9E_GT_M_M01_C01_V4_A

8/4/2019 9E_GT_M_M01_C01_V4_A

1/47

GE Energy Products Europe

Rev. : APage : 1/47

MAINTENANCE MANUALGAS TURBINE

All rights reserved Copyright - Droits de reproduction rservs9E_GT_M_M01_C01_P01_V2_A Revision: (A) Date: 02/05

1. INTRODUCTION AND STANDARD PRACTICES

1.1. INTRODUCTION

1.1.1. Foreword

This Maintenance Manual is applicable to all Gas Turbines of GE Energy ProductsEurope.

The subject is maintenance of GE Energy Products Europe Gas Turbines

Maintenance costs and availability are two of the most important concerns to theequipment owner. A maintenance program that optimizes the owner's costs andmaximizes equipment availability must be instituted. For a maintenance program to beeffective, the owner must develop a general understanding of the relationship between hisoperating plans and priorities of the plant, the skill level of operating and maintenancepersonnel, and the manufacturer's recommendations regarding the number and types of inspections, spare parts planning, and the major factors affecting component life andproper operation of the equipment.

In this paper, operating and maintenance practices will be reviewed with emphasis placedon types of inspections plus operating factors that influence maintenance schedules. Awell-planned maintenance program will result in maximum equipment availability andoptimal maintenance costs.

The operating and maintenance discussions presented in this paper aregenerally applicable to all heavy-duty gas turbines of GE Energy ProductsEurope; i. e., MS3000 , 5000, 6000, and 9000.

8/4/2019 9E_GT_M_M01_C01_V4_A

2/47


Rev. : APage : 2/47



1.1.2 Maintenance PlanningAdvance planning for maintenance is a necessity for utility, base-load industrial andcogeneration plants where downtime must be kept to a minimum. Also the correct controlof planned maintenance and inspection provides direct benefits in reduced forcedoutages and start failures, which in turn reduces unscheduled repair downtime. Theprimary factors, which affect the maintenance planning process, are shown in Figure 1-1and the owner's operating mode will determine how each factor is weighted.

Parts unique to the gas turbine requiring the most careful attention are those associatedwith the combustion process together with those exposed to high temperatures from thehot gases discharged from the combustion system. They are called the hot gas path partsand include combustion liners, end caps, fuel nozzle assemblies, cross fire tubes,transition pieces, turbine nozzles, turbine stationary shrouds, and turbine buckets.

The basic design and recommended maintenance of heavy-duty gas turbines of GEEnergy Products Europe are oriented toward:

- Maximum periods of operation between inspection and overhauls

- In-place, on-site inspection and maintenance

- Use of local trade skills to disassemble, inspect and reassemble

In addition to maintenance of the basic gas turbine, the control devices, fuel meteringequipment, gas turbine auxiliaries, load package, and other station auxiliaries also requireperiodic servicing.

Figure 1-1: Key factors affecting maintenance planning

It is apparent from the breakdown of scheduled outages and forced outages (Figure 1-2) that theprimary maintenance effort is attributed to five basic systems: controls and accessories,combustion, turbine, generator and balance-of-plant. The unavailability of controls and accessories

8/4/2019 9E_GT_M_M01_C01_V4_A

3/47


Rev. : APage : 3/47



is generally composed of numerous short-duration outages, whereas conversely the other four systems are composed of far fewer, but usually longer-duration outages.

Unit in typical peakload duty Unit in typical continuous baseloadduty

1 2 3 4 5 6 7

Balance of Plant

Generator

Control & Accessories

Combustion

Turbine

Unavailability %

1 2 3

Control & Accessories

Combustion

Turbine

Balance of Plant

Generator

Unavailability %

Forced Outage Scheduled Outaged

Figure 1-2: Plant level-top 5 systems contribution to downtime

The inspection and repair requirements outlined in the Maintenance and Instructions Manualprovided to each owner, lend themselves to establishing a pattern of inspections. In addition,supplementary information is provided through a system of Service Info's. This updating of information, contained in the Maintenance and Instructions Manual, assures optimum installation,operation and maintenance of the turbine. Many of the Service Info's contain advice to improve theoperation, maintenance, safety, reliability or availability of the turbine. The recommendationscontained in Service Info's should be followed and factored into the overall maintenance-planningprogram.

8/4/2019 9E_GT_M_M01_C01_V4_A

4/47


Rev. : APage : 4/47



1.1.3 Gas Turbine Design Maintenance FeaturesThe heavy-duty gas turbine of GE Energy Products Europe is designed to withstandsevere duty and to be maintained on-site, with off-site repair required only on certaincombustion components, hot gas path parts and rotor assemblies needing hot gas pathparts and rotor assemblies needing specialized shop service. The following features aredesigned into heavy-duty gas turbines of GE Energy Products Europe to facilitate on-sitemaintenance:

- All casings, shells and frames are split on machine horizontal centerline. Upper halves may be lifted individually for access to internal parts.

- With upper-half compressor casings removed, all stator vanes can be slid

circumferentially out of the casings for inspection or replacement without rotor removal.

- With upper-half of the turbine shell lifted, each half of the first-stage nozzle assemblycan be removed for inspection, repair or replacement without rotor removal. On someunits, upper half, later-stage nozzle assemblies are lifted with the turbine shell, alsoallowing inspection and/or removal of the turbine buckets.

- All turbine buckets are moment weighed and computer charted in sets for rotor spoolassembly so that they may be replaced without the need to remove or rebalance therotor assembly.

- All bearing housings and liners are split on the horizontal centerline so that they may be

inspected and replaced, when necessary. The lower half of the bearing liner can beremoved without removing the rotor.

- All seals and shaft packings are separate from the main bearing housings and casingstructures and may be readily removed and replaced.

- Fuel nozzles, combustion liners and flow sleeves can be removed for inspection,maintenance or replacement without lifting any casings or removing combustioncans.

Inspection aid provisions have been built into heavy-duty gas turbines of GE EnergyProducts Europe to facilitate conducting several special inspection procedures. Thesespecial procedures provide for the visual inspection and clearance measurement of someof the critical internal turbine gas-path components without removal of the gas turbineouter casings and shells. These procedures include gas-path bore scope inspection andturbine nozzle axial clearance measurement.

8/4/2019 9E_GT_M_M01_C01_V4_A

5/47


Rev. : APage : 5/47



1.1.4 Bore scope InspectionsHeavy-duty gas turbines of GE Energy Products Europe incorporate provisions in bothcompressor casings and turbine shells for gas path visual inspection of intermediatecompressor rotor stages, first-, second- and third-stage turbine buckets and partly theturbine nozzle partitions by means of the optical bore scope. These provisions, consistingof radially aligned holes through the compressor casings, turbine shell and internalstationary turbine shrouds, are designed to allow the penetration of an optical bore scopeinto the compressor or turbine flow-path area. An effective bore scope inspection programcan result in removing casings and shells from a turbine unit only when it is necessary torepair or replace parts.

GE Energy Products Europe recommend to perform a planned bore scope inspectiontogether with a combustion inspection.

It should be recognized that these bore scope inspection intervals are based on averageunit operating modes. Adjustment of these bore scope intervals may be made based onoperating experience and the individual unit mode of operation, the fuels used and theresult of previous bore scope inspections.

The application of a monitoring program utilizing a bore scope will allow schedulingoutages and pre-planning of parts requirements, resulting in lower maintenance costs andhigher availability and reliability of the gas turbine.

8/4/2019 9E_GT_M_M01_C01_V4_A

6/47


Rev. : APage : 6/47



1.1.5 Major Factors Influencing Maintenance and Equipment There are many factors that can influence equipment life and these must be understoodand accounted for in the owner's maintenance planning. Starting cycle, power setting, fueland level of steam or water injection are key factors in determining the maintenanceinterval requirements as these factors directly influence the life of critical gas turbineparts.

- Fuel

- Firing Temperature

- Steam / Water Injection

- Cyclic EffectsIn the approach of GE Energy Products Europe to maintenance planning, a gas fuel,base load application, with no water or steam injection, is established as the baselinecondition, which sets the maximum recommended maintenance intervals. For operationthat differs from the baseline, maintenance factors are established that determine theincreased level of maintenance that is required. For example, a maintenance factor of twowould indicate a maintenance interval that is half of the baseline interval.

a) Starts and Hours Criteria

Gas turbines wear out in different ways for different service duties. Thermal mechanicalfatigue is the dominant limiter of life for peaking machines, while creep, oxidation, andcorrosion are the dominant limiters of life for continuous duty machines. Interactions of these mechanisms are considered in the design criteria of GE Energy Products Europe,but to a great extent are second order effects. For that reason, gas turbines of GE EnergyProducts Europe maintenance requirements are based on independent counts of startsand hours. Whichever criterion limit is first reached determines the maintenance intervals.

