Proceedings of the ASME 2010 Power Conference
POWER2010
July 13-15, 2010, Chicago, Illinois, USA
POWER2010-27
Douglas D. Reed
Dominion Generation
Glen Allen, Virginia, USA
NDE – Non-Destructive Examination
ABSTRACT
Steam turbine maintenance intervals have been
extended from the Original Equipment Manufacturers’ (OEM)
recommended intervals over the last 20 years. Inspections in
which the casing is completely opened have been pushed to 10
years or longer on units with OEM recommended intervals of 5
to 6 years. This has been made possible because of additional
data monitoring and in place inspection techniques which allow
the internal condition of the unit to be assessed without opening
the casing. Risk-based computer modeling and analysis
techniques have allowed us to predict safe extended component
inspection intervals using fracture mechanics. This paper gives
a systematic approach to determining the condition of a steam
turbine based on past history and current measured parameters.
It provides a discussion of the effects of changes to components
and how to determine and rank risk factors. Also discussed are
results of inspections of machines which have been opened
after extended intervals.
INTRODUCTION
Steam turbine maintenance intervals are set by evaluating
anticipated performance improvement gains and component
maintenance needs.
Performance degradation due to a
damaged blade path or worn seals determines the inspection
interval for some companies. For others, the interval is driven
by the need to perform maintenance inspections on major
components. Examples include rotor bore inspections, shrunk
on wheel inspections in LP turbines, and mechanical issues
with the stationary or rotating blades. These inspections must
be performed in a timely manner to ensure the safety of the
plant personnel. The maintenance interval should be set using
safety considerations as the overarching factor, with equipment
maintenance next, and performance as the final factor.
NOMENCLATURE
OEM – Original Equipment Manufacturer
KEY SAFETY FACTORS
Certain factors have been identified as critical safety
issues for the evaluation of a candidate for an open casing
interval extension. These factors have the most potential to
increase risk of harm to personnel and equipment.
Maintenance activities should be evaluated to determine
whether they affect the five factors discussed below. Then the
magnitude of any increased risk experienced by extending the
inspection interval needs to be defined.
Avoiding Overspeed Conditions Operating a machine at a
speed in excess of normal operating speed is detrimental to
component longevity and can place personnel at risk. The
extent of the safety risk and amount of damage to the unit is
dependent on the magnitude of the speed and the time that the
unit operates at high speed.
A turbine-generator may
experience up to 120% of rated speed after a full load trip. The
units are designed to withstand this event, but there will be a
reduction in rotating component life each time this occurs. It is
important to minimize all operation above rated to extend the
life of the components.
Precautions should be taken to avoid an uncontrolled
overspeed event. This condition occurs if the steam controlling
valves cannot be tripped or shut manually. The most extreme
overspeed event would occur with continued admission of
steam after a loss of full load. In this situation, the rotors can
reach speeds high enough to self destruct. The components
released during overspeed have energies high enough to exit the
casings.
It is imperative that the steam admission valves and
control system be maintained in good condition and tested at
recommended intervals. Overspeed protection systems and
reverse current relays at the generator breaker can avoid an
uncontrolled speed incident.
These systems must have
provisions for testing and be maintained as recommended.
Most overspeed systems have provision for testing without
requiring the unit to be driven to the actual overspeed set point.
1
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
DETERMINING STEAM TURBINE INSPECTION INTERVALS
While an extensive study has not been done, the
turbine failures known to us show that components will remain
in the casings if failure occurs at normal operating speed.
Components that fail at uncontrolled speed conditions have
exited the casing causing damage to additional equipment.
LP Turbine Last Stage (L-0) Blade Condition A L-0 blade
failure can cause extensive damage. The failure can range from
the loss of a tip to a failure at the root. While loss of a small
amount of mass may cause minimal damage, the liberation of a
last stage blade at the root can destroy a steam turbine
generator. When a large amount of material is lost, the rotor
becomes extremely unbalanced. The resulting high vibration of
the rotor can cause loss of additional mass in the blade path
when other blades or portions of blades fail. Whether or not
this occurs, the bearings can be destroyed. Excessive motion of
the rotor near the generator can cause loss of the hydrogen
sealing capability which can cause a fire as discussed
previously. The result is tremendous damage to the machine
and a possible fire or explosion. The safety of the plant
personnel is jeopardized both by the initial damage, and
then by managing the fire and ancillary damage afterwards.
