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GER-3620N (10/17)
Mardy Merine
The Power Generation industry globally continues to experience rapid change. Distributed generation, renewables, storage, and smart grids
are disrupting markets everywhere.
In the face of these ever-changing market forces, Power Generation enterprises need to balance a wide range of decisions on how to operate
and maintain assets to achieve the best outcomes for their business and customers.
It is with these things in mind that we bring you this revised version of GER 3620. For over 28 years, this document has long stood in our
industry as the standard for O&M tradeoffs for GE Gas Turbines.
Highlights to look for in this revision include:
Emphasis on building a Digital strategy for O&M
New products maintenance interval information (HA, 7FA.05, 6F.01)
Clarified maintenance factors
A shift from calendar based inspections to operational based
Introduction to maintenance strategy for Alstom technology GT equipment
As our industry continues to evolve, and O&M decisions become ever more complex, having a clear digital strategy to manage the tradeoffs
will be a key way successful Power Generation companies gain a competitive edge.
This document serves as a great starting point to build an O&M plan for your business. It is meant to serve as a core set of recommendations
and guidelines, but does not cover every possible scenario. It is best used as a starting point to build a dialogue within your company and with
GE on what the best strategy is for your business now and in the future.
I invite you to reach out to your GE representative to partner in building your O&M strategy that will deliver the outcomes you need to win
General Manager Product Service Engineering
GE Power | GER-3620N (10/17) i
Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Maintenance Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Digital Solutions for Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Gas Turbine Configuration Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Borescope Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Major Factors Influencing Maintenance and Equipment Life. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Starts and Hours Criteria. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Service Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Firing Temperatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Steam/Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Cyclic Effects and Fast Starts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Hot Gas Path Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Rotor Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Combustion Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Casing Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Exhaust Diffuser Parts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Off-Frequency Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Compressor Condition and Performance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Lube Oil Cleanliness. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Moisture Intake. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Maintenance Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Standby Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Running Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Rapid Cool-Down. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Combustion Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Hot Gas Path Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Major Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Parts Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Inspection Intervals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Borescope Inspection Interval. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Combustion Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Hot Gas Path Inspection Interval. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Legacy Alstom Inspection Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Rotor Inspection Interval. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Welded Rotor Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
GE Power | GER-3620N (10/17) iii
Personnel Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Conclusion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Appendix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
A.1) Example 1 Hot Gas Path Maintenance Interval Calculation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
A.2) Example 2 Hot Gas Path Factored Starts Calculation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
B) Examples Combustion Maintenance Interval Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
C) Definitions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
D) Estimated Repair and Replacement Intervals (Natural Gas Only). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
E) Borescope Inspection Ports. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
F) Turning Gear/Ratchet Running Guidelines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
G) B/E-, F-, and H-class Gas Turbine Naming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Revision History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
List of Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Acknowledgments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Introduction Maintenance Planning
Maintenance costs and machine availability are two of the Advanced planning for maintenance is necessary for utility,
most important concerns to a heavy-duty gas turbine equipment industrial, independent power, and cogeneration plant operators
owner. Therefore, a well thought out maintenance program that in order to maintain reliability and availability. The correct
reduces the owners costs while increasing equipment availability implementation of planned maintenance and inspection
should be instituted. For this maintenance program to be effective, provides direct benefits in the avoidance of forced outages,
owners should develop a general understanding of the relationship unscheduled repairs, and downtime. The primary factors that
between the operating plans and priorities for the plant, the skill affect the maintenance planning process are shown in Figure 1.
level of operating and maintenance personnel, and all equipment The owners operating mode and practices will determine how
manufacturers recommendations regarding the number and each factor is weighted. Gas turbine parts requiring the most
types of inspections, spare parts planning, and other major factors careful attention are those associated with the combustion
affecting component life and proper operation of the equipment. process, together with those exposed to the hot gases discharged
from the combustion system. These are called the combustion
In this document, operating and maintenance practices for
section and hot gas path parts, and they include combustion liners,
heavy-duty gas turbines will be reviewed, with emphasis placed
end caps, fuel nozzle assemblies, crossfire tubes, transition pieces,
on types of inspections plus operating factors that influence
turbine nozzles, turbine stationary shrouds, and turbine buckets.
Additional, longer-term areas for consideration and planning
are the lives of the compressor rotor, turbine rotor, casings,
The operation and maintenance practices outlined in this
and exhaust diffuser. The basic configuration and recommended
document are based on full utilization of GE-approved parts,
maintenance of GE heavy-duty gas turbines are oriented toward:
repairs, and services. Contact GE for support and solutions
when operational practices are not aligned with GER-3620 Maximum periods of operation between inspections
recommendations. and overhauls
The operating and maintenance discussions presented In-place, on-site inspection and maintenance
are generally applicable to all GE heavy-duty gas turbines;
Use of local trade skills to disassemble, inspect, and
i.e., Frames 3, 5, 6, 7, and 9. Appendix G provides a list of
re-assemble gas turbine components
common B/E-, F-, and H-class heavy-duty gas turbines with
current and former naming conventions. For purposes of In addition to maintenance of the basic gas turbine, other
illustration, the GE GT-7E.03 was chosen for most components station auxiliaries require periodic servicing including the
except exhaust systems, which are illustrated using different control devices, fuel-metering equipment, gas turbine auxiliaries,
gas turbine models as indicated. Also, the operating and and load package. The primary maintenance effort involves five
maintenance discussions presented for all B/E-class units basic systems: controls and accessories, combustion, turbine,
are generally applicable to Frame 3 and Frame 5 units unless generator, and balance-of-plant. Controls and accessories are
otherwise indicated. Consult the GE Operation and Maintenance typically serviced in outages of short duration, whereas the
(O&M) Manual for specific questions on a given machine, or other four systems are maintained through less frequent
contact the local GE service representative. outages of longer duration. This document is focused on
maintenance planning for the basic gas turbine, which includes
GE merged with Alstom in 2015. This revision of GER-3620
the combustion and turbine systems. The other systems,
includes operating and maintenance considerations applicable to
while outside the scope of this document, also need to be
Alstom technology type heavy duty gas turbines where explicitly
considered for successful plant maintenance.
stated. Unit specific inspection guidelines (IGLs) should be
consulted for detailed operating and maintenance considerations,
including maintenance intervals and recommended outage scope.
GE Power | GER-3620N (10/17) 1
Recommended Configuration Cost of
Maintenance Features Downtime
Reliability Need Parts
On-Site Reserve
Maintenance Utilization Need Environment Requirements
The inspection and repair requirements, outlined in the O&M
Manual provided to each owner, lend themselves to establishing
Turbine-specific manual provided to customer
a pattern of inspections. These inspection patterns will vary
Includes outline of recommended Inspection and
from site to site, because factors such as air and fuel quality
are used to develop an inspection and maintenance program.
Helps customers to establish a pattern of systematic
In addition, supplementary information is provided through a inspections for their site
system of Technical Information Letters (TILs) associated with
Technical Information Letters (TILs)*
specific gas turbines after shipment. This updated information, in
Issued after shipment of turbine
addition to the O&M manual, aims to assure optimum installation,
Provides O&M updates related to turbine installation,
operation, and maintenance of the turbine. (See Figure 2.) Many
maintenance, and operation
of the TILs contain advisory technical recommendations to help Provides advisory technical recommendations to help
resolve issues and improve the operation, maintenance, safety, resolve potential issues
reliability, or availability of the turbine. The recommendations *	Specific smaller frame turbines are issued service letters known as
contained in TILs should be reviewed and factored into the Customer Information Notices (NICs) instead of TILs
overall maintenance planning program.
Digital Solutions for M&D center is connected to more than 5000 power production
assets, giving GE one of the richest data sets of experience
from across the world, which combines with our unique domain
Operational and business conditions are continually evolving
knowledge to provide excellent analytics, and proven results
as the power industry is undergoing a rapid transformation.
Dynamic conditions require power generation and utility
companies to refine how they monitor and maintain operating Outage Workscope
assets. Businesses that embrace digital solutions have best GE Powers Outage Excellence process, a milestone-driven
managed these dynamic shifts in the industry. GE provides a outage planning cycle, improves asset specific outage workscope
suite of digital tools that is built on years of power production through digital predictions and inspections. This methodology
domain expertise. These tools enable strategic plant operation enables GE and customers, to plan and execute real-time
by providing insights related to equipment operation, improved condition based maintenance and provision emergent work,
outage planning, and more continuous operation in line with on time and to budget. Digital inspections are utilized to
industry demand. GE Powers Asset Performance Management analyze asset conditions and evaluate technical risks, thereby
(APM), M&D Center coverage, and Asset Life Odometers, can identifying the correct outage scope to reduce unplanned
improve reliability, availability and improve maintenance across downtime with no impact to performance.
not only the gas turbine, but the entire plant.
GE Powers Asset Performance Management solution is a
The GE heavy-duty gas turbine is constructed to withstand
dynamic suite of tools, created to provide customers with
severe duty and to be maintained on-site, with off-site repair
real time access to data and predictive analytics in a collaborative
required only on certain combustion components, hot gas path
environment focused on enhancing operation and maintenance
parts, and rotor assemblies needing specialized shop service.
decisions. APM not only gives insight into asset operation but
The following features are configured into GE heavy-duty gas
also provides the capability to shift to a predictive maintenance
turbines to facilitate on-site maintenance:
operating model. Utilizing GEs expertise as one of the leading
OEMs in the industry, physics based and fleet reliability models All casings, shells and frames are split on machine horizontal
can more accurately predict the effect of operation and events, centerline. Upper halves may be lifted individually for access
on parts and assets across the plant. Our advanced models, linked to internal parts.
to failure modes, enable customers to extend useful life of parts, With upper-half compressor casings removed, all stationary
improve outage workloads and enhance outage planning cycles. vanes can be slid circumferentially out of the casings for
With one of the widest failure mode coverages in the industry, inspection or replacement without rotor removal. HA gas
APM helps asset-centric organizations drive safer and more turbines also require the removal of inner casings for hot
reliable operations while facilitating improved performance gas path maintenance.
at a lower, more sustainable, cost.
With the upper-half of the turbine shell lifted, each half of the
Remote Monitoring and Diagnostic (M&D) Center first stage nozzle assembly can be removed for inspection,
The GE Remote M&D Center provides customers direct access repair, or replacement without rotor removal. On some units,
to GE engineers and power production experts for real-time upper-half, later-stage nozzle assemblies are lifted with the
collaboration on operation and maintenance decisions. Utilizing turbine shell, also allowing inspection and/or removal of
the latest Digital tools, subject matter experts in the M&D the turbine buckets. HA gas turbines require removal of
center continuously monitor connected assets, evaluate alarm the inner turbine shell for access to and maintenance of the
indications, and take action to help ensure accurate diagnoses hot gas path hardware. Special tooling is required to remove
and rapid remediation. First established over 20 years ago, GEs the inner turbine shell.
GE Power | GER-3620N (10/17) 3
All turbine buckets are moment-weighed and computer Provisions have been built into GE heavy-duty gas turbines to
charted in sets for rotor spool assembly so that they may facilitate several special inspection procedures. These special
be replaced without the need to remove or rebalance the procedures provide for the visual inspection and clearance
rotor assembly. measurement of some of the critical internal components
without removal of the casings. These procedures include gas
All bearing housings and liners are split on the horizontal
path borescope inspection (BI), radial clearance measurements,
centerline so that they may be inspected and replaced when
and turbine nozzle axial clearance measurements.
necessary. The lower half of the bearing liner can be removed
without removing the rotor. A GE gas turbine is a fully integrated configuration consisting of
stationary and rotating mechanical, fluid, thermal, and electrical
All seals and shaft packings are separate from the main
systems. The turbines performance, as well as the performance
bearing housings and casing structures and may be readily
of each component within the turbine, is dependent upon the
operating interrelationship between internal components and
On most configurations, fuel nozzles, combustion liners and the total operating systems. GEs engineering process evaluates
flow sleeves can be removed for inspection, maintenance, or how new configurations, configuration changes, and repairs
replacement without lifting any casings. All major accessories, affect components and systems. This configuration, evaluation,
including filters and coolers, are separate assemblies that testing, and approval helps assure the proper balance and
are readily accessible for inspection or maintenance. They interaction between all components and systems for safe,
may also be individually replaced as necessary. reliable, and economical operation.
Casings can be inspected during any outage or any shutdown The introduction of new, repaired, or modified parts must be
when the unit enclosure is cool enough for safe entry. The evaluated in order to avoid negative effects on the operation
exterior of the inlet, compressor case, compressor discharge and reliability of the entire system. The use of non-GE approved
case, turbine case, and exhaust frame can be inspected during parts, repairs, and maintenance practices may represent a
any outage or period when the enclosure is accessible. The significant risk. Pursuant to the governing terms and conditions,
interior surfaces of these cases can be inspected to various warranties and performance guarantees are predicated upon
degrees depending on the type of outage performed. All interior proper storage, installation, operation, and maintenance,
surfaces can be inspected during a major outage. conforming to GE approved operating instruction manuals
Exhaust diffusers can be inspected during any outage by and repair/modification procedures.
entering the diffuser through the stack or Heat Recovery Steam
Generator (HRSG) access doors. The flow path surfaces, flex seals,
An effective borescope inspection program monitors the
and other flow path hardware can be visually inspected with or
condition of internal components without casing removal.
without the use of a borescope. Diffusers can be weld-repaired
Borescope inspections should be scheduled with consideration
without the need to remove the exhaust frame upper half.
given to the operation and environment of the gas turbine and
Inlets can be inspected during any outage or shutdown. information from the O&M Manual and TILs.
As an alternative to on-site maintenance, in some cases plant GE heavy-duty gas turbine designs incorporate provisions in
availability can be improved by applying gas turbine modular both compressor and turbine casings for borescope inspection
replacements. This is accomplished by exchanging engine modules of intermediate compressor rotor stages, first, second and third-
or even the complete gas turbine with new or refurbished units. stage turbine buckets, and turbine nozzle partitions. These
The removed modules/engines can then be sent to an alternate provisions are radially aligned holes through the compressor
location for maintenance.
casings, turbine shell, and internal stationary turbine shrouds
Major Factors Influencing
that allow the penetration of an optical borescope into the
compressor or turbine flow path area. Borescope inspection
There are many factors that can influence equipment life, and
access locations for the various frame sizes can be found in
these must be understood and accounted for in the owners
maintenance planning. Starting cycle (hours per start),
Figure 3 provides a recommended interval for a planned power setting, fuel, level of steam or water injection, and site
borescope inspection program following initial baseline environmental conditions are some of the key factors in
inspections. It should be recognized that these borescope determining maintenance interval requirements, as these factors
inspection intervals are based on average unit operating directly influence the life of replaceable gas turbine parts.
modes. Adjustment of these borescope intervals may be made
Non-consumable components and systems, such as the
based on operating experience, mode of operation, fuels used,
compressor airfoils, may be affected by site environmental
employment of online M&D analytics, and the results of previous
conditions as well as plant and accessory system effects. Other
borescope inspections. GE should be consulted before any
factors affecting maintenance planning are shown in Figure 1.
change to the borescope frequency is made.
Operators should consider these external factors to prevent
In general, an annual or semiannual borescope inspection the degradation and shortened life of non-consumable
uses all the available access points to verify the condition components. GE provides supplementary documentation
of the internal hardware. This should include, but is not limited to assist in this regard.
to, signs of excessive gas path fouling, symptoms of surface
In the GE approach to maintenance planning, a natural gas
degradation (such as erosion, corrosion, or spalling), displaced
fuel unit that operates at base load with no water or steam
components, deformation or object damage, material loss,
injection is established as the baseline condition, which
nicks, dents, cracking, indications of contact or rubbing, or
sets the maximum recommended maintenance intervals.
other anomalous conditions.
For operation that differs from the baseline, maintenance factors
(MF) are established to quantify the effect on component lives
Gas and At combustion inspection
Distillate or annually, whichever and provide the increased frequency of maintenance required.
Fuel Oil occurs first For example, a maintenance factor of two would indicate a
Borescope maintenance interval that is half of the baseline interval.
At combustion inspection
Heavy Fuel Oil or semiannually, whichever
Gas turbines wear differently in continuous duty application
Figure 3. Borescope inspection planning
and cyclic duty application, as shown in Figure 5. Thermal
During BIs and similar inspections, the condition of the upstream mechanical fatigue is the dominant life limiter for peaking
components should be verified, including all systems from the filter machines, while creep, oxidation, and corrosion are the dominant
house to the compressor inlet. life limiters for continuous duty machines. GE bases most gas
turbine maintenance requirements on independent counts of
The application of a borescope monitoring program will assist with
starts and hours. Whichever criteria limit is first reached
the scheduling of outages and preplanning of parts requirements,
determines the maintenance interval. A graphical display of
resulting in outage preparedness, lower maintenance costs, and
the GE approach is shown in Figure 8. In this figure, the inspection
higher availability and reliability of the gas turbine.
interval recommendation is defined by the rectangle established
by the starts and hours criteria. These recommendations for
GE Power | GER-3620N (10/17) 5
inspection fall within the parts life expectations and are either a linear or elliptical formula. A third variant for determining
selected such that components acceptable for continued use maintenance intervals is a combination of the starts, operating
at the inspection point will have low risk of failure during the hours and EOH concept.
subsequent operating interval.
These various EOH methods are illustrated in Figure 6.
Continuous Duty Cyclic Duty Inspection Intervals
Rupture Thermal Mechanical
Fatigue EOH
Corrosion High-Cycle Fatigue t Operating
of sign Hours)
Oxidation Rubs/Wear n
FFS or WCE
ti h D
olu at
Foreign Object Damage Ev as P
Erosion Linear All Fleet G
High-Cycle Fatigue Elliptical F-Fleet
Rubs/Wear Extended Linear F-Fleet
Foreign Object Damage Extended Linear B/E-Fleet
Box (F-Fleet)
Figure 4. Causes of wear hot gas path components
FFH or WOH
The interactions of continuous duty and cyclic duty applications
Figure 6. Hot gas path maintenance interval comparisons. GE method vs.
can have a second order effect on the lifetime of components. EOH method. FFS = Factored Fired Starts, FFH = Factored Fired Hours,
WCE = Weighted Cyclic Events, WOH = Weighted Operating Hours.
