GE Frame 5 Service Manual

							27
inspection of all of the major flange-to-flange components of 
the gas turbine, which are subject to deterioration during normal 
turbine operation. This inspection includes previous elements of the 
combustion and hot gas path inspections, and requires laying open 
the complete flange-to-flange gas turbine to the horizontal joints, 
as shown in Figure 32.
Removal of all of the upper casings allows access to the 
compressor rotor and stationary compressor blading, as well as 
to the bearing assemblies. Prior to removing casings, shells, and 
frames, the unit must be properly supported. Proper centerline 
support using mechanical jacks and jacking sequence procedures 
are necessary to assure proper alignment of rotor to stator, obtain 
accurate half shell clearances, and to prevent twisting of the 
casings while on the half shell. Reference the O&M Manual for 
unit-specific jacking procedures. In addition to combustion and 
hot gas path inspection requirements, typical major inspection 
requirements are: •	
Check all radial and axial clearances against their original values 
(opening and closing).
•	 Inspect all casings, shells, and frames/diffusers for cracks   
and erosion.
•	 Inspect compressor inlet and compressor flow-path for fouling, 
erosion, corrosion, and leakage.
•	 Check rotor and stator compressor blades for tip clearance,   
rubs, object damage, corrosion pitting, and cracking.
•	 Remove turbine buckets and perform a nondestructive check 
of buckets and wheel dovetails. Wheel dovetail fillets, pressure 
faces, edges, and intersecting features must be closely examined 
for conditions of wear, galling, cracking, or fretting.
•	 Inspect unit rotor for cracks, object damage, or rubs.
•	 Inspect bearing liners and seals for clearance and wear.
Figure 37  . Gas turbine major inspection – key elements
Criteria
•	 O&M	Manual	 •	 TILs
•	 GE	 Field	EngineerInspection Methods
•	 Visual	 •	 Liquid	Penetrant
•	 Borescope	 •	 Ultrasonics
Major Inspection
Hot Gas Path Inspection Scope—Plus:
Key Hardware  Inspect For  Potential Action
Compressor blading  Foreign object damage  Repair/refurbishment/replace
Unit rotor Oxidation/corrosion/erosion  •	Bearings/seals
Journals and seal surfaces  Cracking  – Clean
Bearing seals  Leaks  – Assess oil condition
Exhaust system  Abnormal wear – Re-babbitt
Missing hardware •	Compressor	 blades
Clearance limits – Clean
Coating wear – Blend
Fretting •	Exhaust	 system
– Weld repair
– Replace flex seals/L-seals
Compressor and compressor 
discharge case hooks Wear 
Repair
All cases – exterior and interior  Cracks  Repair or monitor
Cases – Exterior Slippage Casing alignment
GE Power & Water | GER-3620M (00015001200140018
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							28
•	Visually inspect compressor and compressor discharge case
hooks for signs of wear.
•	 Visually inspect compressor discharge case inner barrel.
•	 Inspect exhaust frame flex seals, L-seals, and horizontal joint
gaskets for any signs of wear or damage. Inspect steam gland
seals for wear and oxidation.
•	 Check torque values for steam gland bolts and re-torque
to full values.
•	 Check alignment – gas turbine to generator/gas turbine to
accessory gear.
•	 Inspect casings for signs of casing flange slippage.
Comprehensive inspection and maintenance guidelines have been 
developed by GE and are provided in the O&M Manual to assist 
users in performing each of the inspections previously described.
Parts Planning
Prior to a scheduled disassembly inspection, adequate spares 
should be on-site. Lack of adequate on-site spares can have   
a major effect on plant availability. For example, a planned   
outage such as a combustion inspection, which should only   
take two to five days, could take weeks if adequate spares are   
not on-site. GE will provide recommendations regarding the   
types and quantities of spare parts needed; however, it is up   
to the owner to purchase these spare parts on a planned basis 
allowing adequate lead times.
Early identification of spare parts requirements ensures their 
availability at the time the planned inspections are performed. 
Refer to the Reference Drawing Manual provided as part of the 
comprehensive set of O&M Manuals to aid in identification and 
ordering of gas turbine parts.
Additional benefits available from the renewal parts catalog   
data system are the capability to prepare recommended spare 
parts lists for the combustion, hot gas path and major inspections 
as well as capital and operational spares.
Estimated repair and replacement intervals for some of the   
major components are shown in Appendix D . These tables assume 
that operation, inspections, and repairs of the unit have been   
done in accordance with all of the manufacturer’s specifications 
and instructions. The actual repair and replacement intervals for any particular 
gas turbine should be based on the user’s operating procedures, 
experience, maintenance practices, and repair practices. The 
maintenance factors previously described can have a major effect 
on both the component repair interval and service life. For this 
reason, the intervals given in Appendix D
 should only be used 
as guidelines and not certainties for long range parts planning. 
Owners may want to include contingencies in their parts planning.
The estimated repair and replacement interval values reflect 
current production hardware (the typical case) with design 
improvements such as advanced coatings and cooling technology. 
With earlier production hardware, some of these lives may not be 
achievable. Operating factors and experience gained during the 
course of recommended inspection and maintenance procedures 
will be a more accurate predictor of the actual intervals.
The estimated repair and replacement intervals are based on 
the recommended inspection intervals shown in Figure 39 . For 
certain models, technology upgrades are available that extend the 
maintenance inspection intervals. The application of inspection (or 
repair) intervals other than those shown in Figure 39  can result in 
different replacement intervals than those shown in Appendix D . 
See your GE service representative for details on a specific system. 
It should be recognized that, in some cases, the service life of a 
component is reached when it is no longer economical to repair 
any deterioration as opposed to replacing at a fixed interval. This 
is illustrated in Figure 38  for a first stage nozzle, where repairs 
continue 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 first-stage buckets, 
repair options are limited by factors such as irreversible material 
damage. In both cases, users should follow GE recommendations 
regarding replacement or repair of these components.
It should also be recognized that the life consumption of any one 
individual part within a parts set can have variations. This may 
lead to a certain percentage of “fallout,” or scrap, of parts being 
repaired. Those parts that fallout during the repair process will 
need to be replaced by new parts. Parts fallout will vary based on 
the unit operating environment history, the specific part design, 
and the current repair technology. 
						