Strategies to reduce last stage blade failures consist
mainly of extensive inspections when the rotor is removed from
the machine and then yearly visual inspections. Rows of
blades/buckets that are problematic can have optical blade
vibration monitors installed. These instruments can give
assurance that no changes are occurring in the L-0 rows during
an extended run. In general, monitoring the fleet for instances
of failure and tracking location and frequency of failure is
recommended.
Some units have experienced multiple failures on a
single unit or a common design of blade. If this in the case, it is
High Temperature Bolting Condition The various equipment
manufacturers have issued inspection recommendations for the
bolting on high pressure casings and valves. Bolts and studs
have a finite life determined by the number of tightening cycles
that have been experienced and the time of exposure to high
stress at high temperature. The existing condition of the bolting
needs to be determined by researching the records for the unit.
If possible, the condition and the number of tightening cycles
that the bolting has experienced needs to be defined. If the
number of cycles is unknown, a full NDE inspection and
possible metallurgical analysis should be done prior to
extending inspection intervals. Where studs are used, the
casing holes and threads need to be inspected also.
Rotating Component Condition The condition of rotors,
shrunk-on-wheels, and rotating blades needs to be understood
and documented prior to extending inspection intervals. The
failure of rotating blades can cause and unbalanced condition
similar to that discussed in the L-0 section above. Another
danger is that the loss of a blade will damage the steam path
downstream. This damage will usually be contained within the
casing, but can cause a long forced outage.
A cracked rotor or shrunk on wheel is a serious danger
to personnel and the equipment. Casings are not designed to
contain the large pieces resulting from a failed rotor or wheel
and the exiting pieces can damage or destroy nearby equipment
or operating units. For this reason, modern inspection intervals
are estimated by determining the smallest crack that could
remain undetected in the rotor or wheel and then calculating the
time this crack would need to propagate to failure. All
operating assumptions used in this calculation need to be
monitored. If there are changes to any of these assumptions the
inspection interval should be adjusted. Examples of these are
ramp rates, changes to maximum temperature, and number of
starts. It is extremely important to avoid propagation of a
through crack in a rotor or wheel as this can cause destruction
of a unit and is dangerous to plant personnel.
2
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
DC Backup System Condition
DC backup system
maintenance can require that the unit be removed for service to
maintain its components. These systems consists of batteries,
charging systems, and DC backup oil pumps to allow
lubrication of the bearings and operation of the Hydrogen Seal
Oil system after a unit has tripped and the plant has experienced
a power failure. In some units, these same battery banks
provide power to the control system to operate devices such as
the relays.
Most steam turbines have a shaft driven oil pump
which will feed a limited amount of oil to the bearings and
hydrogen seals in emergency conditions. The oil pressure from
these shaft pumps drops off significantly below 600 rpm or so.
This drop in pressure will trigger the start-up of the DC systems
to boost the pressure while the unit is coasting to a standstill. If
the systems do not operate, the hydrogen in the generator will
go to atmosphere and usually cause a fire. This fire can ignite
the lubrication oil and travel to the main oil tank, extending the
fire to areas below the turbine. Lack of lubrication can cause
the journal bearings to melt causing the rotors to drop down on
stationary components. The result can range from extensive
seal rubs to destruction of the steam path and rotor.
important to determine if common operating conditions are
occurring at the time of the L-0 failure. Examples include low
condenser vacuum, a particular load point, or certain heaters
being removed from service. If an operating cause can be
identified, it may be possible to avoid the operating condition
causing the problem and extend the inspection interval.
Installation of a L-0 row of a different design can
extend the length of time between “rotor out” inspections. New
articulating or segmented connections between blades are less
prone to failure than older soldered tie wires or welded lashing
lugs. Some new designs have made changes to address past
problems. These can be less prone to cracking than the older
designs. Some blades with hardened leading edges experience
less erosion than older shielded designs. The type and vintage
of the L-0 blades installed in the machine will be a factor in the
length of time between inspections.
Figure 1 - Outer shell crack in radius
VALVE MAINTENANCE VS ROTATING COMPONENT
MAINTENANCE
The generation industry has had more success in
extending the maintenance intervals of the main casings and
rotating components than in extending valve maintenance
intervals. This is mostly due to the caution with which valve
maintenance is approached. Avoidance of an unplanned
overspeed event is the top priority for the maintenance plan for
the reasons mentioned previously. Therefore, the safety
consequences of performing trial runs with extended intervals
are higher than with other turbine-generator components.