As a result, an alternative to the aforementioned approach, converts
each start cycle and operating hour to an equivalent number of
operating hours (EOH) with inspection intervals based on the
The effect of fired starts and fired hours on component lifetime
equivalent hours count. The EOH counting may be done through
are not the only wear mechanisms which must be considered. As
Fatigue Limits Life Different
Failure Region Limit Life
Starts M it
Un Oxidation
GE Inspection uous
Recommendation Contin & Wear
Unit Limit Life
Inspection Design Life
Recommendation GE Inspection
(Equivalent Hours per Start) Recommendation
Figure 5. GE bases gas turbine maintenance requirements on independent counts of starts and hours
shown in Figure 7, influences such as fuel type and quality, firing Fuel
temperature setting, and the amount of steam or water injection Fuels burned in gas turbines range from clean natural gas to
are considered with regard to the hours-based criteria. Startup rate residual oils and affect maintenance, as illustrated in Figure 9.
and the number of trips are considered with regard to the starts- Although Figure 9 provides the basic relationship between fuel
based criteria. In both cases, these influences may reduce the severity factor and hydrogen content of the fuel, there are other
maintenance intervals. fuel constituents that should be considered. Selection of fuel
severity factor typically requires a comprehensive understanding
Typical baseline inspection intervals (6B.03/7E.03):
of fuel constituents and how they affect system maintenance.
Hot gas path inspection	24,000 hrs or 1200 starts
The selected fuel severity factor should also be adjusted based
Major inspection	48,000 hrs or 2400 starts on inspection results and operating experience.
Heavier hydrocarbon fuels have a maintenance factor ranging
from three to four for residual fuels and two to three for crude
Hours-Based Factors
oil fuels. This maintenance factor is adjusted based on the
water-to-fuel ratio in cases when water injection for NOx
abatement is used. These fuels generally release a higher
Diluent (water or steam injection)
amount of radiant thermal energy, which results in a subsequent
Starts-Based Factors
reduction in combustion hardware life, and frequently contain
Start type (conventional or peaking-fast)
corrosive elements such as sodium, potassium, vanadium, and
Start load (max. load achieved during start cycle, e.g.
lead that can cause accelerated hot corrosion of turbine nozzles
part, base, or peak load)
and buckets. In addition, some elements in these fuels can cause
Shutdown type (normal cooldown, rapid cooldown, or trip)
deposits either directly or through compounds formed with
Figure 7. Maintenance factors inhibitors that are used to prevent corrosion. These deposits
affect performance and can require more frequent maintenance.
When these service or maintenance factors are involved in a
units operating profile, the hot gas path maintenance rectangle Distillates, as refined, do not generally contain high levels of these
that describes the specific maintenance criteria for this operation corrosive elements, but harmful contaminants can be present
is reduced from the ideal case, as illustrated in Figure 8. The in these fuels when delivered to the site. Two common ways of
following discussion will take a closer look at the key operating contaminating number two distillate fuel oil are: salt-water ballast
factors and how they can affect maintenance intervals as well as mixing with the cargo during sea transport, and contamination of
parts refurbishment/replacement intervals. the distillate fuel when transported to site in tankers, tank trucks, or
pipelines that were previously used to transport contaminated fuel,
chemicals, or leaded gasoline. GEs experience with distillate fuels
indicates that the hot gas path maintenance factor can range from
Starts-Based Factors as low as one (equivalent to natural gas) to as high as three. Unless
1,000 Start type
Start load operating experience suggests otherwise, it is recommended that
800 Shutdown type
a hot gas path maintenance factor of 1.5 be used for operation on
Hours-Based Factors distillate oil. Note also that contaminants in liquid fuels can affect
400 Fuel type the life of gas turbine auxiliary components such as fuel pumps
200 Diluent and flow dividers.
Not shown in Figure 9 are alternative fuels such as industrial
Thousands of Fired Hours process gas, syngas, and bio-fuel. A wide variety of alternative
Figure 8. GE maintenance intervals fuels exist, each with their own considerations for combustion in
GE Power | GER-3620N (10/17) 7
Increasing Fuel Severity Factor
Increasing Hydrogen Content in Fuel
Figure 9. Estimated effect of fuel type on maintenance
a gas turbine. Although some alternative fuels can have a neutral path components. Potentially high maintenance costs and loss
effect on gas turbine maintenance, many alternative fuels require of availability can be reduced or eliminated by:
unit-specific intervals and fuel severity factors to account for their
Placing a proper fuel specification on the fuel supplier.
fuel constituents or water/steam injection requirements.
For liquid fuels, each shipment should include a report that
As shown in Figure 9, natural gas fuel that meets GE specification identifies specific gravity, flash point, viscosity, sulfur content,
is considered the baseline, optimum fuel with regard to turbine pour point and ash content of the fuel.
maintenance. Proper adherence to GE fuel specifications in
Providing a regular fuel quality sampling and analysis program.
GEI-41040 and GEI-41047 is required to allow proper combustion
As part of this program, continuous monitoring of water
system operation and to maintain applicable warranties. Liquid
content in fuel oil is recommended, as is fuel analysis that,
hydrocarbon carryover can expose the hot gas path hardware to
at a minimum, monitors vanadium, lead, sodium, potassium,
severe overtemperature conditions that can result in significant
reductions in hot gas path parts lives or repair intervals.
Liquid hydrocarbon carryover is also responsible for upstream Providing proper maintenance of the fuel treatment system
displacement of flame in combustion chambers, which can lead when burning heavier fuel oils.
to severe combustion hardware damage. Owners can control Providing cleanup equipment for distillate fuels when there
this potential issue by using effective gas scrubber systems and is a potential for contamination.
by superheating the gaseous fuel prior to use to approximately
In addition to their presence in the fuel, contaminants can
50F (28C) above the hydrocarbon dew point temperature at
also enter the turbine via inlet air, steam/water injection, and
the turbine gas control valve connection. For exact superheat
carryover from evaporative coolers. In some cases, these sources
requirement calculations, please review GEI 41040. Integral to the
of contaminants have been found to cause hot gas path degradation
system, coalescing filters installed upstream of the performance
equal to that seen with fuel-related contaminants. GE specifications
gas heaters is a best practice and ensures the most efficient
define limits for maximum concentrations of contaminants for
removal of liquids and vapor phase constituents.
fuel, air, and steam/water.
Undetected and untreated, a single shipment of contaminated
In addition to fuel quality, fuel system operation is also a factor in
fuel can cause substantial damage to the gas turbine hot gas
equipment maintenance. Liquid fuel should not remain unpurged
or in contact with hot combustion components after shutdown reduced below approximately 80% of rated output. Conversely,
and should not be allowed to stagnate in the fuel system when a non-DLN turbine running in simple cycle mode maintains fully
strictly gas fuel is run for an extended time. To reduce varnish open inlet guide vanes during a load reduction to 80% and will
and coke accumulation, dual fuel units (gas and liquid capable) experience over a 200F/111C reduction in firing temperature
should be shutdown running gas fuel whenever possible. Likewise, at this output level. The hot gas path and combustion part lives
during extended operation on gas, regular transfers from gas to change for different modes of operation. This turbine control
liquid are recommended to exercise the system components and effect is illustrated in Figure 11. Turbines with DLN combustion
reduce coking. systems use inlet guide vane turndown as well as inlet bleed
heat to extend operation of low NOx premix operation to part
Contamination and build-up may prevent the system from
removing fuel oil and other liquids from the combustion,
compressor discharge, turbine, and exhaust sections when the Firing temperature effects on hot gas path and combustion
unit is shut down or during startup. Liquid fuel oil trapped in the maintenance as described above, relate to clean burning fuels such
system piping also creates a safety risk. Correct functioning of the as natural gas and light distillates. Higher operating temperatures
false start drain system (FSDS) should be ensured through proper affect the creep capability of hot gas path components which
maintenance and inspection per GE procedures. is the primary life limiting mechanism. The life capability of
combustion components can also be affected.
Firing 2500
Peak load is defined as operation above base load and is B/E-class
IGVs close max to min
achieved by increasing turbine operating temperatures. 1200 at constant TF
Significant operation at peak load will require more frequent 2000
Min IGV
maintenance and replacement of hot gas path and combustion 1000
F Max IGV (open)
components. Figure 10 defines the parts life effect corresponding C
to increases in firing temperature. It should be noted that this is 800 1500 Heat Recovery
not a linear relationship, and this equation should not be used IGVs close max to min
at constant TX
for decreases in firing temperature. 600 Peak Load
(0.018*Tf ) % Load
B/E-class: Ap = e
Figure 11. Firing temperature and load relationship heat recovery vs.
(0.023*Tf ) simple cycle operation
F-class: Ap = e
Ap = Peak fire severity factor Steam/Water Injection
Tf = Peak firing temperature adder (in F) Water or steam injection for emissions control or power
augmentation can affect part life and maintenance intervals
Figure 10. Peak fire severity factors - natural gas and light distillates even when the water or steam meets GE specifications. This
relates to the effect of the added water on the hot gas transport
It is important to recognize that a reduction in load does not
properties. Higher gas conductivity, in particular, increases the
always mean a reduction in firing temperature. For example,
heat transfer to the buckets and nozzles and can lead to higher
in heat recovery applications, where steam generation drives
metal temperature and reduced part life.
overall plant efficiency, load is first reduced by closing variable
inlet guide vanes to reduce inlet airflow while maintaining Part life reduction from steam or water injection is directly
maximum exhaust temperature. For these combined cycle affected by the way the turbine is controlled. The control system
applications, firing temperature does not decrease until load is on most base load applications reduces firing temperature as
water or steam is injected. This is known as dry control curve
GE Power | GER-3620N (10/17) 9
operation, which counters the effect of the higher heat transfer Cyclic Effects and Fast Starts
on the gas side and results in no net effect on bucket life. This is the In the previous discussion, operating factors that affect the
standard configuration for all gas turbines, both with and without hours-based maintenance criteria were described. For the
water or steam injection. On some installations, however, the starts-based maintenance criteria, operating factors associated
control system is configured to keep firing temperature constant with the cyclic effects induced during startup, operation, and
with water or steam injection. This is known as wet control curve shutdown of the turbine must be considered. Operating conditions
operation, which results in additional unit output but decreases other than the standard startup and shutdown sequence can
parts life as previously described. Units controlled in this way potentially reduce the cyclic life of the gas turbine components
are generally in peaking applications where annual operating hours and may require more frequent maintenance including part
are low or where operators have determined that reduced parts refurbishment and/or replacement.
lives are justified by the power advantage. Figure 12 illustrates the
Fast starts are common deviations from the standard startup
wet and dry control curve and the performance differences that
sequence. GE has introduced a number of different fast start
result from these two different modes of control.
systems, each applicable to particular gas turbine models. Fast
An additional factor associated with water or steam injection relates starts may include any combination of Anticipated Start Purge, fast
to the higher aerodynamic loading on the turbine components that acceleration (light-off to FSNL), and fast loading. Some fast start
results from the injected flow increasing the cycle pressure ratio. This methods do not affect inspection interval maintenance factors.
additional loading can increase the downstream deflection rate of Fast starts that do affect maintenance factors are referred to as
the second- and third-stage nozzles, which would reduce the repair peaking-fast starts or simply peaking starts.
interval for these components. However, the introduction of high
The effect of peaking-fast starts on the maintenance interval
creep strength stage two and three nozzle (S2N/S3N) alloys, such as
depends on the gas turbine model, the unit configuration, and
GTD-222* and GTD-241*, has reduced this factor in comparison to
the particular start characteristics. For example, simple cycle
previously applied materials such as FSX-414* and N-155*.
7F.03 units with fast start capability can perform a peaking start
Water injection for NOx abatement should be performed according in which the unit is brought from ignition to full load in less than
to the control schedule implemented in the controls system. Forcing 15 minutes. Conversely, simple cycle 6B and other smaller frame
operation of the water injection system at high loads can lead to units can perform conventional starts that are less than 15
combustion and HGP hardware damage due to thermal shock. minutes without affecting any maintenance factors. For units
that have peaking-fast start capability, Figure 13 shows
Steam Injection for 25 pmm NOx
conservative peaking-start factors that may apply.
3% Steam Inj.
Exhaust Temperature F
TF = 2020F (1104C)
Load Ratio = 1.10 Starts-Based Combustion Inspection
Dry Control As = 4.0 for B/E-class
As = 2.0 for F-class
0% Steam Inj.
TF = 2020F (1104C) Starts-Based Hot Gas Path Inspection
Load Ratio = 1.0 3% Steam Inj. Ps = 3.5 for B/E-class
TF = 1994F (1090C)
Ps = 1.2 for F-class
Load Ratio = 1.08
The Wet Control Curve
Maintains Constant TF Starts-Based Rotor Inspection
Fs = 2.0 for F-class*
* See Figure 21 for details
Figure 12. Exhaust temperature control curve dry vs. wet control 7E.03
Figure 13. Peaking-fast start factors
Because the peaking-fast start factors can vary by unit and responding edges cool more quickly than the bulk section, which
by system, the baseline factors may not apply to all units. For results in a tensile strain at the leading edge.
example, the latest 7F.03 peaking-fast start system has the start
factors shown in Figure 14. For comparison, the 7F.03 nominal
fast start that does not affect maintenance is also listed. Consult
Light-Off Unload Ramp
applicable unit-specific documentation or your GE service
representative to verify the hours/starts factors that apply. Load Ramp
Warm-Up No Load Fired Shutdown
7F.03 Starts-Based Combustion Inspection
As = 1.0 for 7F nominal fast start
As = 1.0 for 7F peaking-fast start
7F.03 Starts-Based Hot Gas Path Inspection Time
Ps = Not applicable for 7F nominal fast start Figure 15. Turbine start/stop cycle firing temperature changes
(counted as normal starts)
Ps = 0.5 for 7F peaking-fast start
7F.03 Starts-Based Rotor Inspection
Fs = 1.0 for 7F nominal fast start
Fs = 2.0 for 7F peaking-fast start*
Figure 14. 7F.03 fast start factors
Figure 15 illustrates the firing temperature changes occurring
over a normal startup and shutdown cycle. Light-off, acceleration,
loading, unloading, and shutdown all produce gas and metal
temperature changes. For rapid changes in gas temperature,
Figure 16. Second stage bucket transient temperature distribution
the edges of the bucket or nozzle respond more quickly than the
thicker bulk section, as pictured in Figure 16. These gradients, in Thermal mechanical fatigue testing has found that the number
turn, produce thermal stresses that, when cycled, can eventually of cycles that a part can withstand before cracking occurs is
lead to cracking. strongly influenced by the total strain range and the maximum
Figure 17 describes the temperature/strain history of a metal temperature. Any operating condition that significantly
representative bucket stage 1 bucket during a normal startup increases the strain range and/or the maximum metal temperature
and shutdown cycle. Light-off and acceleration produce transient over the normal cycle conditions will reduce the fatigue life and
compressive strains in the bucket as the fast responding leading increase the starts-based maintenance factor. For example,
edge heats up more quickly than the thicker bulk section of the Figure 18 compares a normal operating cycle with one that
airfoil. At full load conditions, the bucket reaches its maximum includes a trip from full load. The significant increase in the
metal temperature and a compressive strain is produced from strain range for a trip cycle results in a life effect that equates
the normal steady state temperature gradients that exist in the to eight normal start/stop cycles, as shown. Trips from part
cooled part. At shutdown, the conditions reverse and the faster load will have a reduced effect because of the lower metal
GE Power | GER-3620N (10/17) 11
Max Strain Range
Max Metal Temperature Shutdown
Figure 17. Representative Bucket low cycle fatigue (LCF)
temperatures at the initiation of the trip event. Figure 19 Trips are to be assessed in addition to the regular startup/shutdown
illustrates that while a trip from between 80% and 100% load cycles as starts adders. As such, in the factored starts equation
has an 8:1 trip severity factor, a trip from full speed no load of Figure 40, one is subtracted from the severity factor so that the
(FSNL) has a trip severity factor of 2:1. Similarly, overfiring net result of the formula (Figure 40) is the same as that dictated
of the unit during peak load operation leads to increased by the increased strain range. For example, a startup and trip
component metal temperatures. As a result, a trip from from base load would count as eight total cycles (one cycle for
peak load has a trip severity factor of 10:1. startup to base load plus 8-1=7 cycles for trip from base load),
just as indicated by the 8:1 maintenance factor.
Leading Edge Temperature/Strain
Normal Startup/Shutdown Normal Start & Trip
~% Temperature
e ~% Temperature
MA X MAX
Figure 18. Representative Bucket low cycle fatigue (LCF)
Similarly to trips from load, peaking-fast starts will affect the specific to the operating profile and rotor configuration must
starts-based maintenance interval. Like trips, the effects of a be incorporated into the operators maintenance planning.
peaking-fast start on the machine are considered separate A GE Rotor life extension is required when the accumulated
from a normal cycle and their effects must be tabulated in rotor factored fired starts or hours reach the inspection limit.
addition to the normal start/stop cycle. However, there is no (See Figure 41 and Figure 42 in the Inspection Intervals section.)
-1 applied to these factors, so a 7F.03 peaking-fast start during
The thermal condition when the startup sequence is initiated
a base load cycle would have a total effect of 1.5 cycles. Refer to
is a major factor in determining the rotor maintenance interval
Appendix A for factored starts examples, and consult unit-specific
and individual rotor component life. Rotors that are cold when
documentation to determine if an alternative hot gas path
the startup commences experience transient thermal stresses
peaking-fast start factor applies.
as the turbine is brought on line. Large rotors with their longer
While the factors described above will decrease the starts-based thermal time constants develop higher thermal stresses than
maintenance interval, part load operating cycles allow for an smaller rotors undergoing the same startup time sequence.
extension of the maintenance interval. Figure 20 can be used in High thermal stresses reduce thermal mechanical fatigue life
considering this type of operation. For example, two operating and the inspection interval.
cycles to maximum load levels of less than 60% would equate
In addition to the startup thermal condition, the rotor shutdown
to one start to a load greater than 60% or, stated another way,
thermal condition can influence the rotor maintenance factor
would have a maintenance factor of 0.5.
as well. A normal rotor cool down following a normal fired
Factored starts calculations are based upon the maximum load shutdown or trip relies heavily on natural convection for cool
achieved during operation. Therefore, if a unit is operated at part down of the rotor structure at turning gear/ratchet speed as
load for three weeks, and then ramped up to base load for discussed in Figure F-1. However, an operator may elect to
the last ten minutes, then the units total operation would be perform a rapid/forced/crank cool down (see Rapid Cool-Down,
described as a base load start/stop cycle. page 23) which is defined as when an operator creates a forced
convection cooling flow thru the unit by operating the rotor at an
Rotor Parts increased mechanical speed (typically purge speed) after a normal
The maintenance and refurbishment requirements of the rotor shutdown or trip to achieve a faster than normal cool down of the
structure, like the hot gas path components, are affected by rotor structure. This accelerated cooling down of the rotor has
the cyclic effects of startup, operation, and shutdown, as well transient thermal effects which increase the thermal mechanical
as loading and off-load characteristics. Maintenance factors fatigue damage to the rotor structure.