Potential failure modes - hot gas path components

Continuous Duty Cyclic Duty

- Rupture- - Thermal Mechanical Fatigue

- Creep Deflection - High-Cycle Fatigue

- High-Cycle Fatigue - Rubs / Wear

- Corrosion - Foreign Object Damage

- Oxidation

- Erosion

- Rubs / Wear

- Foreign Object Damage

A graphical display of the GE Energy Products Europe approach is shown in Figure 1-3.In this figure, the inspection interval recommendation is defined by the rectangle

8/4/2019 9E_GT_M_M01_C01_V4_A

7/47


Rev. : APage : 7/47



established by the starts and hours criteria. These recommendations for inspection fallwithin the design life expectations and are selected such that components verified to beacceptable for continued use at the inspection point would have low risk of failure duringthe subsequent operating interval.

Fatigue Limits Life

L i f e T i m e

L i m i t b y

C o r r o s i o n ,

O x i

d a

t i o n a n

d C r e e p

A

A

B

B

E

DC

F

Hours

S t a r t s

A = Inspection RecommendationB = Design LifeC = Peak Load Operation

D = Mid - Range OperationE = Base LoadF = Equivalent Hours Per

Start Acc. EOH - Method

Figure 1-3: Maintenance requirements on independent counts of starts and hours

An alternative to the GE Energy Products Europe approach, which is sometimesemployed by other manufacturers, converts each start cycle to an equivalent number of operating hours (EOH) with inspection intervals based on the equivalent hours count. For the reasons stated above, GE Energy Products Europe does not agree with thisapproach. This logic can create the impression of longer intervals; while in reality morefrequent maintenance inspections are required. Referring again to Figure 1-3, the startsand hours inspection "rectangle" is reduced in half as defined by the diagonal line fromthe starts limit at the upper left hand corner to the hours limit at the lower right handcorner. Midrange duty applications, with starts per hour ratios of 30-50, are particularlypenalized by this approach.

8/4/2019 9E_GT_M_M01_C01_V4_A

8/47


Rev. : APage : 8/47



GE - Method

B = GE, after 2,4 Years

C = G E, after 3 Years

Figure1- 4: Hot gas path maintenance interval comparisons

This is further illustrated in Figure 1-4 for the example the unit is operating on gas fuel, atbase load conditions with no steam or water injection or trips from load. The unit operates4000 hours and 300 starts per year. Following recommendations of GE Energy ProductsEurope, the operator would perform the hot gas path inspection after four years of operation, with starts being the limiting condition. Performing maintenance on this sameunit based on equivalent hours criteria would require a hot gas path inspection after 2.4years. Similarly, for a continuous duty application operating 8000 hours and 160 starts per year, the GE Energy Products Europe recommendation would be to perform the hot gaspath inspection after three years of operation with the operating hours being the limitingcondition for this case. The equivalent hours criteria would set the hot gas path inspectionafter 2.1 years of operation for this application.

8/4/2019 9E_GT_M_M01_C01_V4_A

9/47


Rev. : APage : 9/47



b) Service Factors

While GE Energy Products Europe does not subscribe to the equivalency of starts tohours ( EOH-Method ), there are equivalencies within a wear out mechanism that must beconsidered. As shown in Figure 1-5, influences such as fuel type and quality, firingtemperature setting, and the amount of steam or water injection are considered withregard to the hours-based criteria. Start-up rate and the number of trips are consideredwith regard to the starts-based criteria. In both cases, these influences may act to reducethe maintenance intervals. When these service or maintenance factors are involved in aunit's operating profile, the hot gas path maintenance "rectangle" that describes thespecific maintenance criteria for this operation is reduced from the ideal case, asillustrated in Figure 1-6. The following discussion will take a closer look at the keyoperating factors and how they can impact maintenance intervals as well as hot gas pathparts refurbishment / replacement intervals.

8/4/2019 9E_GT_M_M01_C01_V4_A

10/47


Rev. : APage : 10/47



Typical Max Inspection Intervals (MS6B / MS7EA)

Hot Gas Path Inspection 24,000 hrs or 1200 starts

Major Inspection 48,000 hrs or 2400 starts

Criterion is Hours or Starts (Whichever Occurs First)

Factors Impacting Maintenance

Hours Factors

Fuel Gas 1

Distillate 1.5

Crude 2 to 3

Residual 3 to 4

Peak Load 6f (T F )

Water / Steam Injection

Dry Control 1 (GTD-222)

Wet Control 1.9 (5% H 2O)

Starts Factors

Trip from Full Load 8

Fast Load 2

Emergency Start 20

Figure 1-5: Maintenance factors for turbine buckets and -nozzles

0

200

400

600

800

1000

1200

0 4 8 12 16 20 24

B

A

Hours ( x 1000)

S T A R T S

Table A:Starts - FactorsTrips

Fast Starts

Table B:Hours - FactorsFiring TemperatureFuel TypeSteam - Water Injection

Figure 1-6: Typical Maintenance interval for hot gas path inspections

8/4/2019 9E_GT_M_M01_C01_V4_A

11/47





c) FuelFuels burned in gas turbines range from clean natural gas to residual oils and impactmaintenance, as illustrated in Figure 1-7. Heavier hydrocarbon fuels have a maintenancefactor ranging from three to four for residual fuel and two to three for crude oil fuels.These fuels generally release a higher amount of radiant thermal energy, which results ina subsequent reduction in combustion hardware life, and frequently contain corrosiveelements such as sodium, potassium, vanadium and lead that can lead to accelerated hotcorrosion of turbine nozzles and buckets. In addition, some elements in these fuels cancause deposits either directly or through compounds formed with inhibitors that are usedto prevent corrosion. These deposits impact performance and can lead to a need for more frequent maintenance.

Distillates, as refined, do not generally contain high levels of these corrosive elements,but harmful contaminants can be present in these fuels when delivered to the site. Twocommon ways of contaminating number two distillate fuel oil are: salt water ballast mixingwith the cargo during sea transport, and contamination of the distillate fuel whentransported to site in tankers, tank trucks or pipelines that were previously used totransport contaminated fuel, chemicals or leaded gasoline. From Figure 1-7, it can beseen that the experience of GE Energy Products Europe with distillate fuels indicates thatthe hot gas path maintenance factor can range from as low as one (equivalent to naturalgas) to as high as three. Unless operating experience suggests otherwise, it isrecommended that a hot gas path maintenance factor of 1.5 be used for operation ondistillate oil. Note also that contaminants in liquid fuels can affect the life of gas turbineauxiliary components such as fuel pumps and flow dividers.

As shown in Figure 1-7, gas fuels, which meet GE Energy Products Europespecifications, are considered the optimum fuel with regard to turbine maintenance andare assigned no negative impact. However, if condensed liquid hydrocarbons are presentin gas fuel and are allowed to carry over into the gas turbine fuel system, a reduction of hot gas path component life will result. While hydrocarbon carry-over in very smallconcentrations can be tolerated, the presence of liquid hydrocarbon mist suggests thepossibility of bulk carry over. In the extreme case, liquid hydrocarbon can reduce the hotgas path parts lives or repair intervals. Owners can control this potential problem by usingeffective gas scrubber systems and by superheating the gaseous fuel prior to use toprovide a nominal 28 K of superheat at the turbine gas control valve connection.

8/4/2019 9E_GT_M_M01_C01_V4_A

12/47





7 8 9 10 11 12 13 14 15 20

1

2

3

4

M a i n

t e n a n c e

F a c

t o r

Residual Leight Heavy Natural Gas

Fuel Percent Hydrogen by weight in Fuel

Destillates

Figure 1-7: Estimated effect of fuel type on maintenance

The prevention of hot corrosion of the turbine buckets and nozzles is mainly under thecontrol of the owner. Undetected and untreated, a single shipment of contaminated fuelcan cause substantial damage to the gas turbine hot gas path components. Potentiallyhigh maintenance costs and loss of availability can be minimized or eliminated by:

- Placing a proper fuel specification on the fuel supplier. For liquid fuels, each shipmentshould include a report that identifies specific gravity, flash point, viscosity, sulfur content, pour point and ash content of the fuel.