The extension of steam turbine valve inspection
intervals has been supported by some OEM’s. One strategy has
been to provide material upgrades for stems and bushings to
reduce the buildup of oxidation (blue blush). These materials
can also reduce valve stem bending. For valves using soft iron
gaskets at the main steam joint, installation of spiral wound
gaskets can allow a reduced bolted joint stress. This allows
more confidence in the ability of the studs and nuts to keep the
joint closed for longer time periods. These valve interval
extension programs require a comprehensive assessment of the
condition of the studs, nuts, washers, and bolting. The casing
condition must be defined to verify that it is suitable for
extended interval service. This can be done through normal
NDE methods, replications to inspect for creep damage, and
checking the operating history for temperature excursions or
unusual operating conditions. It is critical that the turbine
valves be in good operating condition at all times.
FACTORS USED TO DETERMINE THE NEXT CASING
OPENING INSPECTION INTERVAL
Determining the interval for the next casing opening
inspection needs to be based on the mechanical condition of the
unit at the last inspection and the current running condition of
the unit.
Keeping good records during major turbine
inspections is crucial to this process. The dimensions and notes
on condition of components may be needed if a predictive
analysis has to be performed. Digital photos taken during
inspections can be a valuable tool for documenting component
condition.
The planned major inspection date should be reviewed
each year in light of the current running condition of the unit.
Changes in the factors listed below, additional information
obtained about the fleet, and changes in operation need to be
evaluated. Adjustments to the inspection interval need to be
made to compensate for any changes seen.
Listed below are twelve factors which are used to evaluate
a steam turbine as a candidate for an extended inspection
interval.
Vibration An informed evaluation of the vibration signature
can reveal much about the condition of the machine. All
bearings should have the magnitude and phase angle of the
vibration plotted versus time. The information should be
analyzed to detect changes over time that could be indicators of
component movement or rotor cracking. Information garnered
shows degradation of the bearing/rotor system due to normal
wear, and will also show loss of mass incidents and potential
cracks in the rotors.
Bearing Temperature Bearing temperatures should also be
plotted versus time. Changes to temperature will show bearing
loading changes which can be due to wear of rotating
components or foundation movement. Spikes in temperature
can indicate wiping of bearing babbit or bearing damage.
Finding a temperature rise along with bearing drain flow
changes can indicate pluggage or leakage in the oil system
which would need to be addressed during an outage.
Overspeed Testing Verification that the overspeed trips are
functional and adjusted correctly is essential. Keeping the unit
from running at excessive speed is the best way to minimize
damage to the steam turbine and the surrounding plant. Both
mechanical and electronic controls allow testing of the
overspeed trip system for functionality without actually running
the unit to the overspeed trip setting (107%-112% rated speed
depending on manufacturer and model of machine). This can
be done on a relatively frequent basis. The manufacturer will
have a recommended interval for this. It is best to minimize
actual overspeed testing to minimize the stress the rotating
3
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Outer Shell condition Outer shells can experience cracking
which can propagate due to thermal cycling. This can be
caused by normal cycling, but more commonly is caused by
temperature ramp rates in excess of OEM recommendations.
These occur either during start-up or shut-down. A through
crack in the outer shell is a danger to personnel and nearby
equipment as steam leaks into the plant. Operating and
inspection practices need to be put in place to discover and
repair any cracks to prevent steam leakage into the plant
environment.
blades and rotor will experience. This will extend the life of
the rotor and blades, but it is imperative that “running speed”
testing verify that the trip system is set correctly and is
functional.
Visual inspections of blade path Much information can be
gained by performing visual inspections of the nozzles and
rotating blades. The blades experiencing the most solid particle
erosion wear are the inlet nozzle, the 1st stage rotating row, the
reheat inlet nozzle, and 1st stage reheat rotating row. Also,
water droplet erosion damage is most common on the last stage
stationary and rotating rows.
The inlet nozzle can sometimes be inspected by
removing one control valve and feeding a videoprobe to the
nozzle partitions. Inspections must be performed carefully
because it is possible for the probe to become caught in the
machine. If this happens it may require disassembly of the
machine to remove the probe. However, if only a small portion
of the probe is broken off, the unit can be started up, and the
piece will probably be ingested and passed through the
machine.
