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Generator Evaluation Techniques for
Refurbishment Decisions
William G. Moore, Florida Power &Light, Ft. Lauderdale, Florida
Stephen F. Ulm, Florida Power Corporation, St. Petersburg, Florida
Ulrich P. Schlager, Siemens Power Corporation, Bradenton, Florida
For Presentation at the EPRI
Utility Motor and Generator Predictive Maintenance Workshop
Scottsdale, AZ
December 10-12, 1991
Authors
Mr. William Moore is currently Technical Manager at
Florida Power &Light's Martin Power Plant. At this site,
he is responsible for managing all predictive maintenance
programs, condition assessment activities, reliability analysis
and prediction, as well as development and coordination
of equipment overhaul activities. Before working at FPL,
Mr. Moore spent IO years with Westinghouse in design and
new product development. He has authored over ten papers
in the power gener¢tion field, and has three patents to his
credit. Master's and Bachelor's degrees in Mechanical
Engineering were obtained from the University of Pittsburgh
and Notre Dame, respectively.
Mr. Stephen F. Ulm received his degree in Electrical
Engineering from the University of South Florida. Upon
graduation in 1974 he began employment with Flonda
Power Corporation where he was responsible for construction
and modifcations to fossil, nuclear and peaking unit plants
including preparation of studies, detailed design and
procurement documents; supervision of installation and
testing; and co-ordination of as-bunts upon completion.
Mr. Ulm was the Project Engineer for the stator midsection
replacement at Crystal River Unit #3.
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Mr. Ulrich Schlager studied power-engineering at the
Technical University of Nuernberg. After graduating in
1973, he started work for Siemens Kraftwerk Union (KWU)
as Project Engineer in the electrical design and layout of
nuclear power plants in Germany. Through several different
assignments within the KraJtwerk Union Group, he extended
his experience in overall project management within the
electrical and I&C field. In 1987 he joined Siemens Power
Corporation to represent Siemens generator technology in the
American market. He has authored papers in the area of
generator replacement/refurbishment applications and is a
senior member ofIEEE and VDE.
Presently Mr. Schlager is Manager for Generators at
Siemens Power Corporation in Bradenton, Florida. He is
responsible for new equipment and refurbishment/rebuilds on
non-OEM equipment.
Generator Evaluation Techniques for
Refurbishment Decisions
Abstract
The Electrical Power Industry is undergoing tremendous
change due to deregulation, aging equipment, environmental
concerns and investment/risk considerations. Public utility
commissions, along with shareholders and end consumers,
are closely monitoring'utilities' decisions, especially in the area
of costs—both Operation and Maintenance, and Capital.
I ncreasing emphasis, within the conventional utility
environment, has been and continues to be, placed on
controlling expenditures. To be responsive to these industry
and competitive pressures, utilities must make cost beneficial
choices when faced with plant equipment refurbishment
decisions. These decisions should be based on input from
many sources, including: severity of the failure, costs of
replacement versus refurbishment, risks and safety
considerations, expected remaining life of the unit, operational
mode(base or peak), fuel type, initial costs, system rapacity,
available budgets and financing options. Many times,
however, refurbishment decisions are based on an abstract
understanding of the above, gut feel, or emotional attachment
to a particular option. This paper describes a general
methodology for refurbishment decision making, applied
specifically to generators. Also included is a case history of
one utility's progression through this process.,
Introduction
Evaluations of generator run/repair/replace options can be
categorized based upon input from three sources: technical
information, economic considerations and risk/safety
concerns. To make the best decision possible, it is
advantageous to understand the technical issues before a
crisis situation (e.g. a forced outage) occurs. Economic and
risk/safety issues may change depending on the urgency of
the decision and the prevalent economic factors. The
technical issues will not change, however, and therefore
should be dealt with before a crisis situation occurs. The
description below details suggested ways in which utilities can
evaluate these areas when preparing for generator
refurbishment decisions.