- Providing a regular fuel quality sampling and analysis program. As part of thisprogram, on-line water in fuel oil monitor is recommended, as is a portable fuelanalyzer that, as a minimum, reads vanadium, lead, sodium, potassium, calcium andmagnesium.

- Providing proper maintenance of the fuel treatment system when burning gas, heavier fuel oils and by providing cleanup equipment for distillate fuels when there is apotential for contamination.

In addition to their presence in the fuel, contaminants can also enter the turbine via theinlet air and from the steam or water injected for NOx emission control or power augmentation. In some cases, these sources of contaminants have been found to causehot gas path degradation equal to that seen with fuel-related contaminants. GE EnergyProducts Europe specifications define limits for maximum concentrations of contaminants

8/4/2019 9E_GT_M_M01_C01_V4_A

13/47





for fuel, air and steam/water. Limits from all sources are one ppm sodium plus potassium,one ppm lead, 0,5 ppm vanadium and two ppm calcium on a referred to fuel basis.

d) Firing Temperature

Significant operation at peak load, because of the higher operating temperatures, willrequire more frequent maintenance and replacement of hot gas path components. For each hour of operation at peak load-firing temperature (56 C ) is the same, from a bucketparts life standpoint, as six hours of operation at base load. This type of operation willresult in a maintenance factor of six. Figure 1-8 defines the parts life effect correspondingto changes in firing temperature for the MS6001B and MS9001E.

It should be noted that this is not a linear relationship, as a 111 C increase in firingtemperature would have an equivalency of six times six, or close to 36:1.

Higher firing temperature reduces hot gas path parts lives while lower firing temperatureincreases parts lives. This provides an opportunity to balance the negative effects of peakload operation by periods of operation at part load. However, it is important to recognizethat the non-linear behavior described above will not result in a one for one balance for equal magnitudes of over and under firing operation. Rather, it would take six hours of operation at 56 C under base conditions to compensate for one-hour operation at 56 Cover base load conditions.

Peak Rating+ 56CLife factor 6

Figure 1-8: Bucket life firing temperature effect MS6001B/MS9001E

8/4/2019 9E_GT_M_M01_C01_V4_A

14/47





It is also important to recognize that a reduction in load does not always mean a reductionin firing temperature. In heat recovery applications, where steam generation drives overallplant efficiency, load is first reduced by closing variable inlet guide vanes to reduce inletairflow while maintaining maximum exhaust temperature. For these applications, firingtemperature does not decrease until load is reduced below approximately 80% of ratedoutput. Conversely, a turbine running in simple-cycle mode maintains full open inlet guidevanes during a load reduction to 80% and will experience over a 111 C reduction in firingtemperature at this output level.

The hot gas path parts life effects for these different modes of operation are obviouslyquite different. This turbine control effect is illustrated in Figure 1-9.

Firing temperature effects on hot gas path maintenance, as described above, relate toclean burning fuels, such as natural gas and light distillates, where creep rupture of hotgas path components is the primary life limiter and is the mechanism that determines thehot gas path maintenance interval impact.

With ash-bearing heavy fuels, corrosion and deposits are the primary influence and adifferent relationship with firing temperature exists. Figure 1-10 illustrates the sensitivity of hot gas path maintenance factor to firing temperature for a heavy fuel operation. It can beseen that while the sensitivity to firing temperature is less, the maintenance factor itself ishigher due to issues relating to the corrosive elements contained in these fuels.

8/4/2019 9E_GT_M_M01_C01_V4_A

15/47





20 40 60 80 100 120

Load in %

F i r i n g T e m p e r a t u r e

600

800

1000

1200

CMS6001B / MS9001E

A

C

B

D

5 7 I G V

8 4 I G V

Figure 1-9: Firing temperature and load relationship - heat recovery vs. Simple cycle operation

TABLEHeat RecoverySimple Cycle

A = Peak Load

B = Base LoadC = Variable Inlet Guide Vanes (IGV's) closing from 84 to 57,

T constant 1104 CD = Variable Inlet Guide Vanes closing from 84 to 57, T constant 371 C

Hot gas path parts life benefit at reduced load is less in the heat recovery mode.

8/4/2019 9E_GT_M_M01_C01_V4_A

16/47





1

5

10

100

M a

i n t e n a n c e

f a c t o r

KelvinFiring Temperature

200 100 0

R e s i d

C R U D E

MS6001B / MS9001E

Max. Heavy Fuel FiringTemperature

Figure 1-10: Heavy fuel maintenance factors

e) Steam / Water Injection

Water (or steam) injection for emissions control or power augmentation can impact hotgas path parts lives and maintenance intervals even when the water or steam qualitymeets specifications of GE Energy Products Europe. This relates to the effect of theadded water on the hot-gas transport properties. Higher gas conductivity, in particular,increases the heat transfer to the buckets and nozzles and can lead to higher metaltemperature and reduced parts lives.

Steam- / water injection increases metal temperature of hot gas path components

1. Steam- / water injection affects gas transport properties:Thermal conductivity ( k ) increaseSpecific heat ( c p ) increaseViscosity ( ) constant

2. This increases heat transfer coefficients:

3. Which increases metal temperature and decreases bucket life

Example (Stage 1 bucket, for constant firing temperature)

3 % Steam (25 ppm NO x )

h = + 4 % ( heat transfer coefficient )

TMetal = + 8 C

Life = minus 33 %

A hot gas path part life impact from steam or water injection is related to the way theturbine is controlled. The control system on most base load applications reduces firingtemperature as water is injected. This counters the effect to the higher heat transfer on

the gas side and results in no impact on bucket life. On some installations, however, thecontrol system is designed to maintain firing temperature constant with water injection

8/4/2019 9E_GT_M_M01_C01_V4_A

17/47





level. This results in additional unit output but it decreases parts life as previouslydescribed. Units controlled in this way are generally in peaking applications where annualoperating hours are low or where operators have determined that reduced parts lives are

justified by the power advantage. GE Energy Products Europe describes these twomodes of operation as dry control curve operation and wet control curve operation,respectively. Figure 1-11 illustrates the wet and dry control curve and the performancedifferences that result from these two different modes of control.

An additional factor associated with water or steam injection relates to higher aerodynamic loading on the turbine components that results from the injected water increasing the cycle pressure ratio. This additional loading increases the downstreamdeflection rate of the second- and third-stage nozzles, which reduces the repair intervalfor these components. However, the introduction of GTD-222, a new high creep strengthstage two and three nozzle alloy, will minimize or eliminate this factor.

Maintenance factors relating to water injection for units operating on dry control, rangefrom one, for units equipped with GTD-222 second- and third-stage nozzles, to a factor of 1.5 for units equipped with FSX 414 nozzles and injecting 5% water. For wet control curveoperation, the maintenance factor is approximately two at 5% water injection.

BA

CD

Compr. Discharge Pressure

E x h a u s t

T e m p e r a

t u r e

LEGENDE

A= Dry ControlB= Wet Control

(TF constant)C= 3% Steam InjectionT

F1104 C

110% LoadD= 0% Steam Injection

TF

1104 C(100% Load)

E=3% Steam InjectionT

F1090 C

106% Last

E

Figure 1-11: Exhaust temperature control curve - dry vs. wet control

8/4/2019 9E_GT_M_M01_C01_V4_A

18/47





f) Cyclic Effects

In the foregoing paragraphs, operating factors that impact the hours-based maintenancecriteria were described. For the starts-based maintenance criteria, operating factorsassociated with the cyclic effects produced during start-up, operation and shutdown of theturbine must also be considered. Operating conditions other than the standard start-upand shutdown sequence can potentially reduce the cyclic life of the hot gas pathcomponents and will require more frequent maintenance and parts refurbishment and/or replacement.

Figure 1-12 illustrates the firing temperature changes occurring over a normal start-up

and shutdown cycle. Ignition, acceleration, loading, unloading and shutdown all producegas temperature changes that produce corresponding metal temperature changes. For rapid changes in gas temperature, the edges of the bucket or nozzle respond morequickly than the thicker bulk section, as pictured in Figure 1-13. These gradients producethermal stresses that can eventually lead to cracking. Figure 1-14 describes thetemperature strain history of a stage 1 bucket during a normal start-up and shutdowncycle. Ignition and acceleration produce transient compressive strains in the bucket as thefast responding leading edge heats up more quickly than the thicker bulk section of theairfoil.