							29
Operating Hours
Nozzle Construction
Severe Deterioration
10,00020,00030,00040,00050,00060,00070,00080,000
New Nozzle
Acceptance Standards
Repaired Nozzle
Min. Acceptance 
Standard 1st
Repair
2nd
Repair
3rd
Repair
Repair Cost ExceedsReplacement CostWithout Repair
Figure 38 .  First-stage nozzle repair program: natural  gas fired – continuous dry – base load
Type of InspectionType of 
hours/
starts
Hours/Starts
6B 
7E  9E
MS3002K MS50 01PA MS5002C, D6B
 .037E .0

3
 (6)9E .03 (7)
Combustion (Non-DLN)  Factored 12000/400 (3) 12000/800 (1)(3)(5) 12000/800 (1)(3)(5) 
12000/600 (2)(5) 8000/900 (2)(5)  8000/900 (2)(5)
Combustion (DLN) 
Factored  8000/400 (3)(5) 8000/400 (3)(5) 12000/450 (5) 
12000/450 (5)  12000/450 (5)
Hot Gas Path 
Factored 24000/1200 (4) 
24000/1200 (4)(5) 24000/1200 (4)(5) 24000/1200 (5) 24000/1200 (5) 24000/900 (5)
Major 
Actual 48000/2400 
48000/2400 (5) 48000/2400 (5) 
48000/2400 (5) 48000/2400 (5) 48000/2400 (5)
Type of Inspection  Type of 
hours/
starts
Hours/Starts
6F
7F 9F
6 F  .
0
 3   7 F  .
0
 3  7 F
 .
0
 4  7FB
 .01

 9 F
 .
0
 3  9 F
 .
0
 5
Combustion (Non-DLN)  Factored 8000/400
Combustion (DLN)  Factored 12000/450 
(5) 24000/900 
32000/900 (5) 12000/450 
24000/900  12000/450
Hot Gas Path  Factored 24000/900  24000/900 
32000/1250 24000/900 
24000/900  24000/900
Major  Actual 48000/2400  48000/2400 
64000/2400 48000/2400 
48000/2400  48000/2400
Factors that can reduce 
maintenance intervals:
•	 Fuel
•	 Load setting
•	 Steam/water injection
•	 Peak load firing
operation
•	 Tr i p s
•	 Start cycle
•	 Hardware design
•	 Off-frequency operation 1.
U

nits with Lean Head End liners have a 400-starts combustion inspection
interval.
2.
M

ultiple Non-DLN configurations exist (Standard, MNQC, IGCC). The typical
case is shown; however, different quoting limits may exist on a machine and
hardware basis. Contact a GE service representative for further information.
3.
C