8 F-class and
B/E-class units with
2 For Trips During Startup Accel Assume aT=2
FSNL 0.2
For Trips from Peak Load Assume aT=10
% Load % Load
Figure 19. Maintenance factor trips from load Figure 20. Maintenance factor effect of start cycle maximum load level
GE Power | GER-3620N (10/17) 13
Initial rotor thermal condition is not the only operating factor that maintenance driven. While the percentage of cold starts is high,
influences rotor maintenance intervals and component life. Peaking- the total number of starts is low. The rotor maintenance interval
fast starts, where the turbine is ramped quickly to load, also on continuous duty units will be determined by operating hours
increase thermal gradients on the rotor. rather than starts.
Though the concept of rotor maintenance factors is applicable
Figure 22 lists reference operating profiles of these three general
to all gas turbine rotors, only F-class rotors will be discussed in
categories of gas turbine applications. These duty cycles have
detail. For all other rotors, reference unit-specific documentation
different combinations of hot, warm, and cold starts with each
to determine additional maintenance factors that may apply.
starting condition having a different effect on rotor maintenance
The rotor maintenance factor for a startup is a function of the
interval as previously discussed. As a result, the starts-based rotor
downtime following a previous period of operation. As downtime
maintenance interval will depend on an applications specific duty
increases, the rotor metal temperature approaches ambient
cycle. In the Rotor Inspection Interval section, a method will be
conditions, and thermal fatigue during a subsequent startup
described to determine a maintenance factor that is specific to the
increases. As such, cold starts are assigned a rotor maintenance
factor of two and hot starts a rotor maintenance factor of less
than one due to the lower thermal stress under hot conditions. F, FA, and FB*-class Rotors
This effect varies from one location in the rotor structure to Rotor Maintenance
another. The most limiting location determines the overall Factors
rotor maintenance factor. Peaking- Normal
Fast Start** Start
Figure 21 lists recommended operating factors that should be
used to determine the rotors overall maintenance factor for Hot 1 Start Factor
(0 < downtime 1 hour) ****
certain F-class rotors. The physics governing the thermal stresses
and mechanical fatigue are similar for FA.05 and HA class rotors; Hot 2 Start Factor
(1 hour < downtime 4 hours) ****
however, F-class factors may not be appropriate for inspection
intervals see unit specific documentation. Warm 1 Start Factor
(4 hours < downtime 20 hours) ****
The significance of each of these factors is dependent on the Warm 2 Start Factor
unit operation. There are three categories of operation that are (20 hours < downtime 40 hours) ****
typical of most gas turbine applications. These are peaking, cyclic,
Cold Start Factor
and continuous duty as described below: 4.0 2.0
(Downtime > 40 hours)****
Peaking units have a relatively high starting frequency and Rapid/Forced/Crank
a low number of hours per start. Operation follows a seasonal Cooling Shutdown ***
demand. Peaking units will generally see a high percentage of *	Other factors may apply to early 9F.03 units.
warm and cold starts. **	An F-class peaking-fast start is typically a start in which
the unit is brought from ignition to full load in less than
Cyclic units start daily with weekend shutdowns. Twelve to 15 minutes.
sixteen hours per start is typical, which results in a warm rotor ***	If a unit is on turning gear/ratchet after normal shutdown
condition for a large percentage of the starts. Cold starts are or trip for more than 8 hours prior to Rapid/Forced/Crank
generally seen only after a maintenance outage or following a cooling being initiated, this factor is equal to 0.0 as outlined
in Figure 42
two-day weekend outage.
****	Downtime hours counted from time unit reaches turning
Continuous duty applications see a high number of hours gear/ratchet until initiation of next start.
per start. Most starts are cold because outages are generally Figure 21. Operation-related maintenance factors
Peaking Cyclic Continuous guidelines (See Appendix). Relevant operating instructions and
TILs should be adhered to where applicable. As a best practice,
Hot 2 Start Factor
units should remain on turning gear or ratchet following a planned
(1 hour < downtime 3% 1% 10%
4 hours) shutdown until wheelspace temperatures have stabilized at or
near ambient temperature. If the unit is to see no further activity
Warm 1 Start Factor
(4 hours < downtime 10% 82% 5% for 48 hours after cool-down is completed, then it may be taken
20 hours) off of turning gear.
Warm 2 Start Factor Figure F-1 also provides guidelines for hot restarts. When an
(20 hours < downtime 37% 13% 5% immediate restart is required, it is recommended that the rotor
be placed on turning gear for one hour following a trip from load,
Cold Start Factor trip from full speed no load, or normal shutdown. This will allow
50% 4% 80%
(Downtime > 40 hours)
transient thermal stresses to subside before superimposing a
Hours/Start 4 16 400 startup transient. If the machine must be restarted in less than
Hours/Year 600 4800 8200 one hour, a start factor of 2 will apply.
Starts/Year 150 300 21
Longer periods of turning gear operation may be necessary prior
Percent Rapid/Forced/ to a cold start or hot restart if bow is detected. Vibration data
Crank Cools
taken while at crank speed can be used to confirm that rotor
Rapid/Forced/Crank bow is at acceptable levels and the start sequence can be initiated.
Cooling Shutdown/Year
Users should reference the O&M Manual and appropriate TILs for
Typical Maintenance specific instructions and information for their units.
1.7 1.0 NA
Factor (Starts-Based)
Operational Profile is Application Specific
Inspection Interval is Application Specific
Figure 22. 7F/7FA gas turbine reference operational profile
6 Starts/Week
operations duty cycle. The applications integrated maintenance 16 Hours/Start
factor uses the rotor maintenance factors described above in 4 Outage/Year Maintenance
combination with the actual duty cycle of a specific application 50 Weeks/Year
and can be used to determine rotor inspection intervals. In this 4800 Hours/Year
calculation, the reference duty cycle that yields a starts-based 300 Starts/Year
maintenance factor equal to one is defined in Figure 23. Duty
12 Cold Starts/Year 4%
cycles different from the Figure 23 definition, in particular duty
39 Warm 2 Starts/Year 13%
cycles with more cold starts or a high number of rapid/forced/crank
246 Warm 1 Starts/Year 82%
cool operations, will have a maintenance factor greater than one.
3 Hot 2 Starts/Year 1%
Turning gear or ratchet operation after shutdown and before
0 Rapid/Forced/Crank Cools/Year
starting/restarting is a crucial part of normal operating procedure.
After a shutdown, turning of the warm rotor is essential to avoid 1 Maintenance Factor
bow, or bend, in the rotor. Initiating a start with the rotor in a Baseline Unit Achieves Maintenance Factor = 1
bowed condition could lead to high vibrations and excessive rubs.
Figure 23. Baseline for starts-based maintenance factor definition
Figure F-1 describes turning gear/ratchet scenarios and operation
GE Power | GER-3620N (10/17) 15
Combustion Parts Continuous mode operation mentioned in this section
From hardware configuration standpoint, GE combustion refers to intentional turbine operation in a certain combustion
hardware configuration include transition pieces, combustion mode for longer than what typically takes during normal
liners, flow sleeves, head-end assemblies containing fuel nozzles startup/shutdown.
and cartridges, end caps and end covers, and assorted other Extended mode operation mentioned in this sections is
hardware parts including cross-fire tubes, spark plugs and flame possible in DLN1 or 1+ and DLN2 or 2+ combustion configuration
detectors. In addition, there are various fuel and air delivery only, where the controls logics can be forced to extend a Lean-
components such as purge or check valves and flexible hoses. Lean Mode or Piloted Premixed Mode beyond the turbine load
GE offers several types of combustion systems configurations: corresponding to a normal combustion mode transfer (as defined
Standard combustors, Multi-Nozzle Quiet Combustors (MNQC), via TTRF1 or CRT values).
Integrated Gasification Combined Cycle (IGCC) combustors, From operational standpoint, earlier DLN combustion configurations
and Dry Low NOx (DLN) combustors. Each of the combustion such as DLN1/1+, DLN2/2+ use diffusion combustion (non-Premix)
configurations mentioned above, has specific gas or liquid fuel at part load before reaching the low emissions combustion mode
operating characteristics that affect differently combustion (Premix). These combustion modes nomenclatures are referred to
hardware factored maintenance intervals and refurbishment as Lean-Lean, extended Lean-Lean, sub-Piloted Premix and Piloted
requirements. Premix Modes. General recommendation for continuous mode
Gas turbines fitted with DLN combustion systems operate in operation is in the combustion mode that provides guaranteed
incremental combustion modes to reach to base load operation. emissions, which is the premixed combustion mode (PM). This
A combustion mode constitutes a range of turbine load where fuel combustion mode is also the most beneficial operation mode for
delivery in combustion cans is performed via certain combination ensuring expected hardware life.
of fuel nozzles or fuel circuits within the fuel nozzles. For example, Continuous and extended mode operation in non-PM combustion
for DLN 2.6 combustion systems, mode 3 refers to the load range modes is not recommended due to reduction in combustion
when fuel is being delivered to PM 1 (Premix 1) and PM 2 (Premix 2) hardware life as shown in Figure 24.
fuel nozzles through gas control valves PM 1 and PM 2.
With the introduction of full Premix combustion systems, such
Combustion modes change when turbine load, and consequently as 2.6, 2.6+ the risks for reduction in hardware durability when
combustion reference temperature value (TTRF1 or CRT) crosses running in non-emissions compliance modes are diminished
threshold values defining the initiation of next combustion mode. (with exception of Mode 3, as shown in Figure 24).
Combustor FSNL Base Load High
Combustion Mode Effect on Hardware Life
DLN 1/1+ Primary Lean-Lean
Extended L-L
DLN 2/2+ Diffusion Lean-Lean/sPPM PPM
Extended PPM
DLN 2.6/
Mode 3 Mode 6.2/6.3 Mode 6.3
2.6+/2.6+ XD5 Low
Figure 24: DLN combustion mode effect on combustion hardware
The use of non-Premix combustion modes affects the factored For combustion parts, the baseline operating conditions that
maintenance intervals of combustion hardware as shown below: result in a maintenance factor of one are fired startup and
shutdown to base load on natural gas fuel without steam or water
DLN-1/DLN-1+ extended lean-lean operation results in a
injection. Factors that increase the hours-based maintenance factor
maintenance factor of 10 (excluding Frame 5 units where MF=2).
include peak load operation, distillate or heavy fuels, and steam or
Nimonic 263 will have a maintenance factor of 4.
water injection. Factors that increase starts-based maintenance
DLN 2.0/DLN 2+ extended piloted premixed operation results in factor include peak load start/stop cycles, distillate or heavy fuels,
a maintenance factor of 10. steam or water injection, trips, and peaking-fast starts.
Continuous mode operation in Lean-Lean (L-L), sub-Piloted
Premixed (sPPM), or Piloted Premixed (PPM) modes is not
Most GE gas turbines have inlet, compressor, compressor
recommended as it will accelerate combustion hardware
discharge, and turbine cases in addition to exhaust frames. Inner
barrels are typically attached to the compressor discharge case.
In addition, cyclic operation between piloted premixed and These cases provide the primary support for the bearings, rotor,
premixed modes leads to thermal loads on the combustion and gas path hardware.
liner and transition piece similar to the loads encountered
The exterior of all casings should be visually inspected for
during the startup/shutdown cycle.
cracking, loose hardware, and casing slippage at each combustion,
Continuous mode operation of DLN 2.6/DLN 2.6+ combustors hot gas path, and major outage. The interior of all casings
will not accelerate combustion hardware degradation. should be inspected whenever possible. The level of the outage
Another factor that can affect combustion system maintenance determines which casing interiors are accessible for visual
is acoustic dynamics. Acoustic dynamics are pressure oscillations inspection. Borescope inspections are recommended for the
generated by the combustion process within the combustion inlet cases, compressor cases, and compressor discharge cases
chambers, which when are present at high levels can lead to during gas path borescope inspections. All interior case surfaces
significant wear of combustion or hot gas path components. should be inspected visually, digitally, or by borescope during a
Common GE practice is to tune the combustion system to levels major outage.
of acoustic dynamics deemed low enough not to affect life of Key inspection areas for casings are listed below.
gas turbine hardware. In addition, GE encourages monitoring of
combustion dynamics during turbine operation throughout the
full range of ambient temperatures and loads. Shroud pin and borescope holes in the turbine shell (case)
Combustion disassembly is performed, during scheduled Compressor stator hooks
combustion inspections (CI). Inspection interval guidelines are
Turbine shell shroud hooks
included in Figure 36. It is expected, and recommended, that
intervals be modified based on specific experience. Replacement Compressor discharge case struts
intervals are usually defined by a recommended number of Inner barrel and inner barrel bolts
combustion (or repair) intervals and are usually combustion
Inlet case bearing surfaces and hooks
component specific. In general, the replacement interval as a
function of the number of combustion inspection intervals is Inlet case and exhaust frame gibs and trunions
reduced if the combustion inspection interval is extended. For Extraction manifolds (for foreign objects)
example, a component having an 8,000-hour CI interval, and a
six CI replacement interval, would have a replacement interval
of four CI intervals if the inspection intervals were increased to
12,000 hours (to maintain a 48,000-hour replacement interval).
GE Power | GER-3620N (10/17) 17
Exhaust Diffuser Parts In addition, flex seals, L-seals, and horizontal joint gaskets should
GE exhaust diffusers come in either axial or radial configurations be visually/borescope inspected for signs of wear or damage at
as shown in Figures 25 and 26 below. Both types of diffusers are every combustion, hot gas path, and major outage. GE recommends
composed of a forward and aft section. Forward diffusers are that seals with signs of wear or damage be replaced.
normally axial diffusers, while aft diffusers can be either axial or To summarize, key areas that should be inspected are listed below.
radial. Axial diffusers are used in the F-class gas turbines, while Any damage should be reported to GE for recommended repairs.
radial diffusers are used in B/E-class gas turbines.
Forward diffuser carrier flange (6F)
Exhaust diffusers are subject to high gas path temperatures
Diffuser strut airfoil leading and trailing edges
and vibration due to normal gas turbine operation. Because
of the extreme operating environment and cyclic operating Turning vanes in radial diffusers (B/E-class)
nature of gas turbines, exhaust diffusers may develop cracks
Insulation packs on interior or exterior surfaces
in the sheet metal surfaces and weld joints used for diffuser
Clamp ring attachment points to exhaust frame
construction. Additionally, erosion may occur due to extended
(major outage only)
operation at high temperatures. Exhaust diffusers should be
inspected for cracking and erosion at every combustion, hot gas Flex seals and L-seals
path and major outage.
Horizontal joint gaskets
GE heavy-duty single shaft gas turbines are engineered to operate
at 100% speed with the capability to operate over approximately
a 95% to 105% speed range. Operation at other than rated speed
has the potential to affect maintenance requirements. Depending
on the industry code requirements, the specifics of the turbine
configuration, and the turbine control philosophy employed,
operating conditions can result that will accelerate life consumption
of gas turbine components, particularly rotating flowpath hardware.
Where this is true, the maintenance factor associated with this
Figure 25. F-class axial diffuser operation must be understood. These off-frequency events
must be analyzed and recorded in order to include them in
the maintenance plan for the gas turbine.
Some turbines are required to meet operational requirements
that are aimed at maintaining grid stability under sudden
load or capacity changes. Most codes require turbines to
remain on line in the event of a frequency disturbance. For
under-frequency operation, the turbine output may decrease
with a speed decrease, and the net effect on the turbine
In some cases of under-frequency operation, turbine output
Figure 26. E-class radial diffuser
must be increased in order to meet the specification-defined
output requirement. If the normal output fall-off with speed ignored. However, if significant operation at overspeed is
results in loads less than the defined minimum, the turbine expected and rated firing temperature is maintained, the
must compensate. Turbine overfiring is the most obvious accumulated hours must be recorded and included in the
compensation option, but other means, such as water-wash, calculation of the turbines overall maintenance factor and
inlet fogging, or evaporative cooling also provide potential the maintenance schedule adjusted to reflect the overspeed
means for compensation. A maintenance factor may need to operation.
be applied for some of these methods. In addition, off-frequency
operation, including rapid grid transients, may expose the blading Compressor Condition and Performance
to excitations that could result in blade resonant response and Maintenance and operating costs are also influenced by
reduced fatigue life. the quality of the air that the turbine consumes. In addition
to the negative effects of airborne contaminants on hot
It is important to understand that operation at over-frequency
gas path components, contaminants such as dust, salt,
conditions will not trade one-for-one for periods at under-
and oil can cause compressor blade erosion, corrosion,
frequency conditions. As was discussed in the firing temperature
section above, operation at peak firing conditions has a nonlinear,
logarithmic relationship with maintenance factor. Fouling can be caused by submicron dirt particles entering
the compressor as well as from ingestion of oil vapor, smoke,
Over-frequency or high speed operation can also introduce
sea salt, and industrial vapors. Corrosion of compressor blading
conditions that affect turbine maintenance and part replacement
causes pitting of the blade surface, which, in addition to increasing
intervals. If speed is increased above the nominal rated speed,
the surface roughness, also serves as potential sites for fatigue
the rotating components see an increase in mechanical stress
crack initiation. These surface roughness and blade contour
proportional to the square of the speed increase. If firing
changes will decrease compressor airflow and efficiency,
temperature is held constant at the overspeed condition, the
which in turn reduces the gas turbine output and overall
life consumption rate of hot gas path rotating components will
thermal efficiency. Generally, axial flow compressor deterioration
increase as illustrated in Figure 27 where one hour of operation
is the major cause of loss in gas turbine output and efficiency.
at 105% speed is equivalent to two hours at rated speed.