T e m p e r a

t u r

A

BD

C

E

F

G

H

IJ

Startup ShutdownTime

A = IgnitionB = Warm - upC = AccelerationD = Full Speed no LoadE = Load RampF = Base LoadG = Unload RampH = Full Speed no LoadI = Fired ShutdownJ = Trip

Figure 1-12: Turbine start / stop cycle - firing temperature changes

At full load conditions, the bucket reaches its maximum metal temperature and acompressive strain produced from the normal steady static temperature gradients thatexist in the cooled part. At shutdown, the conditions reverse where the faster respondingedges cool more quickly than the bulk section, which results in a tensile strain at the

edges.

8/4/2019 9E_GT_M_M01_C01_V4_A

19/47





COLD

Figure 1-13: First-stage bucket transient temperature distribution

Thermal mechanical fatigue testing has found that the number of cycles that a part canwithstand before cracking occurs is strongly influenced by the total strain range and themaximum metal temperature experienced. Any operating condition that significantlyincreases the strain range and/or the maximum metal temperature over the normal cycleconditions will act to reduce the fatigue life and increase the starts-based maintenancefactor.

0

D

TMAX

CE

B

c

A

Table

A = Ignition and Warm UpB = AccelerationC = Full Speed no LoadD = Base LoadE = Fired Shutdown

Figure 1-14: Bucket low cycle fatigue (LCF)

8/4/2019 9E_GT_M_M01_C01_V4_A

20/47





For example, Figure 1-15 compares a normal operating cycle with one that includes a tripfrom full load. The significant increase in the strain range for a trip cycle results in a lifeeffect that equates to eight normal start/stop cycles, as shown. Trips from part load willhave a reduced impact because of the lower metal temperatures at the initiation of the tripevent. Figure 1-16 illustrates that while a trip from loads greater than 80% has an 8:1maintenance factor, a trip from full speed no load would have a maintenance factor of 2:1.

Similar to trips from load, emergency starts and fast loading will impact the starts-basedmaintenance interval. This again relates to the increased strain range that is associatedwith these events. Emergency starts where units are brought from standstill to full load inless than five minutes will have a parts life effect equal to 20 normal start cycles and anormal start with fast loading will produce a maintenance factor of two.

TMAX

MAX

Temperature S t r a

i n i n %

+

_

TMAX

MAX

Temperature S t r a

i n i n %

+

_

Figure 1-15: Low cycle fatigue life sensitivities - first-stage bucket

8/4/2019 9E_GT_M_M01_C01_V4_A

21/47





0

2

4

6

8

10

0 20 40 60 80 100 120Load in %

T r i p

S e v e r i

t y F a c

t o r

BaseLoad

100% Full Speed no Load

Note:For Trips during Start upAccel Assume TripSeverity Factor = 2

Figure 1-16: Maintenance factor - trips from load (MS6001B/MS9001E)

For Trips During Start-up Accel Assume Trip Severity Factor = 2

While the factors described above will decrease the starts-based maintenance interval,part load operating cycles would allow for an extension of the maintenance interval asshown in figure 17. For example, an operating cycle to maximum load levels of 60%would have a maintenance factor of 0.5.

8/4/2019 9E_GT_M_M01_C01_V4_A

22/47





0

0,2

0,4

0,6

0,8

0 20 40 60 80 100Load in %

M a i n

t e n a n c e

F a c t o r

1,0

1,2

1,4

Figure 1-17: Maintenance factor - effect start cycle maximum load level (MS6001B/MS9001E)

8/4/2019 9E_GT_M_M01_C01_V4_A

23/47





g) Air Quality

Maintenance and operating costs are also influenced by the quality of the air that theturbine consumes. In addition to the deleterious effects of airborne contaminants on hotgas path components, contaminants such as dust, salt and oil can also cause compressor blade erosion and fouling. Twenty-micron particles entering the compressor can causesignificant blade erosion. Fouling can be caused by submicron dirt particles entering thecompressor as well as from ingestion of oil vapor, smoke, sea salt and industrial vapors.Corrosion of compressor blading causes pitting of the blade surface, which, in addition toincreasing the surface roughness, also serves as potential sites for fatigue crack initiation.These surface roughness and blade contour changes will decrease compressor airflowand efficiency, which in turn reduces the gas turbine output and overall thermal efficiency.Generally, axial-flow compressor deterioration can be the major cause of loss in gasturbine output and efficiency. Recoverable losses, attributable to compressor bladefouling, typically account for 70 to 85% of the performance losses seen. As Figure 1-18illustrates, compressor fouling to the extent that airflow is reduced by 5%, will reduceoutput by 13% and increase heat rate by 5.5%. Fortunately, much can be done throughproper operation and maintenance procedures to minimize fouling-type losses. On-linecompressor wash systems are available that are used to maintain compressor efficiencyby washing the compressor up to 95 % base load ( or less) , before significant fouling hasoccurred.

Off-line systems are used to clean heavily fouled compressors. Off-line cleaning can bedone only if the unit is shutdown and cool. Washing should be done at a compressor speed of 300- (MS9001E) or 600 rpm. Due to the method the Off-line cleaning systemhas been found to be the most effective procedure. A combination of a daily carried outOn-line compressor washing and a cyclic Off-line washing is the preferred method.

Other procedures include maintaining the inlet filtration system and inlet evaporativecoolers as well as periodic inspection and prompt repair or change of compressor blading.

There are also non-recoverable losses. In the compressor, these are typically caused bynon-deposit-related blade surface roughness, erosion and blade tip rubs. In the turbine,nozzle throat area changes, bucket tip clearance increases and inner leakages arepotential causes. Some degree of unrecoverable performance degradation should be

expected, even on a well-maintained gas turbine. The owner, by regularly monitoring andrecording unit performance parameters, has a very valuable tool for diagnosing possiblecompressor deterioration.

8/4/2019 9E_GT_M_M01_C01_V4_A

24/47





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

-14

-12

-10

-8

-6

-4

-2

0

2

4

6

8

F o u l i n g

F o u l i n g

Heat Rate Inreasein %

Output Decreasein %

5 % Loss of Airflow

Pressure Ratio Decrease in %

Figure 1-18: Deterioration of gas turbine performance due to compressor blade fouling

h) Load versus Exhaust Temperature

The general relationship between load and exhaust temperature should be observed andcompared to previous data. Ambient temperature and barometric pressure will have someeffect upon the absolute temperature level. High exhaust temperature can be an indicator of deterioration of internal parts, excessive leaks or a fouled air compressor. For mechanical drive applications, it may also be an indication of increased power required bythe driven equipment.

i) Vibration Level

The vibration signature of the unit should be observed and recorded. Minor changes willoccur with changes in operating conditions. However, large changes or a continuouslyincreasing trend give indications of the need to apply corrective action.

j) Fuel Flow and Pressure

The fuel system should be observed for the general fuel flow versus load relationship.Fuel pressures through the system should be observed. Changes in fuel pressure canindicate the fuel nozzle passages are plugged, or that fuel metering elements aredamaged our out of calibration.

8/4/2019 9E_GT_M_M01_C01_V4_A

25/47





k) Exhaust Temperature and Spread VariationThe most important control function to be observed is the exhaust temperature fueloverride system and the back up over temperature trip system. Routine verification of theoperation and calibration of these functions will minimize wear on the hot gas path parts.

The variations in turbine exhaust temperature spread should be measured and monitoredon a regular basis. Large changes or a continuously increasing trend in exhausttemperature spread indicate combustion system deterioration or fuel distributionproblems. If the problem is not corrected, the life of downstream hot gas path parts will bereduced.

l) Start-Up Time

Start-up time is an excellent reference against which subsequent operating parameterscan be compared and evaluated. A curve of the starting parameters of speed, fuel signal,exhaust temperature and critical sequence bench marks versus time from the initial startsignal will provide a good indication of the condition of the control system. Deviations fromnormal conditions help pinpoint impending trouble, changes in calibration or damagedcomponents.

m) Coast-Down Time

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

Close observation and monitoring of these operating parameters will serve as the basisfor effectively planning maintenance work and material requirements needed for subsequent shutdown periods.

8/4/2019 9E_GT_M_M01_C01_V4_A

26/47





1.1.6 Inspection And MaintenanceInspection and maintenance types may be broadly classified as stand-by, running anddisassembly inspections. The stand-by inspection is performed during off-peak periodswhen the unit is not operating and includes routine servicing of accessory systems anddevice calibration. The running inspection is performed by observing key operatingparameters while the turbine is running. The disassembly inspection requires opening theturbine for inspection of internal components and is performed in varying degrees.Disassembly inspections progress from the combustion inspection to the hot gas pathinspection to the major inspection. Details of each of these inspections are describedbelow.