ombustion inspection without transition piece removal. Combustion
inspection with transition pieces removal to be performed every 2
combustion inspection intervals.
4.
H

ot gas path inspection for factored hours eliminated on units that operate
on natural gas fuel without steam or water injection.
5.
U

pgraded technology (Extendor*, PIP, DLN 2.6+, etc) may have longer
inspection intervals.
6.
A

lso applicable to 7121(EA) models.
7.
A

pplicable to non-AGP units only.
*Trademark of General Electric Company
Note: 
B
 aseline inspection intervals 
reflect current production 
hardware, unless otherwise 
noted, and operation 
in accordance with 
manufacturer specifications. 
They represent initial 
recommended intervals in 
the absence of operating 
and condition experience.
For Repair/Replace intervals 
see  Appendix D .
Figure 39 . Baseline recommended inspection intervals: base load – natural gas fuel – dry
GE Power & Water | GER-3620M (00015001200140018
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							30
Inspection Intervals
In the absence of operating experience and resulting part 
conditions, Figure 39 lists the recommended combustion, hot   
gas path and major inspection intervals for current production 
GE turbines operating under typical conditions of natural gas fuel, 
base load, and no water/steam injection. These recommended 
intervals represent factored hours or starts calculated using 
maintenance factors to account for application specific operating 
conditions. Initially, recommended intervals are based on   
the expected operation of a turbine at installation, but this   
should be reviewed and adjusted as operating and maintenance 
data are accumulated. While reductions in the recommended 
intervals will result from the factors described previously or 
unfavorable operating experience, increases in the recommended 
intervals may also be considered where operating experience   
has been favorable. 
The condition of the combustion and hot gas path parts provides a 
basis for customizing a program for inspection and maintenance. 
The condition of the compressor and bearing assemblies is the   
key driver in planning a major inspection. Historical operation   
and machine conditions can be used to tailor maintenance 
programs such as optimized repair and inspection criteria to 
specific sites/machines. GE leverages these principles and 
accumulated site and fleet experience in a “Condition Based 
Maintenance” program as the basis for maintenance of units 
under Contractual Service Agreements. This experience was 
accumulated on units that operate with GE approved repairs, 
field services, monitoring, and full compliance to GE’s technical 
recommendations.
GE can assist operators in determining the appropriate 
maintenance intervals for their particular application. Equations 
have been developed that account for the factors described earlier 
and can be used to determine application-specific combustion,   
hot gas path, and major inspection intervals.
Borescope Inspection Interval
In addition to the planned maintenance intervals, which   
undertake scheduled inspections or component repairs or 
replacements, borescope inspections should be conducted to 
identify any additional actions, as discussed in the sections   “Gas Turbine Design Maintenance Features.” Such inspections 
 
may identify additional areas to be addressed at a future 
scheduled maintenance outage, assist with parts or resource 
planning, or indicate the need to change the timing of a future 
outage. The BI should use all the available access points to verify 
the condition of the internal hardware. As much of the Major 
Inspection workscope as possible should be done using this visual 
inspection without dissassembly. Refer to Figure 4  for standard 
recommended BI frequency. Specific concerns may warrant 
subsequent BIs in order to operate the unit to the next scheduled 
outage without teardown.
Combustion Inspection Interval
Equations have been developed that account for the earlier 
mentioned factors affecting combustion maintenance intervals. 
These equations represent a generic set of maintenance factors 
that provide guidance on maintenance planning. As such, these 
equations do not represent the specific capability of any given 
combustion system. For combustion parts, the baseline operating 
conditions that result in a maintenance factor of one are normal 
fired startup and shutdown (no trip) to base load on natural gas 
fuel without steam or water injection.
An hours-based combustion maintenance factor can be determined 
from the equations given in Figure 40  as the ratio of factored hours 
to actual operating hours. Factored hours considers the effects of 
fuel type, load setting, and steam/water injection. Maintenance 
factors greater than one reduce recommended combustion 
inspection intervals from those shown in Figure 39  representing 
baseline operating conditions. To obtain a recommended 
inspection interval for a specific application, the maintenance 
factor is divided into the recommended baseline inspection interval.
A starts-based combustion maintenance factor can be determined 
from the equations given in Figure 41  and considers the effect of 
fuel type, load setting, peaking-fast starts, trips, and steam/water 
injection. An application-specific recommended inspection interval 
can be determined from the baseline inspection interval in Figure 39  
and the maintenance factor from Figure 41 . Appendix B  shows six 
example maintenance factor calculations using the above hours 
and starts maintenance factor equations. 
						