Step 1: Develop a Database of Unit Specific
Information
It is important for utilities to have a thorough database of critical
equipment information regarding .the specific design
differences of the components. This database should
encompass every unit within the utility's system. The following
list is a minimum amount of information, necessary to respond
to potential generator issues currently prevalent in the
industry:
•
•
•
•
•
•
•
•
•
•
•
•
Unit Manufacturer ~
Factory Ship Year ~
Nameplate Information 1
Stator Winding Insulation Type Rotor Winding Insulation Type (including slot liner and
turn to turn insulation)
Stator End Winding Bracing Configuration
Rotor Forging Material
Year Rotor Forging Made
Rotor T-Head Material
Retaining Ring Material
Nominal Rotor Diameter
Stator Core Tightening Mechanism
In many cases, the O-riginal Equipment Manufacturer or a
competitor can provide this information, if Et is not found in the
Plant Data Books.Some of the information can be derived from
knowing the factory ship year. For instance, 1958 to 1960, was
a critical period in the power generation industry. At that time
stator winding insulation- systems were upgraded from
thermoplastic to thermosetting. In addition, reliability in rotor
forgings increased due to advanced forging techniques such
as vacuum degassing. Ultrasonic Testing was also greatly
improved in this time period: Other pertinent information is
specific to certain suppliers. What is most important is that
each utility have a thorough understanding of the generator
designs and configurations that they have, and consequently
the potential problems with those particular designs.
Step 2: Develop FMEA's and/or Fault Trees
Specific to Your Units
An FMEA (Failure Mode Effects Analysis) or fault tree analysis
done on major critical generator components will enhance the
run/repair/replace decision making as well as bring other
benefits to the utility. By identifying failure modes or base
faults, up front, the station engineer has a ready source of
information to refer to when a component fails. This source of
information (the fault tree) should be developed in a
non-pressured atmosphere by .a team of experts. It will then
be available when the station engineer is diagnosing a
problems occurring in the industry, have well known and
documented root causes. In those.cases, fault tree analyses
are still beneficial for they provide a greater understanding of
the failure mechanisms and increase the awareness of the
problem to all involved, not to mention the value to the end
user who may not be a generator expert. Beyond that,
however, plant engineers involved with generators face
numerous problems that may not be the same magnitude as
the "well known problems", but the criticality is just as
important. Pre-completed fault tree analyses are invaluable in
cases such as these.
problem that needs immediate attention, but the resources of
the experts are not available.
More importantly, however,identification of failure modes now
can allow preventive action to take place before a failure
occurs. For example,the fault tree shown in Figure Yidentifies
tube oil contamination and tube oil temperature at turning gear
as root causes for a bearing wipe. Identification of.these failure
modes has resulted in specific plant actions to prevent future
failures.~~~ No failures have occurred since the appropriate
countermeasures were put into place. Many generator
Sy~cronous
Speed
Main Oil
Pump Failure
D
doss of o~~
Supply
RPM <3600
To Turning Gear
Aux. Oil
Pump Failure
Lack of
Lubrication
D
Shaft RPM
< 2000
~~~ o~i
D
High Oil
Viscosity
1
~
Temp From
Cooler> 90'F
Loss of tube
Oil Film
Synchronous
Speed
Lube Oil
D
Low Oil
Yscosity
Temp From
Cooler c 110°F
tube OiI
Supply Side
Contamination
Inadequate J
FilVation of
Reservoir Tank
Contact with
Rotor Journal
Contam. Oil w/
Particulate Dia.>
~~~ ~~m
Embedded
Particles in the
Bearin Babbit
Grooved
journal Surface
~"
Scored and
Grooved
gearin Surface
Rotation of
the Rotor
Loss of Load
Bearing
Capability
Worn Bearing
Surface
Misalignment
D
At~jecent
Bearing Failure
Turbine Bearing
Overload
Rotor
Thermal Rise
Lack of Journal
To Bearing
Clearance
Lube Oil
Film
D
Rotor Rise
~
Synchronous
Speed
Lack of Journal
~o oeanng
Clearance
Figure 1. Fault Tree Analysis for aTurbine-Generator Bearing Wipe
2
}~ oR
D AND
r
#6 Turbine
Bearing Wipe
Step 3: Develop a Useable Database of
Operational Data,Testing Data,
and Failure History.