1. a) Stand-By Inspections

Stand-by inspections are performed on all gas turbines but pertain particularly to gasturbines used in peaking and intermittent-duty services where starting reliability is of primary concern. This inspection includes routinely servicing the battery system, changingfilters, checking oil and water levels, cleaning relays and checking device calibrations.Servicing can be performed in off-peak periods without interrupting the availability of theturbine. A periodic start-up test run is an essential part of the stand-by inspection.

Among the most useful drawings in the Service Manual Instruction Books for stand-bymaintenance is the control specification and piping schematic to perform these periodicchecks. These drawings provide the calibration operating limits, operating characteristicsand sequencing of all control devices. This information should be used regularly byoperating and maintenance personnel. Careful adherence to minor stand-by inspectionmaintenance can have a significant effect on reducing overall maintenance costs andmaintaining high turbine reliability. It is essential that a good record be kept of allinspections made and of the maintenance work performed in order to ensure establishinga sound maintenance program.

b) Running Inspections

Running inspections consist of the general and continued observations made while a unitis operating. This starts by establishing baseline-operating data during initial start-up of anew unit and after any major disassembly work. This baseline then serves as a referencefrom which subsequent unit deterioration can be measured.

Data should be taken to establish normal equipment start-up parameters as well as keysteady-state operating parameters. Steady state is defined as conditions at which nomore than a 3 K change in wheel space temperature occurs over a 15-minute time period.

Data must be taken at regular intervals and should be recorded to permit an evaluation of the turbine performance and maintenance requirements as a function of operating time.This operating inspection data, summarized in Figure 1-19, includes: load versus exhausttemperature, vibration, fuel flow and pressure, lube oil pressure, exhaust temperatures,spread variation and start-up time. This list is only a minimum and other parametersshould be used as necessary. A graph of these parameters will help provide a basis for

8/4/2019 9E_GT_M_M01_C01_V4_A

27/47





judging the conditions of the system. Deviations from the norm help pinpoint impendingtrouble, changes in calibration or damaged components.

SPEED PRESSURES

LOAD - COMPRESSOR DISCHARGE

FIRED STARTS - LUBE PUMP(S)

FIRED HOURS - BEARING HEADER

SITE BAROMETRIC READING - COOLING WATER

TEMPERATURES - FUEL- INLET AMBIENT - FILTERS (FUEL, LUBE, INLET AIR)

COMPRESSOR DISCHARGE GENERATOR

- TURBINE EXHAUST - OUTPUT VOLTAGE - FIELD VOLTAGE

- TURBINE WHEELSPACE - PHASE CURRENT - FIELD CURRENT

- LUBE OIL HEADER - VARS - STATOR TEMP.

- LUBE OIL TANK - LOAD - VIBRATION

- BEARING DRAINS

- EXHAUST SPREAD VIBRATION DATA FOR POWER TRAINSTART UP TIME

COAST-DOWN TIME

Figure 1-19: Operating inspection data parameters

c) Combustion Inspection

The combustion inspection is a relatively short disassembly shutdown inspection of fuelnozzles, liners, transition pieces, crossfire tubes and retainers, spark plug assemblies,

flame detectors and combustor flow sleeves. This inspection concentrates on thecombustion liners, transition pieces and fuel nozzles, which are recognized as being thefirst to require replacement and repair in a good maintenance program. Proper inspection,maintenance and repair (Figure 1-20) of these items will contribute to a longer life of thedownstream parts, such as turbine nozzles and buckets.

Figure 1-24 illustrates the section of a unit that is disassembled for a combustioninspection. The combustion liners, transition pieces and fuel nozzles should be removedand replaced with new or repaired components to minimize downtime. The removedliners, transition pieces and fuel nozzles can then be cleaned and repaired after the unit isreturned to operation and be available for the next combustion inspection. Requirementsfor MS6001B/9001E machines are:

8/4/2019 9E_GT_M_M01_C01_V4_A

28/47





Key Hardware Inspect for Inspection / Actions:Combustion Liners

Combustion Covers

Fuel Nozzles

Transition Pieces

Cross fire Tubes

Flow Sleeves

Purge Valves

Check Valves

Flame DetectorsSpark Plugs

Flex Hoses

Foreign Objects

Abnormal Wear

Cracking

Liner Cooling Hole Plugging

TBC Coating Cond.

Oxidation/Corrosion/Erosion

Hot Spots / Burning

Missing Hardware

Clearance LimitsBore scope Compressor and

Turbine

Tightness

Repair / Refurbishment

Liners

Cracking / Erosion / Wear

TBC Repair

Transition Pieces

Wear

TBC Repair

Distortion

Fuel NozzlesPlugging

Wear / Erosion

Flow Test

Cross Fire Tubes

Wear / Burning

Pressure Test (Flex Hoses)

Availability of On Site Spares is the Key to Minimizing DowntimeFigure 1-20: Combustion inspection - key elements

8/4/2019 9E_GT_M_M01_C01_V4_A

29/47





Inspect and identify combustion chamber components. Inspect and identify each crossfire tube retainer and combustion liner.

Inspect combustion chamber interior for foreign objects.

Inspect flow sleeve welds for cracking.

Inspect transition piece for wear and cracks.

Inspect fuel nozzles for plugging, erosion and safety lock of tips.

Inspect all fluid, air, and gas passages in nozzle assembly for plugging, erosion,burning, etc.

Inspect spark plug assembly for freedom from binding; check condition of insulators,electrodes and clearance.

Replace all consumable and normal wear- and -tear items such as seals, lock plates,nuts, bolts, gaskets, etc.

Enter the combustion wrapper and observe the condition of blading in the aft end of axial-flow compressor with a bore scope.

Perform visual inspection of first stage turbine nozzle partitions and bore scopeinspection of following turbine buckets and turbine nozzle stages to mark the progressof wear and deterioration of these parts. This inspection will help establish theschedule for the hot gas path inspection.

Visually inspect the compressor inlet and turbine exhaust areas, checking condition of IGV's, IGV bushings, last-stage buckets and exhaust system components.

Verify proper operation of purge and check valves. Confirm proper setting andcalibration of the combustion controls.

After the combustion inspection is complete and the unit is returned to service, theremoved combustion liners and transition pieces can be bench-inspected and repaired, if necessary, by either competent on-site-personnel, or off-site at a qualified Service Center of GE Energy Products Europe. The removed fuel nozzles can be cleaned on-site andflow tested on-site, if suitable test facilities are available.

8/4/2019 9E_GT_M_M01_C01_V4_A

30/47





2. d) Hot gas path Inspection

The purpose of a hot gas path inspection is to examine those parts exposed to hightemperatures from the hot gases discharged from the combustion process. The hot gaspath inspection outlined in Figure 1-22 includes the full scope of the combustioninspection and, in addition, a detailed inspection of the turbine nozzles, stationary stator shrouds and turbine buckets. To perform this inspection, the top half of the turbine shellmust be removed. Prior to shell removal, proper machine centerline support usingmechanical jacks is necessary to assure proper alignment of rotor to stator, obtainaccurate half-shell clearances and prevent twisting of the stator casings. For inspection of the hot gas path (Figure 1-24), all parts as described for combustion inspection and thefirst-stage turbine nozzle assembly must be removed. Removal of the second- and third-stage turbine nozzle segment assemblies is optional, depending upon visual observationsand clearance measurement. The buckets can usually be inspected in place. Also it isusually worthwhile to fluorescent penetrate inspect (FPI) the bucket vane sections todetect any cracks. In addition a complete set of internal turbine radial and axialclearances (opening and closing) must be taken during any hot gas path inspection.

41 235

0.15 mm 0 .10 mm0.05 to 0.08 mm

Jacking S equence

Vertical Mov ement in mm

Figure 1-21: Stator tube jacking procedure

1. Position No. 5 is not required if compressor casing is a single piece casing.(no aft casing)

2. Position No. 1, 4 and if necessary 5 is required if a compressor casing must be removed during hot gas path inspection.

8/4/2019 9E_GT_M_M01_C01_V4_A

31/47





Typical hot gas path inspection requirements for MS 6001B/9001E machines are: Inspect and record condition of first-, second- and third-stage buckets. If it is

determined that the turbine buckets should be removed, follow bucket removal andcondition recording instructions. The first-stage bucket protective coating should beevaluated for remaining coating life.