							31
Figure 40 . Combustion inspection hours-based maintenance factors
Syngas units require unit-specific intervals to account for unit-
specific fuel constituents and water/steam injection schedules.   
As such, the combustion inspection interval equations may not 
apply to those units. 
Hours-Based Combustion Inspection 
Where:
i   = Discrete Operating mode (or Operating Practice   
    of Time Interval)
t
i  =  Operating hours at Load in a Given Operating mode
Ap
i  =  Load Severity factor
    Ap  =  1.0 up to Base Load
    Ap  =  For Peak Load Factor See Figure 11
Af
i   =   Fuel Severity Factor
    Af = 1.0 for Natural Gas Fuel
 (1)
   Af = 1.5 for Distillate Fuel, Non-DLN (2.5 for DLN)
    Af = 2.5 for Crude (Non-DLN)
    Af = 3.5 for Residual (Non-DLN)
K
i   =   Water/Steam Injection Severity Factor
    (% Steam Referenced to Compressor Inlet Air Flow,   
    w/f = Water to Fuel Ratio)
    K  =  Max(1.0, exp(0.34(%Steam – 2.00%)))   
        for Steam, Dry Control Curve
    K  =  Max(1.0, exp(0.34(%Steam – 1.00%)))   
        for Steam, Wet Control Curve
    K  =  Max(1.0, exp(1.80(w/f – 0.80)))   
        for Water, Dry Control Curve
    K  =  Max(1.0, exp(1.80(w/f – 0.40)))   
        for Water, Wet Control Curve
(1)  Af = 10 for DLN 1/DLN 1+ extended lean-lean, and DLN 2.0/ DLN 2+ 
extended piloted premixed operating modes.
Maintenance Factor = Factored Hours 
Actual Hours 
Factored Hours =  (Ki · Afi · Api · ti ), i = 1 to n in Operating Modes 
Actual Hours =  (ti ), i = 1 to n in Operating Modes 
 Maintenance  Interval   =  
Baseline CI (Figure 39)  
      Maintenance Factor
Figure 41 . Combustion inspection starts-based maintenance factors
Starts-Based Combustion Inspection 
Where:
i  = Discrete Start/Stop Cycle (or Operating Practice)
N
i   =   Start/Stop Cycles in a Given Operating Mode
As
i  =   Start Type Severity Factor
    As  =  1.0 for Normal Start
    As  =  For Peaking-Fast Start See Figure 14
Ap
i   =   Load Severity Factor
    Ap  =  1.0 up to Base Load
    Ap  =  exp (0.009 x Peak Firing Temp Adder in °F)   
        for Peak Load
At
i   =   Trip Severity Factor
    At  =  0.5 + exp(0.0125*%Load) for Trip
    At  =  1 for No Trip
Af
i   =   Fuel Severity Factor
    Af  =  1.0 for Natural Gas Fuel
    Af  =  1.25 for Non-DLN (or 1.5 for DLN) for Distillate Fuel
    Af  =  2.0 for Crude (Non-DLN)
    Af  =  3.0 for Residual (Non-DLN)
K
i   =   Water/Steam Injection Severity Factor
    (% Steam Referenced to Compressor Inlet Air Flow,   
    w/f = Water to Fuel Ratio)
    K  =  Max(1.0, exp(0.34(%Steam – 1.00%)))   
        for Steam, Dry Control Curve
    K  =  Max(1.0, exp(0.34(%Steam – 0.50%)))   
        for Steam, Wet Control Curve
    K  =  Max(1.0, exp(1.80(w/f – 0.40)))   
        for Water, Dry Control Curve
    K  =  Max(1.0, exp(1.80(w/f – 0.20)))   
        for Water, Wet Control Curve
Maintenance Factor = Factored Star ts 
Actual Star ts 
Factor ed Star ts =  (Ki · Afi · Ati · Api · Asi · Ni ), i = 1 to n Star t/Stop Cycles
Actual Starts =  (Ni ), i = 1 to n in Star t/Stop Cycles
 Maintenance  Interval   =  
Baseline CI (Figure 39)  
      Maintenance Factor
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							32
Hot Gas Path Inspection Interval
The hours-based hot gas path criterion is determined from the 
equations given in Figure 42. With these equations, a maintenance 
factor is determined that is the ratio of factored operating hours 
and actual operating hours. 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 
reduce the hot gas path inspection interval from the baseline 
(typically 24,000 hour) case. To determine the application specific 
maintenance interval, the maintenance factor is divided into the 
baseline hot gas path inspection interval, as shown in Figure 42 .The starts-based hot gas path criterion is determined from the 
equations given in Figure 43
. 
As previously described, the limiting criterion (hours or starts) 
determines the maintenance interval. Examples of these equations 
are in Appendix A .
Rotor Inspection Interval
Like hot gas path components, the unit rotor has a maintenance 
interval involving removal, disassembly, and inspection. This 
interval indicates the serviceable life of the rotor and is generally 
considered to be the teardown inspection and repair/replacement 
interval for the rotor. The disassembly inspection is usually 
concurrent with a hot gas path or major inspection; however, 
it should be noted that the maintenance factors for rotor 
maintenance intervals are distinct from those of combustion and 
hot gas path components. As such, the calculation of consumed 
life on the rotor may vary from that of combustion and hot gas 
path components. Customers should contact GE when their rotor is 
approaching the end of its serviceable life for technical advisement.
Hours-Based HGP Inspection 
i 
 