Many utilities keep exce4lent records of unit operational data,
past test results and component failures. The problem of most,
however, is that no one individual or group is overseeing the
trending of this data. The report is buried away in some file
room located on the other side of the plant, or it had a limited
distribution to a few key individuals who have it in their private
files. Even control room operators, who monitor data on a
continuous basis, usually only see data trended over the last
24 hour period, or at most the last week or month. With many
of the generator problems, (i.e. in the areas of insulation
degradation, stator end winding looseness and core
looseness) it is helpful to trend data (in this case, test results)
over the last 5 or 10 years.
Nowhere is the value of this more illustrated-than in the turbine
performance area. Initial acceptance test values done on unit
start-up can be compared to each test value throughout the
units life to optimize maintenance intervals or prevent failure.
Typically, with regard to generator testing, the unit passes the
test, is put into service and the test Value is buried in a file.
Trending data, which can lead to more informative decision
making, can be done in many areas including: bearing
vibration, gas temperature, hydrogen purity, field current, flux
probe testing, winding insulation tests and closed cooling
water temperatures.
In addition, commercial packages -are available to provide
additional information to trend. Such items as end winding
vibration monitors, shaft current monitors, generator condition
monitors, radio frequency monitors and others. These devices
can be useful if the data is used and analyzed. If a utility does
not desire to provide the manpower to trend this important
data, it can purchase commercial packages to do the long
term trending and even purchase outside help to do the
analysis of the trends.
Other critical information to track and analyze is the failure
history of each component. Weibull and reliability growth
analyses are excellent tools to take the existing failure history
and predict the number of recurring failures, and the timing of
the next one to occur. These tools, however, are ideally suited
for components`that have multiple failures with the same failure
mode, such as turbine blade cracks or boiler tube failures.
Generators, however, are not ideally suitable for these types
of failure predictions, primarily because of severity of the
failure, the lack of multiplicity of components and the driving
mechanism of the failure. If a boiler, tube fails, the unit is
brought off line, the tube is repaired and the unit is brought
back. A failure investigation will identify the root cause, which
mayor may not be actionable in the immediate future. On the
other hand, if a generator retaining ring fails, the unit isoff-line
from 6 months to a year. This inability to use past unit specific
failures as a prediction tool makes trending of operational data
and test results even more important.
Step 4. Identify Major Generator Issues
Specific to your Units
Currently, there are a number of major generator issues in the
industry that should receive the most attention from your
management. These should be screened and applied only to
the appropriate units within your system. Below is a brief listing
of the major issues in the industry.
•
•
•
•
•
•
•
Stator Insulation Degradation ~~Rotor Insulation Degradation
Stator End Winding Looseness
Stator Core Looseness .,~
Rotor Tooth Top Cracking
Rotor Copper Dusting
Retaining Ring Stress Corrosion Cracking
There are numerous references in the current literature that
addresses these problems.~2,3,a,5,s,~,a,s,io) Suffice it to say that
it is each utility's responsibility to do the necessary research
and to be aware of wF~at potential problems are out there
before a crisis situation develops. In many cases, the utility
can make an intelligent run/repair/replace technical decision
by adequate record keeping and trending of this parameter.
Economic and Risk/Safety considerations still have to be
entered into the decision making process.
Step 5: Do the Economic Analysis with the
Run/Repair/Replace Options
Many utilities have pre-packaged programs for performing
economic analyses of the different options. These analyses
involve many different factors, including:
Costs
•
•
•
•
Run to Failure
Refurbishment
Replacement
Additional O & M
Benefits
•
•
•
•
•
•
Deferred Generation .
Capital Cost Avoidance
Replacement Power
Avoided O & M
Efficiency Improvement
Increased Capacity
The run to failure option, while sometimes used for non-critical
plant equipment, is usually not an acceptable option for
generator components,especially in any of the current critical
industry issues. A decision can be made to run until a more
timely refurbishment~or replacement can be made, but making
that decision requires a keen understanding of all the issues:
technical, economic
'
and < fet .Again, with generators,
9i
consideration must be based on a one time, possibly
catastrophic failure. In contrast, feedwater heater tube leaks,
for example, can be observed over time, plotted and repaired
and replaced in a timely fashion. By building a failure history,
one can predict the number of future failures: Knowing that, it
is an easy calculation to determine the cost of future operation,
considering the operation and maintenance costs associated
with each of the future tube leaks.