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

Inspect and record condition of later-stage nozzle diaphragm packings. Check sealsfor rubs and deterioration of clearance.

Record the bucket tip clearances. Inspect bucket shank seals for clearance, rubs anddeterioration.

Check the turbine stationary shrouds for clearance, cracking, erosion, oxidation,rubbing and built-up.

Check and replace any faulty wheel space thermocouples.

Enter compressor inlet plenum and observe the condition of the forward section of thecompressor. Pay specific attention to Ivys looking for corrosion, bushing wear evidenced by excessive clearance and vane cracking.

Enter the combustion wrapper and, with a bore scope, observe the condition of theblading in the aft end of the axial-flow compressor.

Visually inspect the turbine exhaust area for any signs of cracking or deterioration.

Key Hardware Inspect for Inspection / Actions:

Nozzles (1, 2, 3)

Buckets (1, 2, 3)

Stator Shrouds

IGV's & Bushings

Compressor Blading

(Bore scope)

Foreign Object Damage

Oxidation / Corrosion /

Erosion

Cracking

Cooling Hole Plugging

Remaining Coating Life

Nozzle Deflection /Deterioration

Abnormal Deflection /

Deterioration

Abnormal Wear

Missing Hardware

Clearance Limits

Repair/Refurbishment/Replace

Nozzles

Weld Repair

Reposition

Recoat

Buckets

Strip & RecoatWeld Repair

Creep Life Limit

Top Shroud Deflection

Availability of On Site Spares is the Key to Minimizing Downtime

Figure 1-22: Hot gas path inspection - key elements

8/4/2019 9E_GT_M_M01_C01_V4_A

32/47





The first stage turbine nozzle assembly exposed to the direct hot-gas discharge from thecombustion process and is subjected to the highest gas temperatures in the turbinesection. Such conditions frequently cause nozzle cracking and oxidation and, in fact, thisis expected.

The second- and third stage nozzles are exposed to high gas bending loads which, incombination with operating temperatures, can lead to downstream deflection and closureof critical axial clearances. To a degree, nozzle distress can be tolerated and criteria havebeen established for determining when repair is required. These limits are contained inthe Maintenance and Instruction Books. However, as a general rule, first stage nozzleswill require repair at the hot path inspection. The second and third stage nozzles may alsorequire refurbishment to re-establish the proper axial clearances. Normally, turbinenozzles can be repaired several times to extend life and it is generally repair cost versusreplacement cost that dictates the replacement decision.

Coatings play a critical role in protecting the first stage buckets to ensure that the fullcapability of the high strength super alloy is maintained and that the bucket rupture lifemeets design expectations. This is particularly true of cooled bucket designs that operateabove 1085 C firing temperature. Significant exposure of the base metal to theenvironment will accelerate the creep rate and can lead to premature failure through acombination of increased temperature and stress and a reduction in material strength.

This degradation process is driven by oxidation of the unprotected base alloy. In the past,on early generation uncooled designs, surface degradation due to corrosion or oxidationwas considered to be a performance issue and not a factor in bucket life. This is no

longer the case at the higher firing temperatures of current generation designs.Given the importance of coatings, it must be recognized that even the best coatingsavailable will have a finite life and the condition of the coating will play a major role indetermining bucket replacement life.

At present GE Energy Products Europe is monitoring for example buckets for MS6001Bunits to determine whether to recommend stripping and recoating the buckets at 24,000hours, to possibly increase the replacement interval beyond the 48,000 hours.

Recoating is not considered an option for buckets with uncoated cooling holes andmultiple recoats are not an option because of limitations imposed by stripping field-serviced buckets. The economics of recoating buckets must look at the cost to recoatversus the cost to replace buckets at more frequent intervals. Economic evaluations of this trade-off suggest that recoating may make sense for the larger designs but less sofor the smaller frame sizes.

Visual and bore scope examination of the hot gas path parts during the combustioninspections as well as nozzle-deflection measurements will allow the operator to monitor distress patterns and progression. This makes part-life predictions more accurate andallows adequate time to plan for replacement or refurbishment at the time of the hot gaspath inspection. It is important to recognize that to avoid extending the hot gas pathinspection, the necessary spare parts should be on site prior to taking the unit out of service.

8/4/2019 9E_GT_M_M01_C01_V4_A

33/47





d) Major Inspection

The purpose of the major inspection is to examine all of the internal rotating andstationary components from the inlet of the machine through the exhaust section of themachine. A major inspection should be scheduled in accordance with therecommendations in the owner's Maintenance and Instructions Manual or as modified bythe results of previous bore scope and hot gas path inspection. The work scope shown inFigure 1-23 involves inspection of all of the major flange-to-flange components of the gasturbine, which are subject to wear during normal turbine operation. This inspectionincludes previous elements of the combustion and hot gas path inspections, in addition tolaying open the complete flange-to-flange gas turbine, to the horizontal joints, as shown inFigure 1-24, with inspections being performed on individual items. Depending on thecoating condition, first-stage bucket replacement may be necessary at the major inspection.

Prior to removing casings, shells and frames, the unit must be properly supported. Proper centerline support using mechanical jacks and jacking sequence procedures arenecessary to assure proper alignment of rotor to stator, obtain accurate half shellclearances and to prevent twisting of the casings while on the half shell.

Key Hardware Inspect for Inspection / Actions:

Compressor Blading

Turbine Wheels

Fir Tree Guide

Journal and

Seal Surfaces

Bearing, Seals

Inlet Systems

Exhaust Systems

Foreign Object Damage

Oxidation / Corrosion /

Erosion

Cracking

Leaks

Abnormal Wear

Missing Hardware

Clearance Limits

Repair / Refurbishment / Replace

Stator Shrouds

Cracking/Oxidation/Erosion

Buckets

Coating Deterioration

Rubs/Cracking

Tip Shroud Deflection

Creep Life Limit

Nozzles

Deterioration

IGV-Bushings Wear

Bearings/Seals

Compressor Blades

Availability of On Site Spares is the Key to Minimizing Downtime

Figure 1-23: Gas turbine major inspection - key elements

8/4/2019 9E_GT_M_M01_C01_V4_A

34/47





Figure 1-24: Inspection work scope

Typical major inspection requirements for MS6001B, MS9001E machines are:

All radial and axial clearances are checked against their original values (opening andclosing).

Casings, shells and frames/diffusers are inspected for cracks and erosion.Compressor inlet and compressor flow-path are inspected for fouling, erosion,corrosion and leakage. The IGVs are inspected, looking for corrosion, bushing wear and vane cracking.

Rotor and stator compressor blades are checked for tip clearance, rubs, impact

damage, corrosion pitting, bowing and cracking. Turbine stationary shrouds are checked for clearance, erosion, rubbing, cracking and

build-up. Seals and hook fits of turbine nozzles and diaphragms are inspected for rubs, erosion,

fretting or thermal deterioration. Turbine buckets are removed and a non-destructive check of buckets and wheel fir

tree guide is performed. Bearing liners and seals are inspected for clearance and wear.

_ Inlet systems are inspected for corrosion, cracked silencers and loose parts.Exhaust systems are inspected for cracks, broken silencer panels or insulation

panels.

8/4/2019 9E_GT_M_M01_C01_V4_A

35/47





Check alignment - gas turbine to load gear - generator to load gear - and gas turbine toaccessory gear.Comprehensive inspection and maintenance guidelines have been developed by GEEnergy Products Europe and are provided in the Maintenance and Instructions Manual toassist users in performing each of the inspections previously described.

8/4/2019 9E_GT_M_M01_C01_V4_A

36/47





1.1.7 Parts planningLack of adequate on-site spares can have a major effect on plant availability; therefore,prior to a scheduled disassembly type of inspection, adequate spares should be on site. Aplanned outage such as a combustion inspection, which should only take two to five days,could take weeks. GE Energy Products Europe will provide recommendations regardingthe type and quantities of spare parts needed; however, it is up to the owner to purchasethese spare parts on a planned basis allowing adequate lead times.

Early identification of spare parts requirements ensures their availability at the time theplanned inspections are performed. Typical expectations for estimated repair cycles for some of the major components are shown in Figure 1-25. Many engineering judgmentsare built into this table, including base load continuous duty on natural gas fuel andoperation of the unit in accordance with all of the manufacturers specifications andinstructions. Maintenance inspections and repairs are also assumed to be done inaccordance with the manufacturers specifications and instructions. The actual repair andreplacement cycles for any particular gas turbine should be based on the users operatingprocedures, experience, maintenance practices and repair practices.