=
  
1 to n d
 iscrete operating modes (or operating practices 
of

 time interval)
t
i  =   Fired hours in a given operating mode
Ap
i  =  Load severity factor for given operating mode
A

p  
 =
  
1
 .0 up to base load
A

p  
 =
  
F
 or peak load factor see Figure 11 .
Af
i  =  Fuel severity factor for given operating mode
A

f   
=
  
1
 .0 for natural gas
A

f   
= 
  
1
 .5 for distillate  
 
(
 =1.0 when Ap > 1, at minimum Af ∙ Ap = 1.5)
A

f   
= 
  
2 to 3 f
 or crude
A

f   
= 
  
3 to 4 f
 or residual
S
i  =   Water/steam injection severity factor = Ki + (Mi ∙ Ii)
I

 
 = 

 
P

ercent water/steam injection referenced 
 
to c

ompressor inlet air flow
M

&K 
 
= 

 
W

ater/steam injection constants
M K Control Water/Steam Inj  .S2N/S3N Material
0 1 Dry 2.2%Non-FSX-414
0.18 0.6 Dry >2.2%FSX-414
0.18 1 Wet >0%Non-FSX-414
0.55 1 Wet >0%FSX-414
Maintenance Factor = Factored Hours 
Actual Hours 
Factored Hours = ni=1 (Si · Afi · Api · ti ) 
Actual Hours = ni=1 (ti ) 
 Maintenance Interval   =  B aseline HGPI (Figure 39) 
(

Hours)  
M
 aintenance Factor
Figure 42 . Hot gas path maintenance interval: hours-based criterion
Starts-Based HGP Inspection
Where:
Actual Starts = (N
A + NB + NP) 
S
 
=

 
B

aseline Starts-Based Maintenance Interval ( Figure 39)
N
A =  Annual Number of Part Load Start/Stop Cycles 
(



100% Load)
P
s =  Peaking-Fast Start Factor (See Figure 14 )
F
 
=
  
A
 nnual Number of Peaking-Fast Starts
T
 
=
  
A
 nnual Number of Trips
a
T =  Trip Severity Factor = f(Load) (See Figure 20 )
n
 
=
  
N
 umber of Trip Categories (i.e. Full Load, Part Load, etc.)
Maintenance Factor = Factored Star ts
Actual Starts
Factored Starts = 0.5NA + NB + 1.3NP + PsF + n i=1 (aTi – 1) Ti
Figure 43 .  Hot gas path maintenance interval: starts-based criterion
 Maintenance  Interval   =  S 
(S