Recoverable losses, attributable to compressor blade fouling,
If overspeed operation represents a small fraction of a turbines typically account for 70-85% percent of the performance losses
operating profile, this effect on parts life can sometimes be seen. As Figure 28 illustrates, compressor fouling to the extent
that airflow is reduced by 5%, will reduce output by up to 8%
Over Speed Operation and increase heat rate by up to 3%. Fortunately, much can
Constant Tfire be done through proper operation and maintenance procedures
10.0 both to reduce fouling type losses and to limit the deposit of
corrosive elements. On-line compressor wash systems are
available to maintain compressor efficiency by washing the
compressor while at load, before significant fouling has
occurred. Off-line compressor wash systems are used to
clean heavily fouled compressors. Other procedures include
maintaining the inlet filtration system, inlet evaporative coolers,
and other inlet systems as well as periodic inspection and
100 101 102 103 104 105 prompt repair of compressor blading. Refer to system-specific
% Speed maintenance manuals.
Figure 27. Maintenance factor for overspeed operation ~constant TF
GE Power | GER-3620N (10/17) 19
4% Moisture Intake
Heat Rate Increase
0% One of the ways some users increase turbine output is through
-4% the use of inlet foggers. Foggers inject a large amount of moisture
in the inlet ducting, exposing the forward stages of the compressor
to potential water carry-over. Operation of a compressor in
5% Airflow Loss
such an environment may lead to long-term degradation of
the compressor due to corrosion, erosion, fouling, and material
property degradation. Experience has shown that depending on
the quality of water used, the inlet silencer and ducting material,
and the condition of the inlet silencer, fouling of the compressor
can be severe with inlet foggers. Similarly, carryover from
evaporative coolers and water washing more than recommended
Pressure Ratio Decrease can degrade the compressor. The water quality standard that
Figure 28. Deterioration of gas turbine performance due to compressor should be adhered to is found in GEK-101944, Requirements
for Water/Steam Purity in Gas Turbines. Water carry-over may
There are also non-recoverable losses. In the compressor, subject blades and vanes to corrosion and associated pitting.
these are typically caused by nondeposit-related blade surface Such corrosion may be accelerated by a saline environment
roughness, erosion, and blade tip rubs. In the turbine, nozzle throat (see GER-3419). Reductions in fatigue strength may result if the
area changes, bucket tip clearance increases and leakages are environment is acidic and if pitting is present on the blade. This
potential causes. Some degree of unrecoverable performance condition is exacerbated by downtime in humid environments,
degradation should be expected, even on a well-maintained gas which promotes wet corrosion.
turbine. The owner, by regularly monitoring and recording unit Water droplets may cause leading edge erosion up to and
performance parameters, has a very valuable tool for diagnosing through the middle stages of the compressor. This erosion, if
possible compressor deterioration. sufficiently developed, may lead to an increased risk of blade
failure. Online water washing may also cause some leading edge
erosion on the forward stage compressor blades and vanes. To
Contaminated or deteriorated lube oil can cause wear and
mitigate this erosion risk, safeguards are in-place that control the
damage to bearing liners. This can lead to extended outages and
amount of water used, frequency of usage, and radial location of
costly repairs. Routine sampling of the turbine lube oil for proper
water wash nozzles.
viscosity, chemical composition, and contamination is an essential
part of a complete maintenance plan.
Lube oil should be sampled and tested per GEK-32568, Lubricating
Oil Recommendations for Gas Turbines with Bearing Ambients
Above 500F (260C). Additionally, lube oil should be checked
periodically for particulate and water contamination as outlined
in GEK-110483, Cleanliness Requirements for Power Plant
Installation, Commissioning and Maintenance. At a minimum,
the lube oil should be sampled on a quarterly basis; however,
monthly sampling is recommended.
Maintenance Inspections The O&M Manual, as well as the Service Manual Instruction
Books, contains information and drawings necessary to perform
Maintenance inspection types may be broadly classified as standby,
these periodic checks. Among the most useful drawings in the
running, and disassembly inspections. The standby inspection is
Service Manual Instruction Books for standby maintenance are
performed during off-peak periods when the unit is not operating
the control specifications, piping schematics, and electrical
and includes routine servicing of accessory systems and device
elementaries. These drawings provide the calibrations, operating
calibration. The running inspection is performed by observing
limits, operating characteristics, and sequencing of all control
key operating parameters while the turbine is running. The
devices. This information should be used regularly by operating
disassembly inspection requires opening the turbine for inspection
and maintenance personnel. Careful adherence to minor
of internal components. Disassembly inspections progress from
standby inspection maintenance can have a significant effect
the combustion inspection to the hot gas path inspection to the
on reducing overall maintenance costs and maintaining high
major inspection as shown in Figure 29. Details of each of these
turbine reliability. It is essential that a good record be kept of all
inspections are described below.
inspections and maintenance work in order to ensure a sound
Standby Inspections maintenance program.
Standby inspections are performed on all gas turbines but pertain
particularly to gas turbines used in peaking and intermittent-
Running inspections consist of the general and continued
duty service where starting reliability is of primary concern. This
observations made while a unit is operating. This starts by
inspection includes routinely servicing the battery system, changing
establishing baseline operating data during startup of a new
filters, checking oil and water levels, cleaning relays, and checking
unit and after any major disassembly work. This baseline then
device calibrations. Servicing can be performed in off-peak periods
serves as a reference from which subsequent unit deterioration
without interrupting the availability of the turbine. A periodic
startup test run is an essential part of the standby inspection.
Disassembly Inspections Inspection
Figure 29. 7E.03 heavy-duty gas turbine disassembly inspections
GE Power | GER-3620N (10/17) 21
Data should be taken to establish normal equipment startup A sudden abnormal change in running conditions or a severe trip
parameters as well as key steady state operating parameters. event could indicate damage to internal components. Conditions
Steady state is defined as conditions at which no more than a that may indicate turbine damage include high vibration, high
5F/3C change in wheelspace temperature occurs over a 15-minute exhaust temperature spreads, compressor surge, abnormal
time period. Data must be taken at regular intervals and should changes in health monitoring systems, and abnormal changes
be recorded to permit an evaluation of the turbine performance in other monitoring systems. It is recommended to conduct a
and maintenance requirements as a function of operating time. borescope inspection after such events whenever component
This operating inspection data, summarized in Figure 30, includes: damage is suspected.
load versus exhaust temperature, vibration level, fuel flow and
pressure, bearing metal temperature, lube oil pressure, exhaust Load vs. Exhaust Temperature
gas temperatures, exhaust temperature spread variation, startup The general relationship between load and exhaust temperature
time, and coast-down time. This list is only a minimum and should be observed and compared to previous data. Ambient
other parameters should be used as necessary. A graph of these temperature and barometric pressure will have some effect
parameters will help provide a basis for judging the conditions of the upon the exhaust temperature. High exhaust temperature can
system. Deviations from the norm help pinpoint impending issues, be an indicator of deterioration of internal parts, excessive leaks
changes in calibration, or damaged components. or a fouled air compressor. For mechanical drive applications,
it may also be an indication of increased power required by
The vibration signature of the unit should be observed and
recorded. Minor changes will occur with changes in operating
Fired Hours conditions. However, large changes or a continuously increasing
Temperatures trend give indications of the need to apply corrective action.
Inlet Ambient Lube Oil Tank
Compressor Discharge Bearing Metal Fuel Flow and Pressure
Turbine Exhaust Bearing Drains The fuel system should be observed for the general fuel flow
Turbine Wheelspace Exhaust Spread versus load relationship. Fuel pressures through the system
Lube Oil Header should be observed. Changes in fuel pressure can indicate that
Pressures the fuel nozzle passages are plugged or that fuel-metering
Compressor Discharge Cooling Water elements are damaged or out of calibration.
Lube Pump(s) Fuel
Bearing Header Filters (Fuel, Lube, Inlet Air) Exhaust Temperature and Spread Variation
Barometric The most important control function to be monitored is the
Vibration exhaust temperature fuel override system and the back-up over
temperature trip system. Routine verification of the operation
Output Voltage Field Voltage and calibration of these functions will minimize wear on the
Phase Current Field Current hot gas path parts.
VARS Stator Temp.
Load Vibration Startup Time
Startup time is a reference against which subsequent operating
parameters can be compared and evaluated. A curve of the
starting parameters of speed, fuel signal, exhaust temperature,
Figure 30. Operating inspection data parameters and critical sequence bench marks versus time will provide a
good indication of the condition of the control system. Deviations Figure 29 illustrates the section of a 7E.03 unit that is disassembled
from normal conditions may indicate impending issues, changes for a combustion inspection. The combustion liners, transition
in calibration, or damaged components. pieces, and fuel nozzle assemblies should be removed and replaced
with new or repaired components to reduce downtime. The
Coast-Down Time removed liners, transition pieces, and fuel nozzles can then be
Coast-down time is an indicator of bearing alignment and bearing cleaned and repaired after the unit is returned to operation and
condition. The time period from when the fuel is shut off during a be available for the next combustion inspection interval. Typical
normal shutdown until the rotor comes to turning gear speed can combustion inspection requirements are:
be compared and evaluated.
Inspect combustion chamber components.
Close observation and monitoring of these operating parameters
Inspect each crossfire tube, retainer and combustion liner.
will serve as the basis for effectively planning maintenance
work and material requirements needed for subsequent Inspect combustion liner for TBC spalling, wear, and cracks.
shutdown periods. Inspect combustion system and discharge casing for debris
and foreign objects.
Inspect flow sleeve welds for cracking.
Prior to an inspection, a common practice is to force cool the
unit to speed the cool-down process and shorten outage time. Inspect transition piece for wear and cracks.
Force cooling involves turning the unit at crank speed for an Inspect fuel nozzles for plugging at tips, erosion of tip holes,
extended period of time to continue flowing ambient air through and safety lock of tips.
the machine. This is permitted, although a natural cool-down
Inspect impingement sleeves for cracks (where applicable).
cycle on turning gear or ratchet is preferred for normal shutdowns
Inspect all fluid, air, and gas passages in nozzle assembly for
when no outage is pending. Forced cooling should be limited since
plugging, erosion, burning, etc.
it imposes additional thermal stresses on the unit that may result
in a reduction of parts life. Opening the compartment doors Inspect spark plug assembly for freedom from binding; check
during any cool-down operation is prohibited unless an emergency condition of electrodes and insulators.
situation requires immediate compartment inspection. Cool-down Replace all consumables and normal wear-and-tear items such
times should not be accelerated by opening the compartment doors as seals, lockplates, nuts, bolts, gaskets, etc.
or lagging panels, since uneven cooling of the outer casings may
Perform visual inspection of first-stage turbine nozzle partitions
result in excessive case distortion and heavy blade rubs. Cool-down
and borescope inspect (Figure 3) turbine buckets to mark the
is considered complete when all wheelspace temperatures are
progress of wear and deterioration of these parts. This inspection
below 150F when measured at turning gear/ratchet speed.
will help establish the schedule for the hot gas path inspection.
Combustion Inspection Perform borescope inspection of compressor.
The combustion inspection is a relatively short disassembly Visually inspect the compressor inlet, checking the condition
inspection of fuel nozzles, liners, transition pieces, crossfire of the inlet guide vanes (IGVs) and VSVs, where applicable,
tubes and retainers, spark plug assemblies, flame detectors, IGV bushings and VSV bushings, where applicable, and
and combustor flow sleeves. This inspection concentrates first stage rotating blades.
on the combustion liners, transition pieces, fuel nozzles, and
Check the condition of IGV actuators and VSV actuators, where
end caps, which are recognized as being the first to require
applicable, and rack-and-pinion gearing.
replacement and repair in a good maintenance program. Proper
inspection, maintenance, and repair (Figure 31) of these items Verify the calibration of the IGVs and VSVs, where applicable.
will contribute to a longer life of the downstream parts, such as Visually inspect compressor discharge case struts for signs
turbine nozzles and buckets. of cracking.
GE Power | GER-3620N (10/17) 23
Visually inspect compressor discharge case inner barrel Inspect turbine inlet systems including filters, evaporative
if accessible. coolers, silencers, etc. for corrosion, cracks, and loose parts.
Visually inspect the last-stage buckets and shrouds. After the combustion inspection is complete and the unit is
Visually inspect the exhaust diffuser for any cracks in flow returned to service, the removed combustion hardware can
path surfaces. Inspect insulated surfaces for loose or missing be inspected by a qualified GE field service representative and,
insulation and/or attachment hardware in internal and external if necessary, sent to a qualified GE Service Center for repairs.
locations. In B/E-class machines, inspect the insulation on the It is recommended that repairs and fuel nozzle flow testing be
radial diffuser and inside the exhaust plenum as well. performed at qualified GE service centers.
Inspect exhaust frame flex seals, L-seals, and horizontal joint See the O&M Manual for additional recommendations and unit
gaskets for any signs of wear or damage. specific guidance.
Verify proper operation of purge and check valves. Confirm
proper setting and calibration of the combustion controls.
Key Hardware Inspect For Potential Action
Combustion liners Foreign object damage (FOD) Repair/refurbish/replace
Combustion end covers Abnormal wear Transition Pieces Fuel nozzles
Fuel nozzles Cracking Strip and recoat Weld repair
End caps Liner cooling hole plugging Weld repair Flow test
Transition pieces TBC coating condition Creep repair Leak test
Cross fire tubes Oxidation/corrosion/erosion Liners
Flow sleeves Hot spots/burning Strip and recoat
Purge valves Missing hardware
Check valves Clearance limits
Repair out-of-
Flame detectors roundness
IGV and VSV and bushings
Compressor and turbine (borescope)
Exhaust diffuser Cracks Weld repair
Exhaust diffuser Insulation Loose/missing parts Replace/tighten parts
Forward diffuser flex seal	Wear/cracked parts Replace seals
Compressor discharge case Cracks Repair or monitor
Cases exterior	Cracks Repair or monitor
Criteria Inspection Methods Availability of On-Site Spares
O&M Manual	TILs Visual	Liquid Penetrant is Key to Minimizing Downtime
GE Field Engineer Borescope
Figure 31. Combustion inspection key elements
Hot Gas Path Inspection on a part number and operational history basis, and can be
The purpose of a hot gas path inspection is to examine those obtained from a GE service representative.
parts exposed to high temperatures from the hot gases discharged Similarly, repair action is taken on the basis of part number, unit
from the combustion process. The hot gas path inspection outlined operational history, and part condition. Repairs including (but not
in Figure 32 includes the full scope of the combustion inspection limited to) strip, chemical clean, HIP (Hot Isostatic Processing),
and, in addition, a detailed inspection of the turbine nozzles, heat treat, and recoat may also be necessary to ensure full parts
stator shrouds, and turbine buckets. To perform this inspection, life. Weld repair will be recommended when necessary, typically
the top half of the turbine shell must be removed. Prior to shell as determined by visual inspection and NDT. Failure to perform
removal, proper machine centerline support using mechanical the required repairs may lead to retirement of the part before
jacks is necessary to assure proper alignment of rotor to stator, its life potential is fulfilled. In contrast, unnecessary repairs are
obtain accurate half-shell clearances, and prevent twisting of an unneeded expenditure of time and resources. To verify the
the stator casings. Reference the O&M Manual for unit-specific types of inspection and repair required, contact your GE service
jacking procedures. representative prior to an outage.
Special inspection procedures apply to specific components in For inspection of the hot gas path (Figure 31), all combustion
order to ensure that parts meet their intended life. These transition pieces and the first-stage turbine nozzle assemblies
inspections may include, but are not limited to, dimensional must be removed. Removal of the second- and third-stage turbine
inspections, Fluorescent Penetrant Inspection (FPI), Eddy Current nozzle segment assemblies is optional, depending upon the results
Inspection (ECI), and other forms of non-destructive testing (NDT). of visual observations, clearance measurements, and other required
The type of inspection required for specific hardware is determined inspections. The buckets can usually be inspected in place. FPI of
Combustion Inspection ScopePlus:
Nozzles (1, 2, 3, 4) Foreign object damage Repair/refurbish/replace
Buckets (1, 2, 3, 4) Oxidation/corrosion/erosion Nozzles Buckets
Stator shrouds Cracking Weld repair Strip & recoat
Compressor blading (borescope) Cooling hole plugging Reposition Weld repair
Recoat Blend
Remaining coating life
Nozzle deflection/distortion Stator shrouds
Abnormal deflection/distortion Weld repair
Abnormal wear Blend
Turbine shell Cracks Repair or monitor
Figure 32. Hot gas path inspection key elements
GE Power | GER-3620N (10/17) 25
the bucket vane sections may be required to detect any cracks. Check the turbine stationary shrouds for clearance, cracking,
In addition, a complete set of internal turbine radial and axial erosion, oxidation, rubbing, and build-up of debris.
clearances (opening and closing) must be taken during any hot
Inspect turbine rotor for cracks, object damage, or rubs.
gas path inspection. Re-assembly must meet clearance diagram
requirements to prevent rubs and to maintain unit performance. Check and replace any faulty wheelspace thermocouples.
In addition to combustion inspection requirements, typical hot Perform borescope inspection of the compressor.
gas path inspection requirements are:
Visually inspect the turbine shell shroud hooks for signs
Inspect and record condition of first-, second-, and third-stage of cracking.
buckets (and fourth-stage for HA). If it is determined that the
The first-stage turbine nozzle assembly is exposed to the direct
turbine buckets should be removed, follow bucket removal and
hot gas discharge from the combustion process and is subjected
condition recording instructions. Buckets with protective coating
to the highest gas temperatures in the turbine section. Such
should be evaluated for remaining coating life.
conditions frequently cause nozzle cracking and oxidation, and
Inspect and record condition of first-, second-, and third-stage in fact, this is expected. The second- and third-stage nozzles are
nozzles (and fourth-stage for HA). exposed to high gas bending loads, which in combination with the
Inspect seals and hook fits of turbine nozzles and diaphragms operating temperatures can lead to downstream deflection and
for rubs, erosion, fretting, or thermal deterioration. closure of critical axial clearances. To a degree, nozzle distress can
be tolerated, and criteria have been established for determining
Inspect and record condition of later-stage nozzle diaphragm
when repair is required. More common criteria are described in the
O&M Manuals. However, as a general rule, first-stage nozzles will
Inspect lab seals and brush seals for any signs of damage. require repair at the hot gas path inspection. The second- and third-
stage nozzles may require refurbishment to re-establish the proper
Inspect double walled casings mounting surfaces (ledges and
axial clearances. Normally, turbine nozzles can be repaired several
wedges) for signs of coating degradation or loss.
times, and it is generally repair cost versus replacement cost that
Inspect double walled casing alignment screws and pins for dictates the replacement decision.
signs of wear of damage.