The maintenance factors can have a major impact on both the component repair intervaland service life. For this reason, the intervals given in Figure 1-25 should be used only asguidelines for long-range parts planning. Operating factors and experience gained duringthe course of recommended inspection and maintenance procedures will be a moreaccurate predictor of the actual intervals.

It should be recognized that, in some cases, the service life of a component is reachedwhen it is no longer economical to repair any deterioration as opposed to replacing at afixed interval. This is illustrated in Figure 1-26 for a first stage nozzle, where repairscontinue until either the nozzle cannot be restored to minimum acceptance standards or the repair cost exceeds or approaches the replacement cost. In other cases, such as firststage buckets, repair options are limited by factors such as irreversible material damage.In both cases, users should follow recommendations of GE Energy Products Europeregarding replacement or repair of these components.

8/4/2019 9E_GT_M_M01_C01_V4_A

37/47





Description Repair Replace ReplaceInterval Interval Interval

(Hours) (Starts)

Combustion Liners CI * 5(CI) 5(CI)Transition Pieces CI 6(CI) 6(CI)Fuel Nozzles CI 3(CI) 3(CI)Cross Fire Tubes CI 3(CI) 3(CI)Flow Divider (Distillate) CI 3(CI) 3(CI)Fuel Pump (Distillate) CI 3(CI) 3(CI)1st. Stage Nozzles HGPI ** 3(HGPI) 3(HGPI)2nd. Stage Nozzles HGPI 3(HGPI) 3(HGPI)3rd. Stage Nozzles HGPI 3(HGPI) 3(HGPI)1st. Stage Buckets HGPI 2(HGPI) 3(HGPI)2nd. Stage Buckets HGPI 3(HGPI) 4(HGPI)3rd. Stage Buckets HGPI 3(HGPI) 4(HGPI)1st. Stage Shrouds HGPI 2(HGPI) 2(HGPI)2nd. / 3rd. Stage Shrouds HGPI 3(HGPI) 4(HGPI)Operation / Maintenance / Repair in accordance with GE Energy Products Europespecifications and instructions is a key for minimizing repair and replacement costs.*CI Combustion Inspection Intervals**HGPI Hot Gas Path Inspection Intervals

Figure 1-25: Estimated repair and replacement cycles (MS6001B / MS9001E, operating under ideal conditions of gas fuel, continuous duty, base load and no water or steam injection)

N o z z

l e c o n

d i t i o n

Figure 1-26: First stage nozzle wear-preventive maintenance.(Gas fired, continuous duty, base load and no water or steam

8/4/2019 9E_GT_M_M01_C01_V4_A

38/47





1.1.8 Inspection intervalsFigure 1-27 lists the recommended combustion, hot gas path and major inspectionintervals for current production of GE Energy Products Europe turbines operating under ideal conditions of gas fuel, continuous duty, base load and no water or steam injection.Considering the maintenance factors discussed previously, an adjustment from thesemaximum intervals may be necessary, based on the specific operating conditions of agiven application. Initially, this determination is based on the expected operation of aturbine installation, but this should be reviewed and adjusted as actual operating andmaintenance data are accumulated. While reductions in the maximum intervals will resultfrom the factors described previously, increases in the maximum interval can also beconsidered where operating experience has been favorable. The condition of the hot gas

path parts provides a good basis for customizing a program of inspection andmaintenance.

Hours / StartsType of MS6B MS6F/7F/9F MS9001EInspectionCombustion Non-DLN

DLN12,000 / 1,200*12,000 / 450 8,000 / 450

8,000 / 90012,000/ 450

Hot gas path 24,000 / 1200 24,000 / 900 24,000 / 900Major 48,000 / 2,400 48,000 / 2,400 48,000 / 2,400

Factors That Can Reduce Maintenance IntervalsFuelTrips from LoadLoad SettingStart CycleSteam / Water injectionHGP Hardware DesignPeak Load T Operation

*Machines with 6581 and 6Bev combustion hardware have a 12,000 / 600 combustion interval .

Figure 1-27: Base line recommended inspection intervals ( base load - gas fuel - dry)

GE Energy Products Europe can assist operators in determining the appropriate

maintenance intervals for their particular application. Equations have been developed thataccount for the factors described earlier and can be used to determine application specifichot gas path and major inspection intervals. The hours-based hot gas path criterion isdetermined from the equation given in Figure 1-28. With this equation, a maintenancefactor is determined that is the ratio of factored operating hours and actual operatinghours. The factored hours consider the specifics of the duty cycle relating to fuel type,load setting and steam or water injection. Maintenance factors greater than one reducethe hot gas path inspection interval from the 24,000 hour ideal case for continuous baseload, gas fuel and no steam or water injection.To determine the application specific maintenance interval, the maintenance factor isdivided into 24,000, as shown in Figure 1-28.

8/4/2019 9E_GT_M_M01_C01_V4_A

39/47





Maintenance Interval (Hours) = 24,000Maintenance Factor

Maintenance Factor = Factored HoursActual Hours

Factored Hours = (K + M x I) x (G + 1.5D + A f H + 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 A f = 3 to 4, Crude A f = 2to 3)

P = Annual Peak Load Operating Hours

I = Percent Water / Steam Injection Referenced to Inlet Air Flow

M & K = Water / Steam Injection Constants

M K Control Steam Injection N2/N3Material

0 1 Dry 2.2% GTD-222

0.18 0.6 Dry > 2.2% FSX-414

0.18 1 Wet > 0% GTD-222/FSX-414

Figure 1-28: Hot gas path inspection; hours-based criterion (MS6001B / 9001E)

The starts-based hot gas path criterion is determined from the equation given in Figure 1-29. As with the hours-based criteria, an application specific starts-based hot gas pathinspection interval is calculated from a maintenance factor that is determined from thenumber of trips typically being experienced, the load level and loading rate.

As previously described, the hours and starts operating spectrum for the application isevaluated against the recommended hot gas path intervals for starts and for hours. Thelimiting criterion (hours or starts) determines the maintenance interval. An example of theuse of these equations is contained in the appendix.

While the hot gas path and major inspection interval can be determined from theequations given in Figures 1-28 and 1-29, the combustion intervals have not beenreduced to that form. Recommendations are provided that are specific to the combustionhardware design, fuel, type of diluents and emissions level. Recommendations for combustion intervals for specific application can be provided by the GE Energy ProductsEurope.

8/4/2019 9E_GT_M_M01_C01_V4_A

40/47





As an example, Figure 1-30 describes the recommended combustion inspection intervalsfor the MS6001B.

Application of the new CLE TM System (Combustor Life Extension) wear kit has thepotential to significantly increase the stated intervals.

Maintenance Interval (Starts) = SMaintenance Factor

Maintenance Factor = Factored StartsActual Starts

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

n

i

Tian1

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

S = Maximum Starts-Based Maintenance Interval (Model Size Dependent)

NA = Annual Number of Part Load Start / Stop Cycles ( < 60% Load)

NB = Annual Number of Normal Base Load Start / Stop Cycles

NP = Annual Number of Peak Load Start / Stop Cycles

E = Annual Number of Emergency StartsF = Annual Number of Fast Load Starts

T = Annual Number of Trips

a T = Trip Severity Factor = f (Load)

n = Number of Trip Categories ( Full Load, Part Load etc.)

Model Series SMS6B 1200MS6FA 900MS9000E 900

Figure 1-29: Hot gas path inspection starts-based criterion

8/4/2019 9E_GT_M_M01_C01_V4_A

41/47





Combustor NO x Diluents Fuel

Design Emissions Levelppm

GasHours/Starts

DistillateHours/Starts

Standard Liner Dry 12,000 / 800 12,000 / 800

65 Steam --------------- 12,000 / 400

Water --------------- 9,000 / 300

42 Steam 12,000 / 400 4,500 / 150

Water 9,000 / 300 2,250 / 100

Multi-Nozzle 42 Steam --------------- 9,000 / 300

Quiet Combustor Water --------------- 9,000 / 300

25 Steam 12,000 / 400 --------------

Water 12,000 / 400 --------------

Dry Low No x(DLN)

25 Dry 12,000 / 400 --------------

Figure 1-30: Combustion inspection intervals - MS6001B

8/4/2019 9E_GT_M_M01_C01_V4_A

42/47





1.1.9 Manpower planningIt is essential that advanced manpower planning be conducted prior to an outage. Itshould be understood that a wide range of experience, productivity and workingconditions exist around the world. However, based upon the maintenance inspectionman-hour assumptions shown in Figure 1-31, such as the use of an average crew of workers in French with trade skill (but not necessarily direct gas turbine experience), withall needed tools and replacement parts (no repair time) available, an estimate can bemade as shown in Figure 1-32. These estimated man-hour requirements deal only withthe flange-to-flange section of the gas turbine. Additional man-hours are needed to cover the controls and accessories as well as the generator, load- and auxiliary gear etc., butthis work can be performed concurrently with the turbine work.