While the run to failure option is ncst a viable option for generator
issues, refurbishment versus replacement usually is. In
general, one looks at the initial casts of the refurbishment and
replacement, adding in the additional maintenance costs with
the refurbishment. For instance, if the refurbishment option is
only a short term solution, the cost of the refurbishment done
two or three times over the rerr~aining life must be weighed
against the.initial costs of the permanent solution. Of course,
the potential benefits of the refurbishment or replacement must
also be captured to justify the expenditure. This is typically
done through an analysis of deferred generation costs, capital
cost avoidance benefit, avoided -O & M costs, avoided
replacement power costs and any increased capacity or
efficiency improvement.
Deferred generation savings can be contributed to the
increased reliability of the repair, thereby offsetting the need
to build new generation. Capital cost avoidance can be
captured to include savings achieved from not having to
replace components which otherwise would have reached
end of life during the period. Avoided O & M savings are
captured through the increase in mean time between failure
of the components)in question. Replacement power savings
are achieved by the increase in the units capacity facxor.
Increased efficiency savings can be attributed to the overall
improvement in efficiency which results can be calculated
back to fuel savings. Increased capacity savings should be
included to capture those savings that result from the ability
to operate the generator at a higher rating, thereby offsetting
the need to build the amount of new generation. All factors
should be included in the economic comparison, although
some may be insignificant or even zero depending upon the
scope of the repair. All costs should be brought back to net
present value for an equal comparison.
While these programs -give a least cost alternative, it may not
be the best alternative- from a technical or risk/safety point of
view. All facto~~ must be considered.
Step 6: Do the Risk/Reliability Analysis
Risk factors include, not only technical risks and reliability
issues involved with implementing a particular option, but also
safety related risks involved with different scopes of repair.
Risk analysis, in and of its own, can be quite complicated and
cumbersome for applications in the Power Generation
Industry. Reliability analysis can be more straightforward, if the
appropriate failure history is available for the new design
options being offered. Usually it is not, since the last thing a
salesman wants to give away is the failure history of a new
product—unless of course it has never failed!
These analyses can best be handled through the use of the
utility's own technical experts, after obtaining all the necessary
knowledge about the options in question. Even with this great
wealth of knowledge,emotional involvement and personal bias
can easily enter into the decision making process. One way to
bypass partiality, is to independently weigh all the options,
their risks and reliability factors and do the appropriate
multiplication and addition to come up with the best solution.
A number of computer programs on the market will facilitate
this process, but it's just as easily done by hand.The important
point is that the critical decision is achieved through a
systematic, methodical evaluation of all the appropriate
1r~ ~~
options.
Case History
~~L~
Florida Power Corporation's Crystatl River Unit #3 developed
problems with"its generator- end windings including:
looseness, broken joints and series connections. Although a
formal fault tree analysis was not done, sufficient operational
and test data was available to accurately diagnose the root
cause of the failures. Table 1 shows a summary of this data
history.
In late 1986, refurbishment evaluation options were initiated.
The options proposed and evaluated were:
Generator Rewind
Stator Replacement
Generator Replacement .
While the technical issues were being addressed, risk and
reliability concerns were also being evaluated. The major risk
factor involved the potential of extending the installation
beyond the proposed schedule, while the reliability
consideration stemmed from the potential of having a forced
outage during the remaining 30year life of the unit. The risk
factors were identified as shown in Table 2. Reliability factors
taken into consideration are listed in Table 3.
The characteristic values were developed using the same
engineers prior to the determination Hof the weight factors to
protect against individual bias.
The evaluation process consisted of three areas to be
considered: total evaluated cost, risk of extending the outage
and reliability of the repair. The initial step was to select the
best vendor for each option. The next step was then to select
the best option. The results of the evaluation showed that the
complete generator replacement was marginally more reliable
and offered a slightly lower risk than the stator replacement.