Coatings play a critical role in protecting the buckets operating
Inspect double walled casing seals (dog bone seals) for signs at high metal temperatures. They ensure that the full capability
of wear or damage. of the high strength superalloy is maintained and that the bucket
Inspect the exhaust frame mini-case and forward diffuser rupture life meets construction expectations. This is particularly
mini-panel. true of cooled bucket configurations that operate above 1985F
(1085C) firing temperature. Significant exposure of the base metal
Check discourager seals for rubs, and deterioration of clearance.
to the environment will accelerate the creep rate and can lead
Record the bucket tip clearances. to premature replacement through a combination of increased
Inspect bucket shank seals for clearance, rubs, and deterioration. temperature and stress and a reduction in material strength,
as described in Figure 33. This degradation process is driven by
Perform inspections on cutter teeth of tip-shrouded buckets.
oxidation of the unprotected base alloy. On early generation
Consider refurbishment of buckets with worn cutter teeth,
uncooled designs, surface degradation due to corrosion or
particularly if concurrently refurbishing the honeycomb of the
oxidation was considered to be a performance issue and not a
corresponding stationary shrouds. Consult your GE service
factor in bucket life. This is no longer the case at the higher firing
representative to confirm that the bucket under consideration
temperatures of current generation designs.
Oxidation & Bucket Life
Base Metal Oxidation
Depleted Coating
Airfoil Surface Reduced Load Carrying Cross Section
TE Cooling Hole Oxidation
Increases Metal Temperature
Decreases Alloy Creep Strength
Pressure Side Surface
Reduces Bucket Creep Life
Figure 33. Stage 1 bucket oxidation and bucket life
Given the importance of coatings, it must be recognized that even Major Inspection
the best coatings available will have a finite life, and the condition The purpose of the major inspection is to examine all of the
of the coating will play a major role in determining bucket life. internal rotating and stationary components from the inlet of
Refurbishment through stripping and recoating is an option for the machine through the exhaust. A major inspection should be
achieving buckets expected life, but if recoating is selected, it scheduled in accordance with the recommendations in the owners
should be done before the coating is breached to expose base O&M Manual or as modified by the results of previous borescope
metal. Normally, for 7E.03 turbines, this means that recoating and hot gas path inspections. The work scope shown in Figure 34
will be required at the hot gas path inspection. If recoating is not involves inspection of all of the major flange-to-flange components
performed at the hot gas path inspection, the life of the buckets of the gas turbine, which are subject to deterioration during normal
would generally be one additional hot gas path inspection interval, turbine operation. This inspection includes previous elements of
at which point the buckets would be replaced. For F-class gas the combustion and hot gas path inspections, and requires laying
turbines, recoating of the first stage buckets is recommended at open the complete flange-to-flange gas turbine to the horizontal
each hot gas path inspection. Visual and borescope examination joints, as shown in Figure 29.
of the hot gas path parts during the combustion inspections as
Removal of all of the upper casings allows access to the compressor
well as nozzle-deflection measurements will allow the operator
rotor and stationary compressor blading, as well as to the bearing
to monitor distress patterns and progression. This makes part-
assemblies. Prior to removing casings, shells, and frames, the
life predictions more accurate and allows adequate time to plan
unit must be properly supported. Proper centerline support using
for replacement or refurbishment at the time of the hot gas path
mechanical jacks and jacking sequence procedures are necessary to
inspection. It is important to recognize that to avoid extending
assure proper alignment of rotor to stator, obtain accurate half shell
the hot gas path inspection, the necessary spare parts should
clearances, and to prevent twisting of the casings while on the half
be on site prior to taking the unit out of service.
shell. Reference the O&M Manual for unit-specific jacking procedures.
See the O&M Manual for additional recommendations and unit In addition to combustion and hot gas path inspection requirements,
specific guidance. typical major inspection requirements are:
GE Power | GER-3620N (10/17) 27
Check all radial and axial clearances against their original Inspect bearing liners and seals for clearance and wear.
values (opening and closing).
Visually inspect compressor and compressor discharge
Inspect all casings, shells, and frames/diffusers for cracks case hooks for signs of wear.
Visually inspect compressor discharge case inner barrel.
Inspect compressor inlet and compressor flow-path for fouling,
Inspect exhaust frame flex seals, L-seals, and horizontal joint
erosion, corrosion, and leakage.
gaskets for any signs of wear or damage. Inspect steam gland
Check rotor and stator compressor blades for tip clearance, seals for wear and oxidation.
rubs, object damage, corrosion pitting, and cracking.
Inspect lab seals and brush seals for any signs of damage.
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 double walled casing alignment screws and pins for
Inspect unit rotor for heavy corrosion, cracks, object damage,
or rubs. Inspect double walled casing seals (dog bone seals) for signs of
Hot Gas Path Inspection ScopePlus:
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
Replace flex seals/L-seals
Compressor and compressor Wear Repair
discharge case hooks
All cases exterior and interior Cracks Repair or monitor
Cases Exterior Slippage Casing alignment
Criteria Inspection Methods
O&M Manual	TILs Visual	Liquid Penetrant
GE Field Engineer Borescope	Ultrasonics
Figure 34. Gas turbine major inspection key elements
Inspect the exhaust frame mini-case and forward diffuser effect on both the component repair interval and service life.
mini-panel. For this reason, the intervals given in Appendix D should
only be used as guidelines and not certainties for long range
Check torque values for steam gland bolts and re-torque
parts planning. Owners may want to include contingencies in
to full values.
their parts planning.
Check alignment gas turbine to generator/gas turbine to
The estimated repair and replacement interval values reflect
accessory gear.
current production hardware (the typical case) with design
Inspect casings for signs of casing flange slippage. improvements such as advanced coatings and cooling technology.
Comprehensive inspection and maintenance guidelines have been With earlier production hardware, some of these lives may not be
developed by GE and are provided in the O&M Manual to assist achievable. Operating factors and experience gained during the
users in performing each of the inspections previously described. course of recommended inspection and maintenance procedures
will be a more accurate predictor of the actual intervals.
Parts Planning The estimated repair and replacement intervals are based on
Prior to a scheduled disassembly inspection, adequate spares the recommended inspection intervals shown in Figure 36.
should be on-site. Lack of adequate on-site spares can have For certain models, technology upgrades are available that
a major effect on plant availability. For example, a planned extend the maintenance inspection intervals. The application
outage such as a combustion inspection, which should only of inspection (or repair) intervals other than those shown in
take two to five days, could take weeks if adequate spares are Figure 36 can result in different replacement intervals than
not on-site. GE will provide recommendations regarding the those shown in Appendix D. See your GE service representative
types and quantities of spare parts needed; however, it is up for details on a specific system.
to the owner to purchase these spare parts on a planned basis
It should be recognized that, in some cases, the service life of a
allowing adequate lead times.
component is reached when it is no longer economical to repair
Early identification of spare parts requirements ensures their any deterioration as opposed to replacing at a fixed interval. This
availability at the time the planned inspections are performed. is illustrated in Figure 35 for a first stage nozzle, where repairs
Refer to the Reference Drawing Manual provided as part of the continue until either the nozzle cannot be restored to minimum
comprehensive set of O&M Manuals to aid in identification and acceptance standards or the repair cost exceeds or approaches
ordering of gas turbine parts. the replacement cost. In other cases, such as first-stage buckets,
Additional benefits available from the renewal parts catalog repair options are limited by factors such as irreversible material
data system are the capability to prepare recommended spare damage. In both cases, users should follow GE recommendations
parts lists for the combustion, hot gas path and major inspections regarding replacement or repair of these components.
as well as capital and operational spares. It should also be recognized that the life consumption of any
Estimated repair and replacement intervals for some of the one individual part within a parts set can have variations. This
major components are shown in Appendix D. These tables may lead to a certain percentage of fallout, or scrap, of parts
assume that operation, inspections, and repairs of the unit being repaired. Those parts that fallout during the repair process
have been done in accordance with all of the manufacturers will need to be replaced by new parts. Parts fallout will vary based
specifications and instructions. on the unit operating environment history, the specific part design,
and the current repair technology.
The actual repair and replacement intervals for any particular
gas turbine should be based on the users operating procedures,
experience, maintenance practices, and repair practices. The
maintenance factors previously described can have a major
GE Power | GER-3620N (10/17) 29
Repaired Nozzle 1st
Min. Acceptance Repair
Without Repair 3rd
Figure 35. First-stage nozzle repair program: natural gas fired continuous dry base load
Inspection Intervals under Contractual Service Agreements. This experience was
accumulated on units that operate with GE approved repairs,
In the absence of operating experience and resulting part
field services, monitoring, and full compliance to GEs technical
conditions, Figure 36 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 GE can assist operators in determining the appropriate
load, and no water/steam injection. These recommended intervals maintenance intervals for their particular application. Equations
represent factored hours or starts calculated using maintenance have been developed that account for the factors described earlier
factors to account for application specific operating conditions. and can be used to determine application-specific combustion,
Initially, recommended intervals are based on the expected hot gas path, and major inspection intervals.
operation of a turbine at installation, but this should be reviewed
and adjusted as operating and maintenance data are accumulated.
In addition to the planned maintenance intervals, which undertake
While reductions in the recommended intervals will result from the
scheduled inspections or component repairs or replacements,
factors described previously or unfavorable operating experience,
borescope inspections should be conducted to identify any
increases in the recommended intervals may also be considered
additional actions, as discussed in the sections Gas Turbine
where operating experience has been favorable.
Configuration Maintenance Features. Such inspections may identify
The condition of the combustion and hot gas path parts provides additional areas to be addressed at a future scheduled maintenance
a basis for customizing a program for inspection and maintenance. outage, assist with parts or resource planning, or indicate the
The condition of the compressor and bearing assemblies is the need to change the timing of a future outage. The BI should use all
key driver in planning a major inspection. Historical operation the available access points to verify the condition of the internal
and machine conditions can be used to tailor maintenance hardware. As much of the Major Inspection workscope as possible
programs such as site specific repair and inspection criteria to should be done using this visual inspection without dissassembly.
specific sites/machines. GE leverages these principles and Refer to Figure 3 for standard recommended BI frequency. Specific
accumulated site and fleet experience in a Condition Based concerns may warrant subsequent BIs in order to operate the unit
Maintenance program as the basis for maintenance of units to the next scheduled outage without teardown.
Hours/Starts
Type of hours/ 6B 7E 9E
Inspection starts MS3002K MS5001PA MS5002C, D 6B.03 7E.03 (6)
9E.03 (7) 9E.04 (10)
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) 32000/900 (11)
(Non-DLN)
Factored 8000/400 (3)(5) 8000/400 (3)(5) 12000/450 (5) 12000/450 (5) 12000/450 (5) 32000/900 (11)
Hot Gas Path Factored 24000/1200 (4) 24000/1200 (4)(5) 24000/1200 (4)(5) 24000/1200 (5) 24000/1200 (5) 24000/900 (5) 32000/900
Major Factored 48000/2400 48000/2400 (5)
48000/2400 (5)
64000/1800 (5)
Type of hours/ 6F 7F
Inspection starts 6F.01 6F.03 7F.03
Factored 8000/400
Factored 32000/900 12000/450 (5) 24000/900
Hot Gas Path Factored 32000/900 24000/900 24000/900
Major Factored 64000/1800 48000/2400 48000/2400
Type of hours/ 7F 9F
Inspection starts 7F.04 7FB.04 7F.05 9F.03 9F.04 9F.05
Factored 32000/950 (5) 32000/950 (5) 24000/900 24000/900 32000/1200 12000/450
Hot Gas Path Factored 32000/1250 32000/1250 24000/900 24000/900 32000/1200 24000/900
Major Factored 64000/2500 64000/2500 48000/2400 48000/2400 64000/2400 48000/2400
Type of hours/ 7HA 9HA
Inspection starts 7HA.01 (8)
7HA.02 (8)
9HA.01 (8) 9HA.02 (8)
Factored 25000/900 25000/720 25000/900 (9) 25000/720
Hot Gas Path Factored 25000/900 25000/720 25000/900 25000/720
Major Factored 50000/1800 50000/1440 50000/1800 50000/1440
Factors that can reduce 1.	Units with Lean Head End liners have a 5.	Upgraded technology (Extendor*, PIP, DLN 2.6+, Note:
maintenance intervals: 400-starts combustion inspection interval. etc) may have longer inspection intervals. Baseline inspection intervals reflect
Fuel 2.	Multiple Non-DLN configurations exist (Standard, 6.	Also applicable to 7121(EA) models. current production hardware, unless
MNQC, IGCC). The typical case is shown; however, otherwise noted, and operation
Load setting 7.	Applicable to non-AGP units only.
different quoting limits may exist on a machine in accordance with manufacturer
Steam/water injection 8.	Intervals assume Base Tfire specifications. They represent initial
and hardware basis. Contact a GE service
Peak load firing representative for further information. 9.	CI = 450 Starts for DLN2.6+ recommended intervals in the absence
operation 10.	Applicable to New Units of 9E.04 and Flange-to- of operating and condition experience.
3.	Combustion inspection without transition
Flange Upgrades For Repair/Replace intervals see
Trips piece removal. Combustion inspection with
transition pieces removal to be performed every 11.	Non-DLN Standard, DLN, and DLN with AFS
Start cycle Rotor maintenance intervals are
2 combustion inspection intervals. configurations exist. Contact a GE service
Hardware design 4.	Hot gas path inspection for factored hours representative for further information. calculated independently.
Off-frequency operation eliminated on units that operate on natural gas *Trademark of General Electric Company (*greater of 64000 FFH or 48000 actuals)
fuel without steam or water injection.
Figure 36. Baseline recommended inspection intervals: base load natural gas fuel dry
GE Power | GER-3620N (10/17) 31
Combustion Inspection Interval An hours-based combustion maintenance factor can be determined
Equations have been developed that account for the earlier from the equations given in Figure 37 as the ratio of factored hours
mentioned factors affecting combustion maintenance intervals. to actual operating hours. Factored hours considers the effects of
These equations represent a generic set of maintenance factors fuel type, load setting, and steam/water injection. Maintenance
that provide guidance on maintenance planning. As such, these factors greater than one reduce recommended combustion
equations do not represent the specific capability of any given inspection intervals from those shown in Figure 36 representing
combustion system. For combustion parts, the baseline operating baseline operating conditions. To obtain a recommended inspection
conditions that result in a maintenance factor of one are normal
Starts-Based Combustion Inspection
fired startup and shutdown (no trip) to base load on natural gas fuel
Baseline CI (Figure 36)
without steam or water injection. Maintenance Interval	=
Hours-Based Combustion Inspection Factored Starts
Maintenance Interval	= Factored Starts = (Ki Afi Ati Api Asi Ni ), i = 1 to n Start/Stop Cycles
Actual Starts = (Ni ), i = 1 to n in Start/Stop Cycles
Factored Hours
Maintenance Factor = Where:
i =	Discrete Start/Stop Cycle (or Operating Practice)
Factored Hours = (Ki Afi Api ti ), i = 1 to n in Operating Modes
Ni = Start/Stop Cycles in a Given Operating Mode
Actual Hours = (ti ), i = 1 to n in Operating Modes Asi	= Start Type Severity Factor
Where: As = 1.0 for Normal Start
i =	Discrete Operating mode (or Operating Practice As = For Peaking-Fast Start See Figure 13
of Time Interval) Api = Load Severity Factor
ti	=	Operating hours at Load in a Given Operating mode Ap = 1.0 up to Base Load
Api	=	Load Severity factor Ap = exp (0.009 x Peak Firing Temp Adder in F)
Ap = 1.0 up to Base Load for Peak Load
Ap = For Peak Load Factor See Figure 10 Ati = Trip Severity Factor
Af i = Fuel Severity Factor At = 0.5 + exp(0.0125*%Load) for Trip
Af = 1.0 for Natural Gas Fuel (1) At = 1 for No Trip
Af = 1.5 for Distillate Fuel, Non-DLN (2.5 for DLN) Af i = Fuel Severity Factor
Af = 2.5 for Crude (Non-DLN) Af =	1.0 for Natural Gas Fuel
Af = 3.5 for Residual (Non-DLN) Af = 1.25 for Non-DLN (or 1.5 for DLN) for Distillate Fuel
Ki = Water/Steam Injection Severity Factor Af = 2.0 for Crude (Non-DLN)
(% Steam Referenced to Compressor Inlet Air Flow, Af = 3.0 for Residual (Non-DLN)
w/f = Water to Fuel Ratio) Ki = Water/Steam Injection Severity Factor
K = Max(1.0, exp(0.34(%Steam 2.00%))) (% Steam Referenced to Compressor Inlet Air Flow,
for Steam, Dry Control Curve w/f = Water to Fuel Ratio)
K = Max(1.0, exp(0.34(%Steam 1.00%))) K = Max(1.0, exp(0.34(%Steam 1.00%)))
for Steam, Wet Control Curve for Steam, Dry Control Curve
K = Max(1.0, exp(1.80(w/f 0.80))) K = Max(1.0, exp(0.34(%Steam 0.50%)))
for Water, Dry Control Curve for Steam, Wet Control Curve
K = Max(1.0, exp(1.80(w/f 0.40))) K = Max(1.0, exp(1.80(w/f 0.40)))
for Water, Wet Control Curve for Water, Dry Control Curve
(1) Af = 10 for DLN 1/DLN 1+ extended lean-lean, and DLN 2.0/ DLN 2+ K = Max(1.0, exp(1.80(w/f 0.20)))
extended piloted premixed operating modes. for Water, Wet Control Curve
Figure 37. Combustion inspection hours-based maintenance factors Figure 38. Combustion inspection starts-based maintenance factors
interval for a specific application, the maintenance factor is divided Syngas units require unit-specific intervals to account for unit-
into the recommended baseline inspection interval. specific fuel constituents and water/steam injection schedules.