tarts)  
M
 aintenance Factor 
						

							33
Figure 44 describes the procedure to determine the hours-
based maintenance criterion. Peak load operation is the primary 
maintenance factor for the F-class rotor and will act to increase 
the hours-based maintenance factor and to reduce the rotor 
maintenance interval. For B/E-class units time on turning gear also 
affects rotor life.
The starts-based rotor maintenance interval is determined from the 
equations given in Figure 45 . Adjustments to the rotor maintenance 
interval are determined from rotor-based operating factors as 
described previously. In the calculation for the starts-based rotor 
maintenance interval, equivalent starts are determined for cold, 
warm, and hot starts over a defined time period by multiplying 
the appropriate cold, warm, and hot start operating factors by the 
number of cold, warm, and hot starts respectively. Additionally, 
equivalent starts for trips from load are added. The total equivalent 
starts are divided by the actual number of starts to yield the  maintenance factor. The rotor starts-based maintenance interval 
is determined by dividing the baseline rotor maintenance interval 
of 5000 starts by the calculated maintenance factor. The baseline 
rotor maintenance interval is also the maximum interval, since 
calculated maintenance factors less than one are not considered.
When the rotor reaches the earlier of the inspection intervals 
described in Figures 44 and 45
, an unstack of the rotor is required 
so that a complete inspection of the rotor components in both 
the compressor and turbine can be performed. It should be 
expected that some rotor components will either have reached 
the end of their serviceable life or will have a minimal amount of 
residual life remaining and will require repair or replacement at this 
inspection point. Depending on the extent of refurbishment and 
part replacement, subsequent inspections may be required at a 
reduced interval.
Hours-Based Rotor Inspection
H = Non-peak load operating hours
P = Peak load operating hours
T
G = Hours on turning gear
R = Baseline rotor inspection interval
Machine
F-class
All other  R(3)
144,000
200,000
(1)  Maintenance factor equation to be used unless otherwise notified in unit-
specific documentation.
(2) 
 
T
 o diminish potential turning gear impact, major inspections must include 
a thorough visual and dimensional examination of the hot gas path 
turbine rotor dovetails for signs of wearing, galling, fretting, or cracking. 
If no distress is found during inspection or after repairs are performed to 
the dovetails, time on turning gear may be omitted from the hours-based 
maintenance factor.
(3) 
 
B
 aseline rotor inspection intervals to be used unless otherwise notified in 
unit-specific documentation.
MF = Factored Hours
Actual Hours
MF for
B/E-class= H + 2P(1)
H + P= H + 2P + 2TG (2)
H + P
Figure 44 .
 Rotor maintenance interval: hours-based criterion
 Maintenance  Interval   =  R 
(

Hours)  
M
 aintenance Factor
Starts-Based Rotor Inspection
For units with published start factors:
For B/E-class units
For all other units additional start factors may apply.
Number of Starts
Nh1 = Number of hot 1 starts
N
h2 =  Number of hot 2 starts
N
w1 =  Number of warm 1 starts
N
w2 =  Number of warm 2 starts
N
c =  Number of cold starts
N
t =  Number of trips from load
N
s =  Total number of fired starts
Start Factors (2)
Fh1 = Hot 1 start factor (down 0-1 hr)
F
h2 =  Hot 2 start factor (down 1-4 hr)
F
w1 =  Warm 1 start factor (down 4-20 hr)
F
w2 = Warm 2 start factor (down 20-40 hr)
F
c =  Cold start factor (down >40 hr)
F
t =  Trip from load factor
(
1) 
 
B

aseline rotor inspection interval is 5,000 fired starts unless otherwise 
notified in unit-specific documentation.
(2) 
 
S

tart factors for certain F-class units are tabulated in Figure 22 . For all 
other machines, consult unit-specific documentation to determine if start 
factors apply.
Maintenance Factor = Factored Starts
Actual Star ts
MaintenanceFactor = 
(Fh1 · Nh1 + Fh2 · Nh2 + Fw1 · Nw1 + Fw2 · Nw2 + Fc · Nc + Ft · Nt)
(Nh1+Nh2+Nw1+Nw2+Nc )
Maintenance Factor = NS + NT
NS
Figure 45 .
 Rotor maintenance interval: starts-based criterion
 Maintenance  Interval   =  5 ,000(1) 
(S

tarts)
 
M

aintenance Factor
GE Power & Water | GER-3620M (00015001200140018
)  
						