Figure 2 - Inlet of 1st Stg Nozzle with 135,000 hours
A better method for inspecting blades is to install ports
designed for the introduction of a videoprobe. The ports are
located so that a borescope or video probe can be fed between
the stationary and the rotating row. In this way it is possible to
view a good portion of the trailing edges of the nozzle while
viewing the inlet of the rotating row. The entire stage of
rotating blades can be inspected for erosion, damage, or
deposits by jogging the rotor through at least one complete
revolution.
Age and Type of Unit Analysis of individual turbine
components must take into account the age and the type of unit.
The number of years that the components have been in service
affects the present condition. High temperature creep will be
affected by the cumulative hours that a component has
experienced high temperatures and pressures. The number of
hours of service will also determine the life expended due to
high cycle fatigue. An additional parameter to consider is the
number of starts. This determines the exposure of the
components to low cycle fatigue. This data must be reviewed
in concert with an actual inspection of component condition,
including NDE inspections.
The manufacture date of a unit can be used to help
determine the type of material and processes used to
manufacture the components. Units manufactured in the 1950’s
typically have more contaminants in the forgings and castings
than units manufactured at a later date when forging vacuum
pouring processes were implemented. Later designs also had
the benefit of learning from the mistakes of the earlier designs.
Shell mounted control valves, flanged intercept valves, and
combination IP-LP rotors were common on early machines and
have their own set of unique challenges. Later designs were
modified to remove these troublesome design features.
Inspection intervals may be limited by one or more of these
design characteristics.
4
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Performance Testing Results It is best to implement a
program to test the performance of the machine at regular
intervals. Many instances of mechanical degradation can be
found by trending performance changes from one test to the
next. Numerous papers and books have been published on how
to diagnose the condition of the steam path and seals using
performance information [1]. This information can be used as
financial justification for a major inspection. The cost of the
disassembly can be only a small portion of the value recovered
from restoring lost efficiency, thereby reducing fuel costs.
Steam Turbine sealing systems have been improved so
that performance does not degrade as quickly as when the units
were placed in service. Retractable seals provide more
clearance during startups, which is when most wear occurs.
This allows the seals to retain their sealing ability much longer.
Other seals have engineered springs or a sturdy tooth to allow
them to be pushed open without extensive wear of the sealing
surface. Some tip seals have incorporated devices to reduce
solid particle erosion. Use of some or all of these components
allows extended inspection intervals without the performance
degradation seen in the past.
Improved steam turbine nozzles and blades are another
enhancement allowing extended inspection intervals. Solid
particle erosion is the most common cause of performance
degradation of these components [2]. New profile designs
resist erosion by changing the area of particle impact and the
velocity. Another performance enhancement is the use of wear
resistant coatings on both existing and redesigned nozzles.
Application of these techniques, especially on inlet and reheat
nozzles, can allow extended inspection intervals with an
acceptable level of performance degradation [3].
Fleetwide Unit Experience It is wise to investigate problems
that are common to the type and size of unit that is being
evaluated. The first step is to utilize the OEM as an
information source. Technical bulletins are issued for common
problems that are being experienced for a particular design of
machine. Information from User’s Groups can pinpoint
common problems and solutions for a specific type of unit. A
company may have a large sample of similar units within it’s
system. This is the best source of information because
operating practices are usually consistent within the same
company. Changes that allow extended operating intervals at
one plant can then be used at another. This transfer of best
practices can quickly multiply maintenance cost savings for an
individual company.
Unusual Operating Conditions Operating parameters need to
be reviewed to determine if the unit has seen unusual
temperature excursions, overspeed events, overpressure
operation, or other occurrences. These events may have
allowed the unit to experience stresses or metallurgical changes
that were not included in the original design.
Analysis of this information has become easier with
data archiving systems combined with spreadsheet and database
software. It is possible to determine the number of hours a
component has experienced above a target temperature or even
in bands of temperatures. Other unusual conditions include
running at high backpressure and running with feedwater
heaters out of service. It is possible to severely reduce the life
of a component under these conditions, so they must be
reviewed.
Base Load versus Cyclic Load Operation It is important to
pay attention to the type of unit operation when determining
inspection intervals. Cycling a unit on and off line degrades the
components more than base load operation. The best situation
for a turbine-generator is to operate it at relatively constant
steam pressure, temperature, and megawatt output. The next
most common duty for a unit is to operate it at full load during
the day and slowly back down to half load during the time with
the lowest demand. The most demanding duty for a unit is
some form of cyclic duty where the unit is taken offline and
restarted 8 or so hours later.