As such, the combustion inspection interval equations may not
A starts-based combustion maintenance factor can be determined
apply to those units.
from the equations given in Figure 38 and considers the effect of
fuel type, load setting, peaking-fast starts, trips, and steam/water
injection. An application-specific recommended inspection interval
The hours-based hot gas path criterion is determined from the
can be determined from the baseline inspection interval in Figure 36
equations given in Figure 39. With these equations, a maintenance
and the maintenance factor from Figure 38. Appendix B shows six
factor is determined that is the ratio of factored operating hours
example maintenance factor calculations using the above hours and
and actual operating hours. The factored hours consider the
starts maintenance factor equations.
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
Hours-Based HGP Inspection (typically 24,000 hour) case. To determine the application specific
maintenance interval, the maintenance factor is divided into the
Maintenance Interval	=	Baseline HGPI (Figure 36)
(Hours)	Maintenance Factor baseline hot gas path inspection interval, as shown in Figure 39.
The starts-based hot gas path criterion is determined from the
Maintenance Factor = equations given in Figure 40.
Factored Hours = ni=1 (Si Afi Api ti )
Actual Hours = ni=1 (ti )
i =	1 to n discrete operating modes (or operating practices
of time interval) Maintenance Interval	=	S
ti = Fired hours in a given operating mode (Starts)	Maintenance Factor
Api =	Load severity factor for given operating mode Where:
Ap	=	1.0 up to base load Factored Starts
Ap	=	For peak load factor see Figure 10. Maintenance Factor =
Af i =	Fuel severity factor for given operating mode Factored Starts = 0.5NA + NB + 1.3NP + PsF + ni=1 (aTi 1) Ti
Af =	1.0 for natural gas
Actual Starts = (NA + NB + NP)
Af = 1.5 for distillate
(=1.0 when Ap > 1, at minimum Af Ap = 1.5) S	=	Baseline Starts-Based Maintenance Interval (Figure 36)
Af = 2 to 3 for crude
NA	=	Annual Number of Part Load Start/Stop Cycles
Af = 3 to 4 for residual (<60% Load)
Si = Water/steam injection severity factor = Ki + (Mi Ii) NB	=	Annual Number of Base Load Start/Stop Cycles
I	= Percent water/steam injection referenced
to compressor inlet air flow NP	=	Annual Number of Peak Load Start/Stop Cycles
(>100% Load)
M&K = Water/steam injection constants
Ps	=	Peaking-Fast Start Factor (See Figure 13)
M K Control Water/Steam Inj. S2N/S3N Material
0 1 Dry <2.2% All F	=	Annual Number of Peaking-Fast Starts
0 1 Dry >2.2% Non-FSX-414 T	=	Annual Number of Trips
0.18 0.6 Dry >2.2% FSX-414
aT	=	Trip Severity Factor = f(Load) (See Figure 19)
0.18 1 Wet >0% Non-FSX-414
n	=	Number of Trip Categories (i.e. Full Load, Part Load, etc.)
0.55 1 Wet >0% FSX-414
Figure 39. Hot gas path maintenance interval: hours-based criterion Figure 40. Hot gas path maintenance interval: starts-based criterion
GE Power | GER-3620N (10/17) 33
As previously described, the limiting criterion (hours or starts) maintenance factor for all rotors and will act to increase the hours-
determines the maintenance interval. Examples of these equations based maintenance factor and to reduce the rotor maintenance
are in Appendix A. interval. For B/E-class units time on turning gear also affects rotor
life. For HA, rotor maintenance factor can be reduced via the use of
Legacy Alstom Inspection Intervals
technology, such as evaporative coolers.
Inspection intervals are primarily based on the hot gas path
lifetime (i.e. turbine and combustor) and determine the intervals of The starts-based rotor maintenance interval is determined from the
visual and major inspections. equations given in Figure 42. Adjustments to the rotor maintenance
interval are determined from rotor-based operating factors as
Counting Methods and Parameters
described previously. In the calculation for the starts-based rotor
Linear (initial BE-class)	EOH = (S*V + TPE*W + OH*X) * Z maintenance interval, equivalent starts are determined for cold,
Elliptical (initial F-class)	EOH = [ ((V*S)2 + (A*OH)2)*Z] warm, and hot starts over a defined time period by multiplying
the appropriate cold, warm, and hot start operating factors by the
Extended Linear (BEF-class)	EOH = WOH + 10x WCE
number of cold, warm, and hot starts respectively. Additionally,
(later upgrades new/service)	WOH = OH * X * Z / WCE = CE * V* Z
equivalent starts for rapid/forced/crank cool downs are added.
Box The total equivalent starts are divided by the actual number of
(future, latest F-upgrade)	WOH = OH * X * Z / WCE = CE * V* Z starts to yield the maintenance factor. The rotor starts-based
EOH Equivalent Operating Hours maintenance interval is determined by dividing the baseline rotor
WOH Weighted Operating Hours maintenance interval starts number by the calculated maintenance
OH Operating hours
WCE Weighted Cyclic Events
S Starts Maintenance Interval	=	R
(Hours)	Maintenance Factor
V, X, W, A Penalty factors
Z Fuel factor Factored Hours H + 2P(1) H + 2P + 2TG(2)
TPE, CE Protective/cyclic events MF = = =
Actual Hours H+P B/E-class H+P
Fuel and penalty factors are GT Type and upgrade specific
H = Non-peak load operating hours
Figure 41. Legacy Alstom Inspection Interval Counting Methods
P = Peak load operating hours
Rotor Inspection Interval TG = Hours on turning gear
Like hot gas path components, the unit rotor has a maintenance
R = Baseline rotor inspection interval
interval involving removal, disassembly, and inspection. This interval
Machine R(3)
indicates the serviceable life of the rotor and is generally considered
FA.05 & HA Class Refer to unit specific documentation.
to be the teardown inspection and repair/replacement interval for F-class 144,000
the rotor. The disassembly inspection is usually concurrent with a B & E Class 200,000
hot gas path or major inspection; however, it should be noted that
(1) Maintenance factor equation to be used unless otherwise notified in unit-
the maintenance factors for rotor maintenance intervals are distinct specific documentation.
from those of combustion and hot gas path components. As such, (2) To diminish potential turning gear impact, major inspections must include
the calculation of consumed life on the rotor may vary from that a thorough visual and dimensional examination of the hot gas path turbine
rotor dovetails for signs of wearing, galling, fretting, or cracking. If no
of combustion and hot gas path components. Customers should distress is found during inspection or after repairs are performed to the
dovetails, time on turning gear may be omitted from the hours-based
contact GE 1 to 2 years prior to their rotor reaching the end of its
serviceable life for technical advisement. (3) Baseline rotor inspection intervals to be used unless otherwise notified in
unit-specific documentation.
Figure 41 describes the procedure to determine the hours-based
maintenance criterion. Peak load operation is the primary hour Figure 42. Rotor maintenance interval: hours-based criterion
factor. The baseline rotor maintenance interval is also the maximum Welded Rotor Inspection Interval
interval, since calculated maintenance factors less than one are Rotors are constructed for at least 4 C-Inspections, based on a
not considered. defined mix of cold/warm/hot starts. Condition Based Maintenance
When the rotor reaches the earlier of the inspection intervals programs can be applied in order to increase the project specific
described in Figures 41 and 42, a GE Rotor Life Extension shall be rotor lifetime.
completed on the rotor components in both the compressor and
turbine. It should be expected that some rotor components will
either have reached the end of their serviceable life or will have a It is essential that personnel planning be conducted prior to an
minimal amount of residual life remaining and will require repair or outage. It should be understood that a wide range of experience,
replacement at this inspection point. Depending on the extent of productivity, and working conditions exist around the world.
refurbishment and part replacement, subsequent inspections may However, an estimate can be made based upon maintenance
be required at a reduced interval. inspection labor assumptions, such as the use of a crew of workers
with trade skill (but not necessarily direct gas turbine experience),
Starts-Based Rotor Inspection with all needed tools and replacement parts (no repair time)
available. These estimated craft labor hours should include controls/
Maintenance Interval	=	5,000(1)
(Starts)	Maintenance Factor accessories and the generator. In addition to the craft labor,
additional resources are needed for technical direction, specialized
Factored Starts tooling, engineering reports, and site mobilization/demobilization.
Inspection frequencies and the amount of downtime varies
For units with published start factors:
within the gas turbine fleet due to different duty cycles and the
Maintenance (Fh1 Nh1 + Fh2 Nh2 + Fw1 Nw1 + Fw2 Nw2 + Fc Nc + FFC NFC) economic need for a unit to be in a state of operational readiness.
Factor (N +N +N +N +N )
h1 h2 w1 w2 c
Contact your local GE service representative for the estimated
For B/E-class units labor hours and recommended crew size for your specific unit.
NS + (4 NFC)
NS Depending upon the extent of work to be done during each
For all other units additional start factors may apply. maintenance task, a cooldown period of 4 to 24 hours may be
Number of Starts Start Factors (2)
required before service may be performed. This time can be utilized
Nh1	=	Number of hot 1 starts Fh1	=	Hot 1 start factor (down 0-1 hr) productively for job move-in, correct tagging and locking equipment
Nh2	=	Number of hot 2 starts Fh2	=	Hot 2 start factor out-of-service, and general work preparations. At the conclusion of
Nw1	=	Number of warm (1 hour < downtime 4 hours)
the maintenance work and systems check out, a turning gear time
1 starts Fw1	=	Warm 1 start factor
Nw2	=	Number of warm
(4 hours < downtime 20 hours) of two to eight hours is normally allocated prior to starting the unit.
2 starts Fw2	=	Warm 2 start factor This time can be used for job clean-up and preparing for start.
(20 hours < downtime 40 hours)
Nc	=	Number of cold starts
NFC	=	Number of
Fc	=	Cold start factor Local GE field service representatives are available to help plan
Rapid/Forced/Crank maintenance work to reduce downtime and labor costs. This
FFC	=	Rapid/Forced/Crank Cooling
Cool Shutdowns
Shutdown Factor planned approach will outline the replacement parts that may be
Ns	=	Total number of
fired starts needed and the projected work scope, showing which tasks can
(1) Baseline rotor inspection interval for B, E, and F class rotors is 5,000 fired
be accomplished in parallel and which tasks must be sequential.
starts unless otherwise notified in unit-specific documentation. Refer to Planning techniques can be used to reduce maintenance cost by
unit specific documentation for FA.05 and HA class rotors for baseline
starts number.
optimizing lifting equipment schedules and labor requirements.
(2) Start factors for certain F-class units are tabulated in Figure 21. For all Precise estimates of the outage duration, resource requirements,
other machines, consult unit-specific documentation to determine if start critical-path scheduling, recommended replacement parts, and
costs associated with the inspection of a specific installation may
Figure 43. Rotor maintenance interval: starts-based criterion be sourced from the local GE field services office.
GE Power | GER-3620N (10/17) 35
GE heavy-duty gas turbines are constructed to have high Jarvis, G., Maintenance of Industrial Gas Turbines, GE Gas Turbine
availability. To achieve increased gas turbine availability, State of the Art Engineering Seminar, paper SOA-24-72, June 1972.
an owner must understand not only the equipment but also
Patterson, J. R., Heavy-Duty Gas Turbine Maintenance Practices,
the factors affecting it. This includes the training of operating
GE Gas Turbine Reference Library, GER-2498, June 1977.
and maintenance personnel, following the manufacturers
recommendations, regular periodic inspections, and the Moore, W. J., Patterson, J.R, and Reeves, E.F., Heavy-Duty Gas
stocking of spare parts for immediate replacement. The Turbine Maintenance Planning and Scheduling, GE Gas Turbine
recording and analysis of operating data is also essential Reference Library, GER-2498; June 1977, GER 2498A, June 1979.
to preventative and planned maintenance. A key factor Carlstrom, L. A., et al., The Operation and Maintenance of General
in achieving this goal is a commitment by the owner to Electric Gas Turbines, numerous maintenance articles/authors
provide effective outage management, to follow published reprinted from Power Engineering magazine, General Electric
maintenance instructions, and to utilize the available service Publication, GER-3148; December 1978.
Knorr, R. H., and Reeves, E. F., Heavy-Duty Gas Turbine
It should be recognized that, while the manufacturer Maintenance Practices, GE Gas Turbine Reference Library,
provides general maintenance recommendations, it is the GER-3412; October 1983; GER- 3412A, September 1984; and
equipment user who controls the maintenance and operation GER-3412B, December 1985.
of equipment. Inspection intervals for optimum turbine service
Freeman, Alan, Gas Turbine Advance Maintenance Planning,
are not fixed for every installation but rather are developed
paper presented at Frontiers of Power, conference, Oklahoma
based on operation and experience. In addition, through
State University, October 1987.
application of a Contractual Service Agreement to a particular
turbine, GE can work with a user to establish a maintenance Hopkins, J. P, and Osswald, R. F., Evolution of the Design,
program that may differ from general recommendations but Maintenance and Availability of a Large Heavy-Duty Gas Turbine,
will be consistent with contractual responsibilities. GE Gas Turbine Reference Library, GER-3544, February 1988
(never printed).
The level and quality of a rigorous maintenance program
have a direct effect on equipment reliability and availability. Freeman, M. A., and Walsh, E. J., Heavy-Duty Gas Turbine
Therefore, GE provides a knowledge based gas turbine user Operating and Maintenance Considerations, GE Gas Turbine
solution that reduces costs and outage time while improving Reference Library, GER-3620A.
reliability and profitability. GEI-41040, Fuel Gases for Combustion in Heavy-Duty
GEI-41047, Gas Turbine Liquid Fuel Specifications.
GEK-101944, Requirements for Water/Steam Purity in
GER-3419A, Gas Turbine Inlet Air Treatment.
GEK-32568, Lubricating Oil Recommendations for Gas Turbines
with Bearing Ambients Above 500F (260C).
GEK-110483, Cleanliness Requirements for Power Plant Installation,
Appendix Therefore, the steam severity factor for modes 1, 2, and 3 are
= S1 = S2 = S3 = K + (M I) = 1
A.1) Example 1 Hot Gas Path Maintenance
Interval Calculation From the hours-based criteria, the maintenance factor is
A 7E.03 user has accumulated operating data since the last hot determined from Figure 39.
gas path inspection and would like to estimate when the next ni=1 (Si Afi Api ti )
one should be scheduled. The user is aware from GE publications ni=1) (ti )
that the baseline HGP interval is 24,000 hours if operating on
(1 1 1 3200) + (1 1.5 1 350) + (1 1 6 120) + (2.3 1 1 20)
natural gas, with no water or steam injection, and at base load. =
(3200 + 350 + 120 + 20)
It is also understood that the baseline starts interval is 1200,
MF = 1.22
based on normal startups, no trips, no peaking-fast starts. The
actual operation of the unit since the last hot gas path inspection The hours-based adjusted inspection interval is therefore,
is much different from the baseline case. The unit operates in four Adjusted Inspection Interval = 24,000/1.22 = 19,700 hours
[Note, since total annual operating hours is 3690, the estimated
1.	The unit runs 3200 hrs/yr in its first operating mode, which is time to reach 19,700 hours is 19,700/3690 = 5.3 years.]
natural gas at base or part load with no steam/water injection.
Also, since the last hot gas path inspection the unit has averaged
2.	The unit runs 350 hrs/yr in its second operating mode, which is 145 normal start-stop cycles per year, 5 peaking-fast start cycles
distillate fuel at base or part load with no steam/water injection. per year, and 20 base load cycles ending in trips (aT = 8) per year.
3.	The unit runs 120 hrs/yr in its third operating mode, which is The starts-based hot gas path maintenance interval parameters
natural gas at peak load (+100F) with no steam/water injection. for this unit are summarized below:
4.	The unit runs 20 hrs/yr in its fourth operating mode, which is
Normal Start Peaking Fast Start
natural gas at base load with 2.4% steam injection on a wet
control curve. Normal Trip from Normal Trip from
Shutdown Load Shutdown Load
The hours-based hot gas path maintenance interval parameters for Part Load
40 0 0 0 NA 40
these four operating modes are summarized below: Cycles
Operating Mode (i) 100 20 5 0 NB 125
5 0 0 0 NP 5
Fired hours (hrs/yr) t 3200 350 120 20 Cycles
Fuel severity factor Af 1 1.5 1 1
From the starts-based criteria, the maintenance factor is
Load severity factor Ap 1 1 [e (0.018*100)] = 6 1 determined from Figure 40.
Steam/water injection rate (%) I 0 0 0 2.4 Ps = 5
For this particular unit, the second- and third-stage nozzles are FSX- F=5
414 material. From Figure 39, at a steam injection rate of 2.4% on a
wet control curve,
M4 = 0.55, K4 = 1 0.5NA + NB + 1.3NP + PsF + ni=1 (aTi - 1) Ti
NA + NB + NP
The steam severity factor for mode 4 is therefore,
= S4 = K4 + (M4 I4) = 1 + (0.55 2.4) = 2.3 0.5 (40) + 125 + 1.3 (5) + 3.5 (5) + (8 - 1 )20
40 + 125 + 5
At a steam injection rate of 0%,
M = 0, K = 1 MF = 1.8
GE Power | GER-3620N (10/17) 37
The adjusted inspection interval based on starts is Total Trips
Adjusted Inspection Interval = 1200/1.8 = 667 starts 5.	50% load (aT1 = 6.5), T1 = 5 + 1 = 6
[Note, since the total annual number of starts is 170, the estimated 6.	Base load (aT2 = 8), T2 = 35 + 2 = 37
time to reach 667 starts is 667/170 = 3.9 years.]
7.	Peak load (aT3 = 10), T3 = 10
In this case the unit would reach the starts-based hot gas path
interval prior to reaching the hours-based hot gas path interval.
Peaking-fast starts, F = 7
The hot gas path inspection interval for this unit is therefore
From the starts-based criteria, the total number of factored starts
667 starts (or 3.9 years).
(FS) and actual starts (AS) is determined from Figure 40.