							34
The baseline rotor life is predicated upon sound inspection results 
at the major inspections. For F-class rotors the baseline intervals 
are typically 144,000 hours and 5,000 starts. For rotors other than 
F-class, the baseline intervals are typically 200,000 hours and 
5,000 starts. Consult unit-specific documentation to determine if 
alternate baseline intervals or maintenance factors may apply.
Personnel Planning
It is essential that personnel planning be conducted prior to an 
outage. It should be understood that a wide range of experience, 
productivity, and working conditions exist around the world. 
However, an estimate can be made based upon maintenance 
inspection labor assumptions, such as the use of a crew of  
workers with trade skill (but not necessarily direct gas turbine 
experience), with all needed tools and replacement parts (no   
repair time) available. These estimated craft labor hours should 
include controls/accessories and the generator. In addition to   
the craft labor, additional resources are needed for technical 
direction, specialized tooling, engineering reports, and site 
mobilization/demobilization.
Inspection frequencies and the amount of downtime varies   
within the gas turbine fleet due to different duty cycles and the 
economic need for a unit to be in a state of operational readiness. 
Contact your local GE service representative for the estimated 
labor hours and recommended crew size for your specific unit.
Depending upon the extent of work to be done during each 
maintenance task, a cooldown period of 4 to 24 hours may be 
required before service may be performed. This time can be 
utilized productively for job move-in, correct tagging and locking 
equipment out-of-service, and general work preparations. At the 
conclusion of the maintenance work and systems check out, a 
turning gear time of two to eight hours is normally allocated prior 
to starting the unit. This time can be used for job clean-up and 
preparing for start.
Local GE field service representatives are available to help plan 
maintenance work to reduce downtime and labor costs. This 
planned approach will outline the replacement parts that may be 
needed and the projected work scope, showing which tasks can 
be accomplished in parallel and which tasks must be sequential. 
Planning techniques can be used to reduce maintenance cost by 
optimizing lifting equipment schedules and labor requirements.  Precise estimates of the outage duration, resource requirements, 
critical-path scheduling, recommended replacement parts, and 
costs associated with the inspection of a specific installation may 
be sourced from the local GE field services office.
Conclusion
GE heavy-duty gas turbines are designed to have high availability. 
To achieve maximum gas turbine availability, an owner must 
understand not only the equipment but also the factors affecting 
it. This includes the training of operating and maintenance 
personnel, following the manufacturer’s recommendations, regular 
periodic inspections, and the stocking of spare parts for immediate 
replacement. The recording and analysis of operating data is also 
essential to preventative and planned maintenance. A key factor 
in achieving this goal is a commitment by the owner to provide 
effective outage management, to follow published maintenance 
instructions, and to utilize the available service support facilities.
It should be recognized that, while the manufacturer provides 
general maintenance recommendations, it is the equipment 
user who controls the maintenance and operation of equipment. 
Inspection intervals for optimum turbine service are not fixed for 
every installation but rather are developed based on operation 
and experience. In addition, through application of a Contractual 
Service Agreement to a particular turbine, GE can work with 
 
a user to establish a maintenance program that may differ   
from general recommendations but will be consistent with 
contractual responsibilities.
The level and quality of a rigorous maintenance program have a 
direct effect on equipment reliability and availability. Therefore, 
a rigorous maintenance program that reduces costs and outage 
time while improving reliability and earning ability is the optimum 
GE gas turbine user solution. 
						

							35
References
Jarvis, G., “Maintenance of Industrial Gas Turbines,” GE Gas Turbine 
State of the Art Engineering Seminar, paper SOA-24-72, June 1972.
Patterson, J. R., “Heavy-Duty Gas Turbine Maintenance Practices,” 
GE Gas Turbine Reference Library, GER-2498, June 1977.
Moore, W. J., Patterson, J.R, and Reeves, E.F., “Heavy-Duty Gas 
Turbine Maintenance Planning and Scheduling,” GE Gas Turbine 
Reference Library, GER-2498; June 1977, GER 2498A, June 1979.
Carlstrom, L. A., et al., “The Operation and Maintenance of General 
Electric Gas Turbines,” numerous maintenance articles/authors 
reprinted from Power Engineering magazine, General Electric 
Publication, GER-3148; December 1978.
Knorr, R. H., and Reeves, E. F., “Heavy-Duty Gas Turbine 
Maintenance Practices,” GE Gas Turbine Reference Library, GER-
3412; October 1983; GER- 3412A, September 1984; and GER-3412B, 
December 1985.
Freeman, Alan, “Gas Turbine Advance Maintenance Planning,” 
paper presented at Frontiers of Power, conference, Oklahoma State 
University, October 1987.
Hopkins, J. P, and Osswald, R. F., “Evolution of the Design, 
Maintenance and Availability of a Large Heavy-Duty Gas Turbine,” 
GE Gas Turbine Reference Library, GER-3544, February 1988 (never 
printed).
Freeman, M. A., and Walsh, E. J., “Heavy-Duty Gas Turbine 
Operating and Maintenance Considerations,” GE Gas Turbine 
Reference Library, GER-3620A.
GEI-41040, “Fuel Gases for Combustion in Heavy-Duty Gas 
Tu r b i n e s .”
GEI-41047, “Gas Turbine Liquid Fuel Specifications.”
GEK-101944, “Requirements for Water/Steam Purity in Gas 
Tu r b i n e s .”
GER-3419A, “Gas Turbine Inlet Air Treatment.”
GER-3569F, “Advanced Gas Turbine Materials and Coatings.”
GEK-32568, “Lubricating Oil Recommendations for Gas Turbines 
with Bearing Ambients Above 500°F (260°C).”
GEK-110483, “Cleanliness Requirements for Power Plant Installation, 
Commissioning and Maintenance.”
GE Power & Water | GER-3620M (00015001200140018
)  
						