However, the small advantages in risk and reliability did not
outweigh the cost savings provided by the stator replacement
option.
, ',
,~
Table 1. Data History of Crystal River Unit 3
Winding Problems.
Date
Table 2. Risk Factors in the Crystal River
Generator Replacement Evaluation.
Findings
6/16/76
Unit 3 acceptance tested.
2/1/78
Crawl through inspection revealed end winding
dusting.
~
5/5/78
Visual inspection revealed dusting in areas o€
series connections and between coils and
f
support rings. Loose wedges and core blocks
identified. Core rewedged. Core blocks
retightened.
5/7/80
10/23/81
4/11/85
Description
Heavy Lift
The movement oflarge components
requires extensive rigging. This factor
takes into consideration the potential of
a rigging accident and its impact. It is
significant for the stator replacement
and generator replacement options only.
,Using Existing
Core
The rewind options assume the existing
core can be reused with minimal repair.
This factor considers the possibility that
there is significant core damage that
would have a major impact on the
schedule. This item was the most
significant risk factor due to past
industry findings.
Visual inspection showed reduced dusting
activity.
Dusting and looseness on strain blocks, diamond
spacers, crossover banding, and.spacers
between bottom coils and support ring. Loose
components repaired.
Inspections showed severe greasing, dusting,
broken ties and burned copper strands.
Minimum repair done involving removal of loose
bracing components, repairing tubes and broken
copper strands.
3/18/86
Decision was made to purchase additional end
winding bracing system.
4/2/86
Discovery of like unit with severe coil shorting
problems. Inspection of Crystal River Unit 3
revealed same problem with shorted strands.
Shorts repaired. Installation of additional end
winding support system deferred.
9/86
J
Risk Factor
Initiated refurbishment option evaluations.
Refurbishment Details
The matrix shown in Figure 2 summarizes the risk/reliability
evaluation for each option and vendor, identifying their
weights. Florida Power Corporation using the evaluation,
implemented a stator replacement. This approach took into
account all thecriteria for the changeout during a regular
scheduled refueling outage of eight(8) weeks. Due to the risk
analyses, it was decided to manufacture a new midsection
piece (Figure 3) including: a new housing, core with core
suspension and winding and end winding supports. As shown
in Figure 4, the end shields including end brackets, terminal
box, rotor and the cooler section were retained and reused.
The midsection replacement was shipped to the site 18.5
months manufacturing time after contract award.
Transporting this midsection replacement to and on site
required special planning. It is approximately 16 feet in
diameter by 32 feet long weighing over 420 tons. The original
Generator Bearing The generator replacerrient will require
Modification _ the present rotor bearings in a separate
pedestal to be modified to be included
in the end shields. This modification
introduces an additional risk.
Stator Core
Component
Compatibility
The stator replacement options are
extremely dependent on the interface
with existing OEM components which
will be reused. Potential for dimension
mismatch is considered.
Installation
Experience
This factor takes into account the vendor
experience in performing similar work.
Number and
Complexity of
Auxiliaries
The scope of auxiliaries to be replaced,
modified or added has a large impact
on risk.
Familiarity
with Exiting
Conditions
This factor covers the familarity with the
OEM equipment, as well as experience
in performing at Crystal River.
plan anticipated a somewhat routine transfer from the (ast
barge to a heavy duty rail car using the stationary crane at
Charlotte, SC. However, hurricane Hugo totally destroyed this
stationary crane just as the midsection was scheduled for
u nloading. Alternate unloading methods had to be
investigated.
Several floating derricks were located, but none in ports where
the midsection could be transferred to proper rail facilities.
Finally the floating derrick Atlantic Giant was located in Norfolk,
VA. It was necessary to tow the Atlantic Giant from Norfolk to
Charlotte where it could transfer the midsection to the rail car
for delivery to Crystal River. Actual delivery to the site was
accomplished in early February, 1990.(Figure 5)
Once at the site, the new midsection was removed from the
rail car and placed on one of two identical transporters in
preparation for the approximately 1 mile move from the rail
siding to the plant entrance.(Figure 6)
5
Table 3. Reliability Factors in Crystal River Generator Replacement Evaluation.