A.2) Example 2 Hot Gas Path Factored Ps = 3.5
Starts Calculation F=7
A 7E.03 user has accumulated operating data for the past year of
operation. This data shows number of trips from part, base, and FS = 0.5NA + NB + 1.3NP + PsF + ni=1 (aTi - 1) Ti
peak load, as well as peaking-fast starts. The user would like to
= 0.5 41 + 66 + 1.3 50 + 3.5 7 + (6.5 - 1) 6 + (8 - 1) 37 + (10 - 1) 10 = 558
calculate the total number of factored starts in order to plan the
next HGP outage. Figure 40 is used to calculate the total number of AS = NA + NB + NP = 41 + 66 + 50 = 157
factored starts as shown below. FS 558
Maintenance Factor = = = 3.6
Normal Trip from Normal Trip from
35 0 1 5 NA 41
25 4 2 35 NB 66
40 0 0 10 NP 50
B) Examples Combustion Maintenance Interval
(reference Figures 37 and 38)
DLN 1 Peak Load with Power Augmentation Standard Combustor Base Load on Crude Oil
+50F Tfire Increase Natural Gas Fuel No Tfire Increase Crude Oil Fuel
3.5% Steam Augmentation 6 Hours/Start 1.0 Water/Fuel Ratio 220 Hours/Start
Peaking Start Wet Control Curve Normal Start Dry Control Curve
Normal Shutdown (No Trip) Normal Shutdown (No Trip)
Factored Hours = Ki * Afi * Api * ti = 34.5 Hours Factored Hours = Ki * Afi * Api * ti = 788.3 Hours
Hours Maintenance Factor = (34.5/6) 5.8 Hours Maintenance Factor = (788.3/220) 3.6
Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) Wet Where Ki = 1.43 Max(1.0, exp(1.80(1.00-0.80))) Dry
Afi = 1.00 Natural Gas Fuel Afi = 2.50 Crude Oil, Std (Non-DLN)
Api = 2.46 exp(0.018(50)) Peak Load Api = 1.00 Base Load
ti = 6.0 Hours/Start ti = 220.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 17.4 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.9 Starts
Starts Maintenance Factor = (17.4/1) 17.4 Starts Maintenance Factor = (5.9/1) 5.9
Where Ki = 2.77 Max(1.0, exp(0.34(3.50-0.50))) Wet Where Ki = 2.94 Max(1.0, exp(1.80(1.00-0.40))) Dry
Afi = 1.00 Natural Gas Fuel Afi = 2.00 Crude Oil, Std (Non-DLN)
Ati = 1.00 No Trip at Load Ati = 1.00 No Trip at Load
Api = 1.57 exp(0.009(50)) Peak Load Api = 1.00 Base Load
Asi = 4.0 Peaking Start Asi = 1.00 Normal Start
Ni = 1.0 Considering Each Start Ni = 1.0 Considering Each Start
DLN 2.6 Base Load on Distillate DLN 2.6 Base Load on Natural Gas with Trip @ Load
No Tfire Increase Distillate Fuel No Tfire Increase Natural Gas Fuel
1.1 Water/Fuel Ratio 220 Hours/Start No Steam/Water Injection 168 Hours/Start
Normal Start Dry Control Curve Normal Start Dry Control Curve
Normal Shutdown (No Trip) Trip @ 60% Load
Factored Hours = Ki * Afi * Api * ti = 943.8 Hours Factored Hours = Ki * Afi * Api * ti = 168.0 Hours
Hours Maintenance Factor = (943.8/220) 4.3 Hours Maintenance Factor = (168.0/168) 1.0
Where Ki = 1.72 Max(1.0, exp(1.80(1.10-0.80))) Dry Where Ki = 1.00 No Injection
Afi = 2.50 Distillate Fuel, DLN Afi = 1.00 Natural Gas Fuel
Api = 1.00 Base Load Api = 1.00 Base Load
ti = 220.0 Hours/Start ti = 168.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 5.3 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 2.6 Starts
Starts Maintenance Factor = (5.3/1) 5.3 Starts Maintenance Factor = (2.6/1) 2.6
Where Ki = 3.53 Max(1.0, exp(1.80(1.10-0.40))) Dry Where Ki = 1.00 No Injection
Afi = 1.50 Distillate Fuel, DLN Afi = 1.00 Natural Gas Fuel
Ati = 1.00 No Trip at Load Ati = 2.62 0.5+exp(0.0125*60) for Trip
Asi = 1.00 Normal Start Asi = 1.00 Normal Start
DLN 1 Combustor Base Load on Distillate DLN 2.6 Peak Load on Natural Gas with Peaking Start
No Tfire Increase Distillate Fuel +35F Tfire Increase Natural Gas Fuel
0.9 Water/Fuel Ratio 500 Hours/Start 3.5% Steam Augmentation 4 Hours/Start
Normal Start Dry Control Curve Peaking Start Dry Control Curve
Factored Hours = Ki * Afi * Api * ti = 1496.5 Hours Factored Hours = Ki * Afi * Api * ti = 12.5Hours
Hours Maintenance Factor = (1496.5/500) 3.0 Hours Maintenance Factor = (12.5/4) 3.1
Where Ki = 1.20 Max(1.0, exp(1.80(0.90-0.80))) Dry Where Ki = 1.67 Max(1.0, exp(0.34(3.50-2.00)))
Afi = 2.50 Distillate Fuel, DLN 1 Afi = 1.00 Natural Gas Fuel
Api = 1.00 Part Load Api = 1.88 exp(0.018(35)) Peak Load
ti = 500.0 Hours/Start ti = 4.0 Hours/Start
Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 3.7 Starts Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 12.8 Starts
Starts Maintenance Factor = (3.7/1) 3.7 Starts Maintenance Factor = (12.8/1) 12.8
Where Ki = 2.46 Max(1.0, exp(1.80(0.90-0.40))) Dry Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) Dry
Api = 1.00 Part Load Api = 1.37 exp(0.009(35)) Peak Load
Asi = 1.00 Normal Start Asi = 4.0 Peaking Start
GE Power | GER-3620N (10/17) 39
C) Definitions Equivalent Availability: Probability of a multi-shaft
Reliability: Probability of not being forced out of combined-cycle power plant being available for power
service when the unit is needed includes forced generation independent of whether the unit is
outage hours (FOH) while in service, while on needed includes all unavailable hours includes
reserve shutdown and while attempting to start the effect of the gas and steam cycle MW output
normalized by period hours (PH) units are %. contribution to plant output; units are %.
Reliability = (1-FOH/PH) (100)
FOH = total forced outage hours GT UH HRSG UH ST UH
[1 +B + x 100 ]
PH = period hours GT PH GT PH ST PH
GT UH = Gas Turbine Unavailable Hours
Availability: Probability of being available,
GT PH = Gas Turbine Period Hours
independent of whether the unit is needed includes
HRSG UH = HRSG Total Unavailable Hours
all unavailable hours (UH) normalized by period
hours (PH) units are %: ST UH = Steam Turbine Unavailable Hours
Availability = (1-UH/PH) (100) ST PH = Steam Turbine Period Hours
UH = total unavailable hours (forced outage, B = Steam Cycle MW Output
failure to start, scheduled maintenance Contribution (normally 0.30)
hours, unscheduled maintenance hours)
MTBFMean Time Between Failure: Measure of
PH = period hours probability of completing the current run. Failure
events are restricted to forced outages (FO) while in
Equivalent Reliability: Probability of a multi-shaft service units are operating hours.
combined-cycle power plant not being totally forced
MTBF = OH/FO
out of service when the unit is required includes the
effect of the gas and steam cycle MW output OH = Operating Hours
contribution to plant output units are %. FO = Forced Outage Events from a Running
(On-line) Condition
Equivalent Reliability =
GT FOH HRSG FOH ST FOH Service Factor: Measure of operational use, usually
[1 +B + x 100 ] expressed on an annual basis units are %.
GT PH B PH ST PH
SF = OH/PH x 100
GT FOH = Gas Turbine Forced Outage Hours OH = Operating Hours on an annual basis
GT PH = Gas Turbine Period Hours PH = Period Hours (8760 hours per year)
HRSG FOH = HRSG Forced Outage Hours
Operating Duty Definition:
B PH = HRSG Period Hours Duty Service Factor Fired Hours/Start
ST FOH = Steam Turbine Forced Outage Hours Stand-by < 1% 1 to 4
ST PH = Steam Turbine Period Hours Peaking 1% 17% 3 to 10
Cycling 17% 50% 10 to 50
B = Steam Cycle MW Output
Continuous > 90% >> 50
Contribution (normally 0.30)
D) Estimated Repair and Replacement Intervals
Repair/replace intervals reflect current production hardware, unless 6B.03
otherwise noted, and operation in accordance with manufacturer Repair Interval Replace Interval (Hours) Replace Interval (Starts)
Combustion Liners Cl 4 (Cl) 4 (Cl) / 5 (Cl)(1)
specifications. Consult previous revisions of GER 3620 or other unit-
Caps Cl 4 (Cl) 5 (Cl)
specific documentation for estimated repair/replacement intervals Transition Pieces Cl 4 (Cl) 4 (Cl) / 5 (Cl)(1)
of previous generation gas turbine models and hardware. Consult Fuel Nozzles Cl 2 (Cl) 2 (Cl) / 3 (Cl)(4)
your GE service representative for further information. Crossfire Tubes Cl 1 (CI) 1 (CI)
Crossfire Tube CI 1 (CI) 1 (CI)
MS3002K Parts
Flow Divider Cl 3 (Cl) 3 (Cl)
Repair Interval Replace Interval (Hours) Replace Interval (Starts) (Distillate)
Combustion Liners CI 4 (CI) 4 (CI) Fuel Pump Cl 3 (Cl) 3 (Cl)
Transition Pieces CI(1) 4 (CI) 4 (CI) (Distillate)
Stage 1 Nozzles (HGPI)(2) 4 (HGPI) 2 (HGPI) Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Nozzles (HGPI)(2) 4 (HGPI) 4 (HGPI) Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 1 Shrouds (HGPI)(2) 4 (HGPI) 4 (HGPI) Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Shrouds (HGPI)(2) 4 (HGPI) 4 (HGPI) Stage 1 Shrouds HGPI 3 (HGPI) 2 (HGPI)
Stage 1 Buckets (3) 2 (HGPI)(3) 2 (HGPI) Stage 2 Shrouds HGPI 3 (HGPI) 4 (HGPI)
Stage 2 Buckets (HGPI)(2) 4 (HGPI) 4 (HGPI) Stage 3 Shrouds HGPI 3 (HGPI) 4 (HGPI)
Note: Repair/replace intervals reflect current production hardware, unless otherwise noted, and operation Stage 1 Buckets HGPI 3 (HGPI)(2) 3 (HGPI)
in accordance with manufacturer specifications. They represent initial recommended intervals in the
absence of operating and condition experience. For factored hours and starts of the repair intervals, refer
Stage 2 Buckets HGPI 3 (HGPI)(3) 4 (HGPI)
to Figure 36. Stage 3 Buckets HGPI 3 (HGPI) 4 (HGPI)
CI = Combustion Inspection Interval Note: Repair/replace cycles reflect current production (6B.03) hardware, unless otherwise noted, and
HGPI = Hot Gas Path Inspection Interval
operation in accordance with manufacturer specifications. They represent initial recommended intervals
(1)	Repair interval is every 2 combustion inspection intervals. in the absence of operating and condition experience. For factored hours and starts of the repair intervals,
(2)	Repair interval is every 2 hot gas path inspection intervals with the exception of 1st stage nozzle refer to Figure 36.
start-based repair interval where repair interval is one inspection interval.
Cl = Combustion Inspection Interval
(3)	No repair required. GE approved repair at 24,000 factored hours may extend replace interval to
72000 factored hours.
(1)	4 (CI) for non-DLN / 5 (CI) for DLN
Figure D-1. Estimated repair and replacement intervals (2)	3 (HGPI) with strip and recoat at first HGPI
(3)	3 (HGPI) for current design only. Consult your GE Energy representative for replace intervals by part
(4)	2 (CI) for non-DLN / 3 (CI) for DLN
Figure D-3. Estimated repair and replacement intervals
Repair Interval Replace Interval (Hours) Replace Interval (Starts)
Combustion Liners CI 4 (CI) 3 (CI)
Transition Pieces CI(1) 4 (CI) 4 (CI)(5)
Stage 1 Nozzles HGPI(2) 4 (HGPI) 2 (HGPI)
Stage 2 Nozzles HGPI(2) 4 (HGPI) 4 (HGPI)
Stage 1 Shrouds HGPI(2) 4 (HGPI) 4 (HGPI)
Stage 2 Shrouds (3) 4 (HGPI) 4 (HGPI)
Stage 1 Buckets (4) 2 (HGPI)(4) 2 (HGPI)
Stage 2 Buckets HGPI(2) 4 (HGPI) 4 (HGPI)
Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation
to Figure 36.
CI = Combustion Inspection Interval
(1)	Repair interval is every 2 combustion inspection intervals.
(2)	Repair interval is every 2 hot gas path inspection intervals with the exception of 1st stage nozzle start-
based repair interval where repair interval is one inspection interval.
(3)	No repair required
(4)	No repair required. GE approved repair at 24,000 factored hours may extend replace interval to 72000
(5)	6 replace intervals (starts-based) for DLN and lean head end (LHE) units.
Figure D-2. Estimated repair and replacement intervals
GE Power | GER-3620N (10/17) 41
7E.03 (7) 9E.03 (6)
Repair Interval Replace Interval (Hours) Replace Interval (Starts) Repair Interval Replace Interval (Hours) Replace Interval (Starts)
Combustion Liners Cl 3 (Cl) / 5 (Cl)(1) 5 (Cl) Combustion Liners Cl 3 (Cl) / 5 (Cl)(1) 5 (Cl)
Caps Cl 3 (Cl) 5 (Cl) Caps Cl 3 (Cl) 5 (Cl)
Transition Pieces Cl 4 (Cl) / 6 (Cl)(5) 6 (Cl) Transition Pieces Cl 4 (Cl) / 6 (Cl)(4) 6 (Cl)
Fuel Nozzles Cl 2 (Cl) / 3 (Cl)(6) 3 (Cl) Fuel Nozzles Cl 2 (Cl) / 3 (Cl)(5) 3 (Cl)
Crossfire Tubes Cl 1 (Cl) 1 (Cl) Crossfire Tubes Cl 1 (Cl) 1 (Cl)
Crossfire Tube CI 1 (CI) 1 (CI) Crossfire Tube CI 1 (CI) 1 (CI)
Retaining Clips Retaining Clips
Flow Divider Cl 3 (Cl) 3 (Cl) Flow Divider Cl 3 (Cl) 3 (Cl)
(Distillate) (Distillate)
Fuel Pump Cl 3 (Cl) 3 (Cl) Fuel Pump Cl 3 (Cl) 3 (Cl)
Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI) Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI) Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI) Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI) Stage 1 Shrouds HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Shrouds HGPI 3 (HGPI) 4 (HGPI) Stage 2 Shrouds HGPI 3 (HGPI) 4 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI) 4 (HGPI) Stage 3 Shrouds HGPI 3 (HGPI) 4 (HGPI)
Stage 1 Buckets HGPI 3 (HGPl)(2)(3) 3 (HGPI) Stage 1 Buckets HGPI 3 (HGPl)(2) 3 (HGPI)
Stage 2 Buckets HGPI 3 (HGPl)(4) 4 (HGPI) Stage 2 Buckets HGPI 3 (HGPl)(3) 4 (HGPI)
Stage 3 Buckets HGPI 3 (HGPl) 4 (HGPI) Stage 3 Buckets HGPI 3 (HGPl) 4 (HGPI)
Note: Repair/replace intervals reflect current production (7121(EA) or 7E.03) hardware, unless otherwise Note: Repair/replace intervals reflect current production (9171(E)) hardware, unless otherwise noted, and
noted, and operation in accordance with manufacturer specifications. They represent initial recommended operation in accordance with manufacturer specifications. They represent initial recommended intervals
intervals in the absence of operating and condition experience. For factored hours and starts of the repair in the absence of operating and condition experience. For factored hours and starts of the repair intervals,
intervals, refer to Figure 36. refer to Figure 36.
Cl = Combustion Inspection Interval Cl = Combustion Inspection Interval
HGPI = Hot Gas Path Inspection Interval HGPI = Hot Gas Path Inspection Interval
(1)	3 (CI) for DLN / 5 (CI) for non-DLN (1)	3 (CI) for DLN / 5 (CI) for non-DLN
(2)	Strip and Recoat is required at first HGPI to achieve 3 HGPI replace interval. (2)	Strip and Recoat is required at first HGPI to achieve 3 HGPI replace interval.
(3)	Uprated 7E machines (2055 Tfire) require HIP rejuvenation at first HGPI to achieve 3 HGPI replace (3)	3 (HGPI) interval requires meeting tip shroud engagement criteria at prior HGP repair intervals.
interval. Consult your GE service representative for details.
(4)	3 (HGPI) interval requires meeting tip shroud engagement criteria at prior HGP repair intervals. (4)	4 (CI) for DLN / 6 (CI) for non-DLN
Consult your GE service representative for details. (5)	2 (CI) for DLN / 3 (CI) for non-DLN
(5)	4 (CI) for DLN / 6 (CI) for non-DLN (6)	Applicable to non-AGP units only
(6)	2 (CI) for DLN / 3 (CI) for non-DLN
(7)	Also applicable to 7121(EA) models.