A methodology has to be used which accounts for the
fact the different duty can cause different amounts of wear in
the unit. The technique which is used in this methodology is to
credit each unit with a 25 operating hour “penalty” for a startup. There is no differentiation between a hot and cold start.
Like many engineering “rules of thumb”, it provides a
surprisingly realistic inspection interval. The normal date for
inspection is continually “pulled back” as cyclic duty is
increased. The use of the actual hours of operation as the
predictor for the date of maintenance works quite well with the
starts penalty.
Evaluation of Rotor Bores The OEMs have intervals of
around 6 years between rotor bore inspections for rotors
running at steam inlet temperatures of 1000 degrees F or more.
To extend this interval requires an understanding of the material
properties of the rotor, it’s history, and it’s present condition.
The material properties of a rotor can be determined
on a high level by using a portable metal analyzer or obtaining
the design properties from the manufacturer. It may be possible
to find the actual material tests for the rotor, but it does not
happen often. If the information cannot be obtained in this
way, a ring sample or a disc sample can be taken from the rotor
and tested. This is actually the best method because any aging
effects of the rotor material will be included in the results. This
information will be needed for the analysis.
It is wise to look at past reports and determine the
recorded history of the rotor. This includes rubs, repairs that
have been performed, and visual observations of the material
condition. Notations in the reports may tell of discolored areas,
chemical contamination of blades or wheels, or incidents of
cracking in areas. Previous rotor bore reports will show any
cracks or defects found and any machining done to remove
defects.
The geometry of the rotor and it’s bore needs to be
defined. This information can be combined with the history
and material properties to perform an analysis using computer
software (such as EPRI’s SAFER)[4]. These programs use
probabilistic analysis techniques to develop crack growth
curves. These show the probability of a defect or crack
propagating to failure for different time intervals. This
information can be reviewed and an inspection interval can be
chosen which has a tolerable level of risk. The most common
level is a probability of 1 in 10,000 which is used in the nuclear
industry.
Evaluation of Shrunk-on Wheels Some LP rotors have
wheels mounted on the cigar forging. These wheels are shrunk
onto the forging and kept from rotating on the shaft using a key
mounted in a keyway machined in the wheel. The method for
analyzing these components is similar to that defined for the
rotor itself.
Material samples are analyzed and then
5
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Unit History Specific incidents in a units history may have an
effect on overall longevity and the inspection interval for the
unit. A water induction incident with the subsequent quenching
may result in reduced inspection intervals. Units operated
outside of the manufacturers recommended parameters can
affect longevity. The life of components may be reduced if
they have been exposed to higher than design temperatures.
This exposure can modify the component material properties.
The result can be reduced material strength or cracking of
rotating components. Stationary components exposed to high
temperatures can be pushed downstream in the steam flow with
the result being “blade lean” or “diaphragm dishing”. Units
which have these problems need to be evaluated and a
conscious decision made to determine the next interval. New
components or a radical design modification may have to be
performed if the unit is expected to have an extended inspection
interval.
Table 1
Steam Turbine Inspection Interval Experience
Code/Type
In
Equivalent
Equivalent
Service
Operating
Operating
date
Hours Last
Hours to
Interval
Next
Inspection
Mfg
Rating
(MW)
A
GE
118 SF HP/DF LP
Jan-87
25,000 (1)
B
GE
230 F7
Apr-62
43,000
C
W
172 RT-1606
Jun-59
53,000
D
GE
110 D1
Jun-55
53,000
E
GE
173 F2
Jul-57
58,000
F
G
H
GE
GE
W
73 SF HP/DF LP
181 F7
170 RT-1606G
Jun-90
Jun-60
Jun-50
92,000 (1)
97,000
103,600
I
W
182 BB245A/BB471
Jan-91
111,000 (2)
J
GE
118 SF HP/DF LP
Jan-87
135,000
K
GE
73 SF HP/DF LP
May-92 Unopened
Notes from Last Inspection
100,000 Inspect
8th
stage
diaphragm.
80,000 Replace 8th stage blades
next inspection
80,000 Replaced both rotating
Curtis rows
80,000 Replace 8th and L-0
blades next inspection
80,000 Installed 1 cover on 1st
stage blade, replaced 18th
and 19th stage bucket
covers.
100,000 No steampath work
80,000 No steampath work
100,000 Replaced 1st stage HP,
2nd, 3rd, and 4th stage IP
blades. L-2 row replaced.