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Appendix
A .1) Example 1 – Hot Gas Path Maintenance 
Interval Calculation
A 7E.03 user has accumulated operating data since the last hot  
gas path inspection and would like to estimate when the next   
one should be scheduled. The user is aware from GE publications 
that the baseline HGP interval is 24,000 hours if operating on 
natural gas, with no water or steam injection, and at base load.   
It is also understood that the baseline starts interval is 1200,   
based on normal startups, no trips, no peaking-fast starts. The 
actual operation of the unit since the last hot gas path inspection 
is much different from the baseline case. The unit operates in four 
different operating modes:
1.
T

he unit runs 3200 hrs/yr in its first operating mode, which is
natural gas at base or part load with no steam/water injection.
2.
T

he unit runs 350 hrs/yr in its second operating mode, which is
distillate fuel at base or part load with no steam/water injection.
3.
T

he unit runs 120 hrs/yr in its third operating mode, which is
natural gas at peak load (+100°F) with no steam/water injection.
4.
T

he unit runs 20 hrs/yr in its fourth operating mode, which is
natural gas at base load with 2.4% steam injection on a wet
control curve.
The hours-based hot gas path maintenance interval parameters 
for these four operating modes are summarized below:
Operating Mode (i)
1 2 34
Fired hours (hrs/yr) t 3200 350 120 20
Fuel severity factor Af 1 1.5 1 1
Load severity factor Ap 1 1 [e 
(0.018*100)] = 61
Steam/water injection rate (%) I 0 00 2.4
For this particular unit, the second- and third-stage nozzles are 
FSX-414 material. From Figure 42 , at a steam injection rate of 2.4% 
on a wet control curve, 
M
4 = 0.55, K4 = 1
The steam severity factor for mode 4 is therefore, = S
4 = K4 + (M4 ∙ I4) = 1 + (0.55 ∙ 2.4) = 2.3
At a steam injection rate of 0%, M = 0, K = 1 Therefore, the steam severity factor for modes 1, 2, and 3 are
= S
1 = S2 = S3 = K + (M ∙ I) = 1
From the hours-based criteria, the maintenance factor is 
determined from Figure 42 .
MF = 1.22
The hours-based adjusted inspection interval is therefore, Adjusted Inspection Interval = 24,000/1.22 = 19,700 hours
[Note, since total annual operating hours is 3690, the estimated 
time to reach 19,700 hours is 19,700/3690 = 5.3 years.]
Also, since the last hot gas path inspection the unit has averaged 
145 normal start-stop cycles per year, 5 peaking-fast start cycles 
per year, and 20 base load cycles ending in trips (a
T = 8) per year. 
The starts-based hot gas path maintenance interval parameters 
for this unit are summarized below:
Normal  cycles Peaking 
starts, °F Cycles ending 
in trip, T Total
Part load cycles, N
A40 0040
Base load cycles, N
B100 520125
Peak load cycles, N
P5 005
From the starts-based criteria, the maintenance factor is 
determined from Figure 43 .
MF = 1.8
The adjusted inspection interval based on starts is Adjusted Inspection Interval = 1200/1.8 = 667 starts
[Note, since the total annual number of starts is 170, the estimated 
time to reach 667 starts is 667/170 = 3.9 years.]
In this case the unit would reach the starts-based hot gas path 
interval prior to reaching the hours-based hot gas path interval. 
The hot gas path inspection interval for this unit is therefore 667 
starts (or 3.9 years).
MF = n i=1 (Si · Afi · Api · ti ) 

n i=1) (ti ) 
= (1 · 1 · 1 · 3200) + (1 · 1.5 · 1 · 350) + (1 ·\
 1 · 6 · 120) + (2.3 · 1 · 1 · 20)
(3200 + 350 + 120 + 20)
MF = 0.5NA + NB + 1.3NP + PsF + ni=1 (aTi - 1) Ti 
NA + NB + NP
MF = 0.5 (40) + 125 + 1.3 (5) + 3.5 (5) + (8 - 1 )20
40 + 125 + 5