DIRECT LABOR - NO SUPERVISIONNO REPAIR TIME - REPLACEMENT ONLY ALL PARTS AVAILABLE ALL NECESSARY TOOLS AVAILABLE CREW WITH AVERAGE TRADE SKILL FLANGE-TO-FLANGE TURBINE ONLY, WITHOUT DRY LOW NO X (DLN) INSPECTION HAS BEEN PRE-PLANNED

Figure 31: Maintenance inspection man-hour assumptions

TYPE OFINSPECTION

MODEL SERIES MAN HOURS AVERAGECREW SIZE

8 HOURSHIFTS

COMBUSTION 3000 72 3 35000 160 4 56000 400 5 109000 624 6 13

HOT GAS PATH 3000 288 6 65000 480 6 106000 1080 9 159000 2400 10 30

MAJOR 3000 758 8 125000 1280 8 206000 2800 10 359000 4400 11 50

Figure 32: Maintenance inspections estimated man-hour requirements (according figure

24, without dln)

8/4/2019 9E_GT_M_M01_C01_V4_A

43/47





Typical crew sizes and trade skills needed to perform a combustion, hot gas path andmajor inspection on a MS6001B unit are shown in Figure 1-33. Furthermore, as anindication of typical maintenance man-hour requirements which may be used in initialplanning phases, Figure 1-34 shows average man-hours per downtime (calendar) hour for some of the more prevalent types of inspection activity that occur during the life of agas turbine.

Man-hoursTrade SkillCombustion Inspec. Hot gas path Inspec. Major Inspection

Millwrights 388 920 2444

Elec./NDT Tech. 9 16 50Crane Operator 3 30 70

Carpenter 0 21 38Welder 0 3 8Driver/Helper 0 90 190

____ _____ ____ 400 1080 2800

Figure 1-33: Man-hours, typically achieved for combustion, hot gas path or major inspections (MS6001B gas turbine only, without DLN)

MH* / DTH**- Control Device Diagnostic- Control Calibration- Change Inlet Air Filter Cartridges- Inlet & Thrust Bearing- Enclosures (Major Scope)- IGV Change out- Combustion Inspection- Hot Gas Path Inspection ( GT only)- Major Inspection (GT only)- Generator Inspection

1.21.51.96.07.05.53.58.09.04.0

----------

1.81.72.37.08.06.54.5

10.011.0

5.0Figure 1-34: Average man-hours per downtime hour (6001B, without DLN)

Supervision / Technical Direction Excluded

* MH = Man-hours

** DTH = Downtime hour

8/4/2019 9E_GT_M_M01_C01_V4_A

44/47





The extent, to which combustion inspection frequencies and downtimes vary within theMS6001B fleet because of different duty cycles and therefore, the economic need for theunit to be in a state of operational readiness, is shown in Figure 1-35. It clearlydemonstrates that a 12,000 hour interval for a combustion inspection and minimumdowntime (72 hours) is achievable based on the associated demand on the unit.

Figure 35: Combustion Inspections MS6001B (without

INTERVAL TIME OF PERFORMANCE

12000 100008000 6000 4000 2000 0 100 200 300 400 500 600

FIRED HOURS DOWNTIME

PEAKING DUTY

CYCLING

CONTINUOUS

STANDBY DUTY

Figure 1-35: Combustion Inspections MS6001B (without DLN)

Depending upon the extent of work to be done during each maintenance task, it isnormally preceded by a cool-down period of 4 to 24 hours. This time can be utilizedproductively for job move-in, correct tagging of equipment and locking equipment out-of-service and general work preparations. At the conclusion of the inspection andmaintenance work, a turning gear time of two to eight hours is normally allocated prior tostarting the unit. This time can be used for job clean up and arranging for any repairsrequired on removed parts. Service Department of GE Energy Products Europe isavailable to help plan your maintenance work to reduce downtime and labor costs. Thisplanned approach will outline the renewal parts that may be needed and the projectedwork scope, showing which tasks can be accomplished in parallel and which tasks mustbe sequential. Planning techniques can be used to reduce maintenance cost byoptimizing lifting equipment and devices schedules and manpower requirements. Preciseestimates of the outage duration, resource requirements, recommended replacementparts and costs associated with the inspection of a specific installation may be obtainedfrom the Service Department of GE Energy Products Europe.

8/4/2019 9E_GT_M_M01_C01_V4_A

45/47





1.1.10 SummaryHeavy-duty gas turbines of GE Energy Products Europe are designed to have aninherently high availability. To achieve maximum gas turbine availability, an owner mustunderstand not only his equipment, but also the factors affecting it. This includes thetraining of operating and maintenance personnel, following the manufacturer'srecommendations, regular periodic inspections and the stocking of spare parts for immediate replacement. The recording of operating data, and analysis of these data, areessential to preventative and planned maintenance. A key factor in achieving this goal is acommitment by the owner to provide effective outage management and full utilization of published instructions and the available service support facilities.

It should be recognized that, while the manufacturer provides general maintenancerecommendations, it is the equipment user who has the major impact upon the proper maintenance and operation of equipment. Inspection intervals for optimum turbine serviceare not fixed for every installation, but rather are developed through an interactiveprocess by each user, based on past experience and trends indicated by key turbinefactor.

The level and quality of a rigorous maintenance program have a direct impact onequipment reliability and availability. Therefore, a rigorous maintenance program, whichoptimizes both maintenance cost and availability, is vital to the user. A rigorousmaintenance program will minimize overall costs, keep outage downtimes to a minimum,improve starting and running reliability and provide increased availability and revenue-earning ability for GE Energy Products Europe gas turbine users.

8/4/2019 9E_GT_M_M01_C01_V4_A

46/47





1.1.11 AppendixExample - Maintenance Interval Calculation

An MS6001B user has accumulated operating data since the last hot gas pathinspection and would like to estimate when the next one should be scheduled. Theuser is aware from publications of GE Energy Products Europe that the normal HGPinterval is 24,000 hours if operating on natural gas, no water or steam injection, baseload. Also, there is a 1200 start interval, based on normal start-ups, no trips, noemergency starts.

The actual operation of the unit since the last hot gas path inspection is much differentfrom the GE Energy Products Europe "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 = E = 2 / yr.

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

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

For this particular unit, the second- and third-stage nozzles are FSX-414 material. Theunit operates on "dry control curve". From Figure 1-28, at a steam injection rate of 2.4%, the value of "M" is 0.18 and "K" is 0.6. From the hours-based criteria, themaintenance factor is determined from Figure 1-28.

MF = (0.6 + 0.18 x 2.4) x (3200 + 1.5 x 350 + 6 x 120))3200 + 350 + 120

MF = 1.25 (MF = Maintenance Factor)

8/4/2019 9E_GT_M_M01_C01_V4_A

47/47




The hours-based adjusted inspection interval is therefore:H = 24,000/1.25

H = 19,200 hours

Since total annual operating hours is 3670, the estimated time to reach 19,200 is5.24 years (19,200/3670).

From the starts-based criteria, the maintenance factor is determined from Figure 1-29.

MF = 100 + 0.5 x 40 + 20 x 2 + 2 x 5 + 8 x 20100 + 40 + 2 + 5 + 20

MF = 2.0 (MF = Maintenance Factor)

The adjusted inspection interval based on starts is:

S = 1200/2.0

S = 600 starts

Since the total annual number of starts is 167, the estimated time to reach 600 starts is 600/167 = 3.6 years.

In this case, the starts-based maintenance factor is greater than the hoursmaintenance factor and therefore the inspection interval is set by starts. The hot gaspath inspection interval is 600 starts (or 3.6 years).

Date post:	07-Apr-2018
Category:	Documents
Upload:	mohammad-ibnul-hossain
View:	216 times
Download:	0 times

9E_GT_M_M01_C01_V4_A

Documents