescope inspection programmingFigure 5. Maintenance cost and equipment life are influenced by key service factorsFigure 6. Causes of wear - hot gas path componentsFigure 7. GE bases gas turbine maintenance requirements on independent counts of starts and hoursFigure 8. Hot gas path maintenance interval comparisons. GE method vs. EOH methodFigure 9. Maintenance factors - hot gas path (buckets and nozzles)Figure 10. GE maintenance interval for hot gas inspectionsFigure 11. Estimated effect of fuel type on maintenanceFigure 12. Bucket life firing temperature effect MS6001B/MS7001EA/MS9001EFigure 13. Firing temperature and load relationship - heat recovery vs. simple cycle operationFigure 14. Heavy fuel maintenance factorsFigure 15. Steam/water injection and bucket/nozzle lifeFigure 16. Exhaust temperature control curve - dry vs. wet control MS7001EAFigure 17. Turbine start/stop cycle - firing temperature changesFigure 18. First-stage bucket transient temperature distributionFigure 19. Bucket low cycle fatigue (LCF)Figure 20. Low cycle fatigue life sensitivities - first-stage bucketFigure 21. Maintenance factor - trips from loadFigure 22. Maintenance factor - effect of start cycle maximum load levelFigure 23. Operation related maintenance factorsFigure 24. Gas turbine typical operational profileFigure 25. Baseline for starts based maintenance factor definitionFigure 26. Deterioration of gas turbine performance due to compressor blade foulingFigure 27. MS7001EA heavy-duty gas turbine - shutdown inspectionsFigure 28. Operating inspection data parametersFigure 29. Combustion inspection - key elementsFigure 30. Hot gas path inspection - key elementsFigure 31. Stator tube jacking procedure - MS7001EAFigure 32. Stage 1 bucket oxidation and bucket lifeFigure 33. Gas turbine major inspection - key elementsFigure 34. Major inspection work scopeFigure 35. Estimated repair and replacement cycles (MS6001B/MS7001EA/MS9001E)Figure 36. First-stage nozzle wear-preventive maintenance gas fired - continuous dry - base loadFigure 37. Estimated repair and replacement cyclesFigure 38. Estimated repair and replacement cyclesFigure 39. Estimated repair and replacement cyclesFigure 40. Estimated repair and replacement cyclesFigure 41. Base line recommended inspection intervals: base load - gas fuel - dryFigure 42. Hot gas path inspection : hours-based criterionFigure 43. Hot gas path inspection starts-based conditionFigure 44. Rotor maintenance factor for starts-based criterionFigure 45. Rotor maintenance factor for hours based criterionFigure 46. Combustion inspection intervals - MS7001EA

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