Reliability
Factor
Reliability
Factor
Description
Shaft Vibration
Analysis
The installation of a new generator requires
the turbine interface be analyzed to verify
that no harmful resident frequencies exist.
The compatibility between the turbine and
generator is critical to the long-term
operation of the unit.
Direction of
Rotation
The replacement generator is'designed to ,~~
rotate in the opposite direction as the
existing unit. This rotor needed to be
modified to properly interface with the
turbine. This modification had a potential to
lessen the reliability of this option.
End Winding
Support System
Description
Rotor/Exciter
Compatibility
The complete generator replacement offer
reused the existing excitation system
requiring rotor modification for proper
interface. This impact is similar to
modifications due to rotation.
Maintainability
This factor considers the future
maintainability of the different options "as
designed."
Service and
Replacement
Parts
The availability of an established service
organization and spare parts was reviewed
for its impact on reliability.
Operating
Experience
This factor takes into account the forced
outage rates for similar designs, utilizing
data from NERC(North American Electric
Reliability Council). The vendor's
experience on an installation similar to the
proposed options was also included.
All options provide a support system which
is rigid for proper support during normal
operations and short circuit conditions, yet
allow for thermal expansion. This factor took
into account history and experience with
proposed designs. This was the most
significant factor in the reliability evaluation.
Weighted Values
Characterisic Values
Weight
Factor
Characteristics
Risk Factors:
1. Risk of Heavy Lift
2. Risk of Using Existing Core
3. Generator Bearing Modifications
4. Stator Casing Component
Compatibility
5. Installation Experience
6. Number and Complexity of Auxiliaries
7. Familiarity with Existing Conditions
Subtotal
Reliability Factors
1. Shaft Vibrat~~n Analyses
2. Direction of Rotation
3. End Winding Support System
4. Rotor/Exciter Compatibility
5. Maintainability
6. Service and Replacement Parts
7. Operating Experience
Subtotal
Options:
1. Generator Rewind
2. Stator Replacement
3. Generator Replacement
Option 1 Option 2 Option 3
Option 1
C
A
B
4.30
8.24
9.50
8.40
1.29
4120
9.50
3.36
129
4120
9.50
5.88
1.29
41.20
2.85
8.40
0.86
4120
9.50
8.40
5.76
10.80
4.20
7.20
10.80
4.20
5.76
10.80
1.68
4.32
18.00
2.52
5.76
10.80
1.68
14.40
7.20
2.10
48.68
52.64
73.59
82.71
71.98
83.66
4.20
5.80
35.92
6.30
9.10
6.00
9.15
4.20
5.80
22.45
6.30
6.50
6.00
9.15
4.20
5.80
35.92
6.30
9.10
6.00
9.15
4.20
5.80
40.41
6.30
11.70
6.75
12.81
1.68
5.80
35.92
3.15
9.10
6.00
9.15
1.68
2.90
44.90
6.30
13.00
7.50
18.30
76.47
60.40
76.47
87.97
70.80
94.58
D
A
C
A
B
A
D
0.43
4.12
0.95
0.84
10
2
10
10
10
2
10
10
3
10
10
4
3
10
10
7
3
10
3
10
2
10
10
10
4.30
8.24
9.50
8.40
1.44
1.80
0.42
4
6
4
5
6
10
4
6
4
3
10
6
4
6
4
10
4
5
0.42
0.58
4.49
0.63
1.30
0.75
1.83
10
10
8
10
7
8
5
10.00
Evaluated Vendors
'A','B', 'C','D'
10
10
5
10
5
8
5
10
10
8
70
7
8
5
10
10
9
10
9
9
7
4
10
8
5
7
8
5
4
5
10
10
10
10
10
Option 3
A
A
10.00
Option 2
Characteristic EvaluationLarger value indicates
better performance.
(Maximum of 10)
Figure 2. Risk/Reliability Generator Evaluation Matrix
Weighting FactorLarger value
Indicates greater
importance.