Figure D-5. Estimated repair and replacement intervals
Figure D-4. Estimated repair and replacement intervals
6F.03 7F.04/7FB.04
Combustion Liners CI 2 (CI) 2 (CI) Combustion Liners Cl 2 (Cl) 2 (Cl)
Caps CI 3 (CI) 2 (CI) Caps Cl 2 (Cl) 2 (Cl)
Transition Pieces CI 3 (CI) 2 (CI) Transition Pieces Cl 2 (Cl) 2 (Cl)
Fuel Nozzles CI 2 (CI) 2 (CI) Fuel Nozzles Cl 2 (Cl) 2 (Cl)
Crossfire Tubes CI 1 (CI) 1 (CI) Crossfire Tubes Cl 1 (Cl) 1 (Cl)
End Covers CI 4 (CI) 2 (CI) End Covers CI 2 (Cl) 2 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 2 Nozzles HGPI 3 (HGPI) 3 (HGPI)
Stage 3 Nozzles HGPI 3 (HGPI) 3 (HGPI) Stage 3 Nozzles HGPI 4 (HGPI) 4 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI) Stage 2 Shrouds HGPI 3 (HGPI) 3 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI) Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGP)
Stage 1 Buckets HGPI 3 (HGPI) 2 (HGPI) Stage 1 Buckets HGPI 3 (HGPI) 3 (HGPI)
Stage 2 Buckets HGPI 3 (HGPI) 2 (HGPI) Stage 2 Buckets HGPI 3 (HGPI) 3 (HGPI)
Stage 3 Buckets HGPI 2 (HGPI) 3 (HGPI) Stage 3 Buckets HGPI 3 (HGPI) 3 (HGPI)
Note: Repair/replace intervals reflect current production (6F.03 DLN 2.6) hardware, unless otherwise Note: Repair/replacement intervals reflect current production (7F.04 DLN 2.6) hardware, unless otherwise
noted, and operation in accordance with manufacturer specifications. They represent initial recommended noted, and operation in accordance with manufacturer specifications. They represent initial recommended
intervals in the absence of operating and condition experience. For factored hours and starts of the repair intervals in the absence of operating and condition experience. For factored hours and starts of the repair
intervals, refer to Figure 36. intervals, refer to Figure 36.
CI = Combustion Inspection Interval Cl = Combustion Inspection Interval
Figure D-6. Estimated repair and replacement intervals Figure D-8. Estimated repair and replacement intervals
7F.03 7FB.01
Combustion Liners Cl 2 (Cl) 2 (Cl) Combustion Liners Cl 2 (Cl) 3 (Cl)
Caps Cl 2 (Cl) 2 (Cl) Caps Cl 2 (Cl) 3 (Cl)
Transition Pieces Cl 2 (Cl) 2 (Cl) Transition Pieces Cl 2 (Cl) 3 (Cl)
Fuel Nozzles Cl 2 (Cl) 2 (Cl) Fuel Nozzles Cl 2 (Cl)(1) 3 (Cl)(1)
End Covers CI 2 (Cl) 2 (Cl) End Covers CI 3 (Cl) 3 (Cl)
Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 2 Nozzles HGPI 1 (HGPI) 1 (HGPI)
Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI) Stage 1 Shrouds HGPI 2 (HGPI) 2 (HGPI)
Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI) Stage 2 Shrouds HGPI 2 (HGPI) 2 (HGPI)
Stage 1 Buckets HGPI 3 (HGPI)(2) 2 (HGPI)(4) Stage 1 Buckets HGPI 1 (HGPI) 1 (HGPI)
Stage 2 Buckets HGPI 3 (HGPI)(1) 3 (HGPI)(1) Stage 2 Buckets HGPI 3 (HGPI) 3 (HGPI)
Stage 3 Buckets HGPI 3 (HGPI)(3) 3 (HGPI) Stage 3 Buckets HGPI 3 (HGPI) 3 (HGPI)
Note: Repair/replace intervals reflect current production (7F.03 DLN 2.6 24k Super B and non-AGP) Note: Repair/replace cycles reflect current production (7251(FB) DLN 2.0+ extended interval) hardware,
hardware, unless otherwise noted, and operation in accordance with manufacturer specifications. They unless otherwise noted, and operation in accordance with manufacturer specifications. They represent
represent initial recommended intervals in the absence of operating and condition experience. For factored initial recommended intervals in the absence of operating and condition experience. For factored hours and
hours and starts of the repair intervals, refer to Figure 36. starts of the repair intervals, refer to Figure 36.
(1)	3 (HGPI) for current design. Consult your GE service representative for replacement intervals by part number. (1)	Blank and liquid fuel cartridges to be replaced at each CI
(2)	GE approved repair procedure required at first HGPI for designs without platform cooling.
(3)	GE approved repair procedure at 2nd HGPI is required to meet 3 (HGPI) replacement life. Figure D-9. Estimated repair and replacement intervals
(4)	2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned
bucket with platform undercut and cooling modifications.
Figure D-7. Estimated repair and replacement intervals
GE Power | GER-3620N (10/17) 43
9F.03 9F.05
Combustion Liners Cl 2 (Cl) 3 (Cl) Combustion Liners CI 4 (CI) 4 (CI)
Caps Cl 2 (Cl) 3 (Cl) Caps CI 4 (CI) 4 (CI)
Transition Pieces Cl 2 (Cl) 3 (Cl) Transition Pieces CI 4 (CI) 4 (CI)
Fuel Nozzles Cl 2 (Cl)(1) 3 (Cl)(1) Fuel Nozzles CI 2 (Cl)(1) 2 (CI)(1)
Crossfire Tubes Cl 1 (Cl) 1 (Cl) Crossfire Tubes CI 1 (Cl) 1 (Cl)
End Covers CI 2 (Cl) 3 (Cl) End Covers CI 4 (CI) 4 (CI)
Stage 1 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 1 Nozzles HGPI 1 (HGPI) 1 (HGPI)
Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI) Stage 2 Nozzles HGPI 2 (HGPI) 2 (HGPI)
Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI) Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGPI)
Stage 1 Buckets HGPI 2 (HGPI)(2) 2 (HGPI)(4) Stage 1 Buckets HGPI 1 (HGPI) 1 (HGPI)
Stage 2 Buckets HGPI 3 (HGPI)(5) 3 (HGPI)(3) Stage 2 Buckets HGPI 1 (HGPI) 1 (HGPI)
Stage 3 Buckets HGPI 3 (HGPI)(5) 3 (HGPI) Stage 3 Buckets HGPI 1 (HGPI) 1 (HGPI)
Note: Repair/replace intervals reflect current production (9F.03 DLN 2.6+) hardware, unless otherwise Note: Repair/replace intervals reflect current production (9F.05) hardware, unless otherwise noted, and
Cl = Combustion Inspection Interval CI = Combustion Inspection Interval
(1) Blank and liquid fuel cartridges to be replaced at each CI (1)	Blank and liquid fuel cartridges to be replaced at each CI
(2)	2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned
Figure D-11. Estimated repair and replacement intervals
(3)	Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.
(4)	GE approved repair procedure at 1 (HGPI) is required to meet 2 (HGPI) replacement life.
(5)	GE approved repair procedure is required to meet 3 (HGPI) replacement life.
Figure D-10. Estimated repair and replacement intervals
E) Borescope Inspection Ports
1st Stg. LE 1st Stg. TE 2nd Stg. LE 2nd Stg. TE 3rd Stg. LE-Turbine
24.5 9.8 10.5 9.73 12
99.5 100.5 100.5 189.73 102
Compressor 204.5 170.2 160.5 155
15th, 16th, 17th Stage
Primary Inspection Access
(Normal Inspection)
Secondary Inspection Access
(Additional Stators and Nozzles)
0-6th Stage
Figure E-1. Borescope inspection access locations for 6FA.03
66 15 151 66 62 130 64 39
14th, 15th, 16th Stage
0-5th Stage
Figure E-2. Borescope inspection access locations for 7F.03, 7F.04,7FB.01, 9F.03, 9F.05
GE Power | GER-3620N (10/17) 45
1st Nozzle TE 1st Bucket TE 2nd Nozzle TE 2nd Bucket TE 3rd Nozzle TE
1st Bucket LE 2nd Nozzle LE 2nd Bucket LE 3rd Nozzle LE 3rd Bucket LE
32 34 42 34 42
18 Compressor-17th Stage
18 (Normal Inspection)
Compressor-12th Stage
(Additional Stators & Nozzles)
Compressor-4th Stage Access for Eddy-current
& Nozzle Deflection Inspection
TE = Trailling Edge
Figure E-3. 7E.03 gas turbine borescope inspection access locations
100 80 90 157.5 82.5
Borescope Inspection Access
Compressor Compressor Turbine
1st-7th Stage 8th-14th Stage 1st-4th Stage
Figure E-4. 7HA.01 gas turbine borescope inspection access locations
Figure E-5. 6FA.03 Borescope port locations
Figure E-6. Typical arrangement. See unit specific information.
GE Power | GER-3620N (10/17) 47
(or Ratchet) Duration
Following Shutdown:
Until wheelspace temperatures <150F.(1)
Case A.1 Normal.
Rotor classified as unbowed.
Restart anticipated for >48 hours
Minimum 24 hours.(2)
Case A.2 Normal. Continuously until restart. Rotor
Restart anticipated for <48 hours unbowed.
Case B Immediate rotor stop
necessary. (Stop >20 minutes)
None. Classified as bowed.
Suspected rotating hardware damage
or unit malfunction
Case C Hot rotor,
01 hour(3)
<20 minutes after rotor stop
Case D Warm rotor, >20 minutes
& <6 hours after rotor stop
Case E.1 Cold rotor, unbowed,
off TG <48 hours
Case E.2 Cold rotor, unbowed,
off TG >48 hours
Case F Cold rotor, bowed 8 hours(4)
During Extended Outage:
Case G When idle 1 hour daily
No TG; 1 hour/week at full speed
Case H Alternative
(no load).(5)
(1) Time depends on frame size and ambient environment.
(2) Cooldown cycle may be accelerated using starting device for forced cooldown. Turning gear, however,
is recommended method.
(3) 1 hour on turning gear is recommended following a trip, before restarting. For normal shutdowns,
(4) Follow bowed rotor startup procedure, which may be found in the unit O&M Manual.
(5) Avoids high cycling of lube oil pump during long outages.
G) B/E-, F-, and H-class Gas Turbine Naming
Frame New Names Former Names
6FA PG6101FA 6FA.01
6F 6F.03 6F 3-Series 6F-3 6FA+e PG6111FA 6FA.03
6F Syngas
7FA PG7221FA 7FA.01
7FA+ PG7231FA 7FA.02
7F.03 7FA+E PG7241FA 7FA.03
7F 3-Series 7F-3
7F 7F.04 7FA.04 7FA AGP
7F Syngas
7F.05 7F 5-Series 7F-5 7FA.05
7HA.01 7F 7-Series 7F-7 FE60
7HA.02
9FA PG9311FA 9FA.01
9FA+ PG9331FA 9FA.02
9F 3-Series 9F-3
9F.03 9FA+e PG9351FA 9FA.03
9F 9F.04 9FA.04 9FA AGP
9FB.01 9FB DLN 2+
9F 5-Series 9F-5 9FB.02
9F.05 9FB.03 9FB DLN 2+
9HA.01 9F 7-Series 9F-7 9FB.05 FE50
PG6521B
PG6531B
PG6551B
6B 6B 3-Series 6B-3
PG6571B
6B.03 PG6581B
6B.03 PIP
6F.01 6F.01 6C 6C 6C PG6591C
7EA 7E 3-Series 7E-3 PG7121EA
7E.03 7EA-PIP
7H 7H.01 7H 7-Series 7H-7 7H GS7072
9E PG9141E
9E PG9151E
9E PG9161E
9E 3-Series 9E-3 9E PG9171E
9E PIP
9E.03 9E AGP
9E 9E Syngas
9E.04/9E Max
9EC 9EC.01 9E 5-Series 9E-5 9EC GS9053
9H GS9048 Commercial/Block 2
9H 9H.02 9H 7-Series 9H-7 9H B2A GS9069 Block 2A
G9069S Block 2A Spares
Figure G-1. B/E-, F-, and H-class Turbine Naming
GE Power | GER-3620N (10/17) 49
9/89 Original Procedural clarifications for HGP inspection added
8/91 Rev A Added inspections for galling/fretting in turbine dovetails to
major inspection scope
9/93 Rev B
HGP factored starts calculation updated for application of trip
3/95 Rev C
Nozzle Clearances section removed
Turning gear maintenance factor removed for F-class hours-
Steam/Water Injection section added based rotor life
Cyclic Effects section added Removed reference to turning gear effects on cyclic
5/96 Rev D customers rotor lives
Estimated Repair and Replacement Cycles added for F/FA HGP factored starts example added
F-class borescope inspection access locations added
11/96 Rev E Various HGP parts replacement cycles updated and additional
11/98 Rev F 6B table added
Rotor Parts section added Revision History added
Estimated Repair and Replace Cycles added for FA+E
11/09 Rev L
Starts and hours-based rotor maintenance interval equations
Updated text throughout
Casing section added
9/00 Rev G Exhaust Diffuser section added
11/02 Rev H Added new Fig. 26: F-class axial diffuser
Estimated Repair and Replace Cycles updated and moved to Added new Fig. 27: E-class radial diffuser
Appendix D Revised Fig. 3, 5, 7, 8, 11, 19, 20, 23, 35, 37, 38, 40, 41, 42, 43,
Combustion Parts section added 44, E-1, and E-2
Inlet Fogging section added Appendix D updated repair and replacement cycles
Added PG6111 (FA) Estimated repair and replacement cycles
1/03 Rev J
Added PG9371 (FB) Estimated repair and replacement cycles
Off Frequency Operation section added
10/10 Correction L.1
10/04 Rev K
Corrected Fig. D-4, D-5, and D-11 combustion hardware repair
GE design intent and predication upon proper components
and replacement cycles
and use added
Added recommendation for coalescing filters installation 5/14 Rev M
upstream of gas heaters Updated text throughout
Added recommendations for shutdown on gas fuel, dual fuel Added Fig. 14, 15, 25
transfers, and FSDS maintenance Revised Fig. 8, 10, 12, 22, 29, 34, 35, 37, 39, 41, 42, 43, 44, 45
Trip from peak load maintenance factor added Updated Appendix A
Lube Oil Cleanliness section added Updated Appendix D
Inlet Fogging section updated to Moisture Intake Added 7F.04 Estimated repair and replacement intervals
Best practices for turning gear operation added
Added Appendix G
Rapid Cool-down section added
10/17 Rev N
Removed reference to Fig. 3
Moved Fig. 3 to Appendix E
Renumbered figure references
Renumbered figure references in Fig. 13, 14, 37, 38, 39, 40, 42,
D-1, D-2, D-3, D-4, D-5, D-6, D-7, D-8, D-9, D-10, D-11
Updated Firing Temperatures section
Revised and renumbered Fig. 25 (now 24)
Updated Moisture Intake
Removed Fig. 30 and Fig. 31
Updated Combustion Inspection section
Revised Fig. 34
Updated Appendix E figure captions
Added Fig E-3 (formerly Fig. 3), E-4, E-5, E-6
Removed Fig. 3, Fig 30, and Fig. 31 from List of Figures and
Append existing Revision History:
Revise Fig. 43 to include affect of forced cooling on rotor MF.
Revise Fig. 31 to include VSVs
Revise Fig. 32 to include 4th stage buckets
Revise Fig. 36 to include 6F.01, 7F.05,7HA.01, 7HA.02, 9HA.01,
and 9HA.02
Major Inspection Maintenance Interval Basis changed from
actual to factored starts/hours
Added Digital Asset Management section
Added Legacy Alstom Inspection Interval section
Added Welded Rotor section
Added Fig. 6 to illustrate EOH counting methodology
Added double wall casing and new seal technology inspection
GE Power | GER-3620N (10/17) 51
Figure 1. Key factors affecting maintenance planning Figure 35. First-stage nozzle repair program: natural gas fired
Figure 2. Key technical reference documents to include in continuous dry base load
maintenance planning Figure 36. Baseline recommended inspection intervals: base load
Figure 3. Borescope inspection planning natural gas fuel dry
Figure 4. Causes of wear hot gas path components Figure 37. Combustion inspection hours-based maintenance factors
Figure 5. GE bases gas turbine maintenance requirements on Figure 38. Combustion inspection starts-based maintenance factors
independent counts of starts and hours Figure 39. Hot gas path maintenance interval: hours-based criterion
Figure 6. Hot gas path maintenance interval comparisons. GE Figure 40. Hot gas path maintenance interval: starts-based criterion
method vs. EOH method Figure 41. Alstom Inspection Interval Counting Methods.
Figure 7. Maintenance factors Figure 42. Rotor maintenance interval: hours-based criterion
Figure 8. GE maintenance intervals Figure 43. Rotor maintenance interval: starts-based criterion
Figure 9. Estimated effect of fuel type on maintenance Figure D-1. Estimated repair and replacement intervals
Figure 10. Peak fire severity factors - natural gas and light distillates Figure D-2. Estimated repair and replacement intervals
Figure 11. Firing temperature and load relationship heat recovery Figure D-3. Estimated repair and replacement intervals
vs. simple cycle operation
Figure 12. Exhaust temperature control curve dry vs. wet
control 7E.03
Figure D-6. Estimated repair and replacement intervals
Figure D-8. Estimated repair and replacement intervals
Figure 15. Turbine start/stop cycle firing temperature changes
Figure D-9. Estimated repair and replacement intervals
Figure 17. Bucket low cycle fatigue (LCF)
Figure 19. Maintenance factor trips from load
Figure E-2. Borescope inspection access locations for 7F.03, 7F.04,
Figure 20. Maintenance factor effect of start cycle maximum
7FB.01, 9F.03 and 9F.05
Figure 21. Operation-related maintenance factors
Figure E-4. 7HA.01 borescope inspection access locations
Figure 22. 7F gas turbine typical operational profile
Figure E-5. 6FA.03 Borescope inspection access locations
Figure 24. DLN combustion mode effect on combustion
hardware Figure F-1. Turning gear guidelines
Figure 25. F-class axial diffuser Figure G-1. B/E-, F, and H-class turbine naming
Figure 28. Deterioration of gas turbine performance due to
Tim Lloyd, Michael Hughes, and Bob Hoeft dedicated many
compressor blade fouling
hours to the detailed development of this document and their
Figure 29. 7E.03 heavy-duty gas turbine disassembly inspections hard work is sincerely appreciated. Ty Balkcum, Jerry Sasser,
Figure 30. Operating inspection data parameters Jim Fossum, Bernard Norris, Cavelle Benjamin, Joe Rizzo, Patrick
Figure 31. Combustion inspection key elements Bowling, Tom Stroud, Matt Ferslew, Gang Qian, John Memmer,
Peter Marx, Steve Wassynger, Curren Shorte, Eamon Gleeson,
Mardy Merine, and Govin Rengarajan are also acknowledged
Figure 33. Stage 1 bucket oxidation and bucket life for significant contributions to the current revision.
GTD-222, GTD-241, GTD-450, GECC-1, FSX-414, N-155 and Extendor are trademarks of the General Electric Company.
2017, General Electric Company. All rights reserved.
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