Figure 5. Arrival of the 870,000 Ib. Stator
Midsection at the Crystal River Site
Figure 3.Completed Stator Midsection
In addition to the two transporters, two jacking towers were
also required; one was set up at the rail siding to place the
midsection on the transporter. It was then moved to a location
just outside the turbine building access door where the old
midsection was loaded on the second transporter and moved
to a rail siding for eventual scrapping. It then removed the new
midsection from its transporter for rolling into the turbine
building where it was elevated to the turbine room floor by the
other jacking tower that had been assembled in the crane bay.
End-Tum
Ba(fb Cap
Air Gep
Seal
Stator
Freme
Stator
Corc
Once the new midsection `reached the turbine floor elevation,
it was-skidded- on stw~tural members at a location
approximately over the exciter area where a travelling gantry
crane lifted and transported it to the proper location on the
foundation. Here the new midsection was aligned and
attached to the original cooler section.The joint between these
two sections duplicates the original design, wherein a double
row of bolting provides the rrfechanical strength and a seal
weld provides the gas seal.
The generator was synchronized on June 23, 1990 and.
following a 30 day trial run and a 100 hour acceptance test, it
Rotor
Stator
Winding
Phase
Connector
Rings ~
Adapters
<~x Replaced Components
High Voltage
Buahinga
Retained Componerns
Fgure 4.Crystal River #3 Stator Midsection Replacement
7
End winding vibration, due to end winding looseness, was the
primary reason for Florida Power Corporation's generator
midsection replacement decision. Therefore, much interest
has been focused on the information coming-from the newly
installed fiber optic end winding monitor and the RF-monitor.
A key design goal is achieving lasting integrity of the end
winding basket. A simple, monolithically acting end winding
basket- prevents, from the beginning-, excessive end winding
vibration. Test results of the Crystal River #3 generator after
the midsection replacement indicate very low, almost
undetectable end winding vibration levels. The readings of the
RF-monitor do not indicate any disturbances at all. By utilizing
five (5) measuring points, this state-of-the-art monitor~t2~
exceeds other known monitoring systems for detecting and
identifying potential problems in or in the vicinity of the
generator(Figure 7).
Figure 6. New Midsection on Transporter
was turned over to Florida Power Corporation for normal
operation.. The unit remained on line operating very
satisfactorily until a planned mid-cycle fuel outage in the fall
of 1991. Florida Power Corporation made limited crawl-thru
inspections of the stator end windings and adjusted internal
monitoring sensors. There were no indications of heavy
greasing and dusting detected which would indicate.
movement and end winding looseness within the end winding
basket. The entire end winding area was dry; no oil was-vi"sible'
which would indicate seal leakages.
The decision of Florida Power Corporation for a stator
midsection replacement solved the end winding vibration
problem as well as provided a new core designed and
manufactured for maintenance free operation. By
compressing X370 psi)and heating (180`F)the core at various
times during stacking, the materials are pre-aged, .thus
preventing major shrinkage during operation. After
approximately five years, any remaining minor shrinkage has
ceased, providing a constant core compression of
approximately 150 psi for the remaining life of the generator.
Core retightening is no longer necessary.(Figure 8)
Monitored High Voltage Systems
Examples of Faults to be Detected
Bad
Contact
in Static
F~cciter
Unit
Sparking of
Ground
Brushes on
Generator
Shaft
Exciter
Failure of
Inner
Potential
Grading in
HV Bushing
Broken
Generator
Circuit Ring
Ground
Connection
HV
Discharges
Inside a Main
Transformer
Broken
•Lead in
Current
Transformer
Winding
High
Corona
Discharge in
aGrounding
Switch
Aux.
Generator
Transformer
Protection
Equipment
Main
Transformer
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Surge Wave Protection Capacitors
High-Frequency Resistors
_ _
~~
Broad-Band
RF Monitor
Peripheral
Diagnostic
Figure 7.On-Line RF Monitoring of High Voltage Equipment
g
y
N/mmz
/
1.8
E
1.6
------I-------3
1 ~
a
1.4
o
1.2
~ Initial Compression
1
FStacking Beams
p
6
2
--
-
E
— -
FThrough-Bolts
y
d
~•~
~
o
0.8
U
~
0.6
~j
0.4
~
4
Remaining Compression
The High Stator Core Compression Achieved by Repeated
Pressing and Heating Prevents Damaging Core Setting Later on
so that no Retightening of the Stator Core will be Required even
after Long-Term Operation.
p2
I
0
0
1
2
3
4
5
6
7
8
9
10
11
12 13 14
15
16
5
Service Years
1)Stacking Beams
1.1) Insulated Dovetail Bars
2)Insulated Through-Bolts
3)Pressure Plate
4)Clamping Finger
5) Core
6) Strain Gauges (installed
on Selected Generators
for Long-Term Supervision
'Figure 8. Axial Core Compression
Conclusion
A comprehensive data base, unit-specific fault trees and the
knowledge of major generator issues in combination with
economic analyses are powerful tools for utilities to conduct
efficient generator replacement evaluation studies. Florida
Power Corporation has demonstrated the effectiveness of this
method by utilizing all the essential evaluation elements for
their Crystal River #3 generator refurbishment decision. The
very satisfactory operation of the new midsection (Figure 9)
over the past sixteen (16) months, justifies that the proper
decision was made.
Acknowledgement
The authors wish to thank Mr. John J. Miele of the Florida Power
Corporation's Crystal River #3 Station for his assistance and
use of operational data.
Figure 9. New Crystal River Midsection Installed
D
References
[1] Moore, W.G., et. al, "Turbine Lubrication Oil
I mprovements," EPRI Steam Turbine Generator
Workshop, July 18, 1991, Charlotte, NC.
[2] Proceedings from EPRI Generator Retaining Ring
Workshop, September 15, 1987, Charlotte, NC.
[3] Proceedings from EPRI Generator Reliability
Workshop, December, 1985, Scottsdale, AZ, Report
#EL-468.
[4] Reason, John, ed., "When it pays to change out the
whole generator," Electrical World, March 1988.
[5] Shelton, J.W. and Reichman, B.M., "A Comparative
Analysis of Turbo-Generator Core Inspection
Techniques," American Power Conference, April 22,
1985, Chicago, IL.
[6~ Londergan, M.B., Murphy, R.L., and Metala, M.J.,
"Generator Rotor Tooth Top Cracking," International
Joint Power Generation Conference, October, 1991,
San Diego, CA.
[7] Edmonds, J.S. and Rasmussen, J.R., "Generator
Problems in Cycled Units," International Joint Power
Generation Conference, October, 1991, San Diego,
CA.
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10
[8] Liese, M., Boeer, H.J., and Schlager, U., "Results of
Inspection and Monitoring of Large Hydrogen-Cooled
Turbine-Generators," EPRI Seminar and IJPGC
Conference, October, 1990, Boston, MA on Rotating
Machine Winding Condition and Repair/Rewinding
Practices, December 13, 1988, Scottsdale, AZ.
[9J Boeer, J., Liese, M., and Schlager, U., "Examples of
Stator Core and Winding Replacements on Large
Turbine-Generators," IJPGC Conference, October,
1990, Boston, MA.
[10] Bailly, H., Westendorf W., Schlager, U., "Generator
Rotor Tooth Top Cracking—Failure Analysis and
Long-Term Refurbishment," EPRI Workshop on Utility
Rotor and Generator Predictive Maintenance,
December 11, 1991, Scottsdale, AZ.
[11] Ulm, Stephen F., Huber, Gustav N. and Rauter,
Joseph J.,"Stator Midsection Replacement of the 990
MVA Crystal River #3 Hydrogen-Cooled Generator,"
American~Power Conference, Chicago, IL, April,
1991.
[12] Weidner, J., Schlager, U., "Turbine-Generator
Modular On-Line Monitoring and Diagnosis System,"
EPRI Workshop on Utility Rotor and Generator
Predictive Maintenance, December 12, 1991,
Scottsdale, AZ.
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