100,000 Replace LP row 6R at
next inspection
100,000 Replaced 1st, 8th, and 9th
buckets for SPE.
100,000 (1) No steampath work
(1) 1st
Inspection
(2) 2nd
Inspection
probabilistic analysis is performed to determine crack growth
rates. The software analysis techniques allow inspection
intervals to be set based on the company’s tolerance for risk.
Again, the most common level is a probability of 1 in 10,000.
STEAM
TURBINE
EXPERIENCE
INSPECTION
INTERVAL
Table 1 shows the history of outage intervals for a cross-section
of units. The data points are sorted in the order of the length of
the last inspection interval.
The first thing to note is that the units opened after
approximately 50,000 equivalent hours usually did not need
components replaced. The outcome of the inspection was a
recommendation to replace components at the next inspection.
Only one unit actually needed components replaced at 53,000
equivalent hours. The improvement of unit performance may
have justified the inspection of the other units, but if not, they
could have been inspected in the future.
The second thing to note is that units that are inspected
after over 100,000 equivalent hours require replacement of
steam path components that are considered long lead time
items. Rather than keeping many of these items on hand, they
have successfully procured within normal outage time frames.
While this has been a successful strategy for the units listed, it
is still possible that a unit may have to be assembled with the
existing parts and run for a short interval while parts are being
obtained.
EXAMPLE OF AN EVALUATION
6
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Unit
The target inspection interval for an open casing inspection is
80,000 equivalent operating hours. For a base load unit which
experiences normal maintenance outages, this equates to
approximately 10 years. This interval was chosen because new
units that were purchased or considered for purchase had 10
years as the OEM recommended inspection interval. This was
extending the intervals. Newer units with boreless rotors in
baseload operation have been assigned intervals of 100,000
equivalent operation hours or more. It is important to note that
“equivalent operating hours” can include significant penalties
for starts. Depending on the design of the machine, the start
penalty may need to be adjusted based on experience. The data
Criteria for 80,000
Eq Hr baseline
Condition
Vibration levels changing with
load
Performance trends of section
efficiency
No Change
Financial analysis
justifies inspection
None
None
None
Unit 4
Mid-standard
noise
No change
No change
No change
No change
VWO flow capability testing
Annually
Varies with CF
No change
Erosion within
OEM guidelines
Perform if access is
available
No defects known.
If defects, use
predictive tools to
determine interval.
Annually
None since last
major
inspection
Annually – no
erosion seen
Annually
Bearing temperature changes
Annually
None since last
major
inspection
Annually – no
erosion seen
None since last
major
Annually – no
erosion seen
None since last
major
Annually -– no
erosion seen
NA
NA
NA
NA
OK
Field rewind &
LP shrunk on
disc inspection
Generator field
rewind
OK
5 issued
None since last
major
13 issued
None since last
major
7 issued
None since last
major
15 issued
None since last
major
Tested
quarterly–
within
specification
Tested
quarterly–
within
specification
Tested
quarterly–
within
specification.
Tested
quarterly–
within
specification.
MHS
Weekly-issues
fixed as found
MHS
Weekly–issues
fixed as found
MHS
Weekly–issues
fixed as found
Overspeed testing
Information only
Within company
guidelines
Within company
guidelines
Annually- pass
Annually -pass
Annually -pass
EHS
Weekly–issues
fixed as found
Annually
–
pass
Unit service
Base Load
Base Load
Base Load
Base Load
Cycling
LP L-0 visual inspections
Videoprobe inspections
Historic condition reports &
findings
OEM Technical
bulletins
issued since last major
Temperature excursions
Maintenance testing, greasing,
etc
Oil condition
Control System
Turbine valve stroke testing
No criteria defined
Within OEM
guidelines
Within OEM
guidelines
Within company
guidelines
Unit 1
an indication that component improvements were available to
safely obtain these intervals.
Adjustments to this baseline must be made using the
results of an assessment of the turbine factors discussed
previously. In some cases the interval is adjusted to require
more frequent inspection. In other cases the data justifies
Unit 2
Unit 3
for this paper maintains the “25 hour per start” penalty and any
adjustments are made using the recommended hour interval.
The longest inspection interval to date has been 135,000
equivalent operating hours. This was on a newer unit designed
for cycling with over 450 starts.
7
Copyright © 2010 by ASME
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Table 2
Turbine Condition Assessment & Applicability
Table 2 shows the summary results for 4 units being
assessed. The results use the key factors discussed previously.
The results for known factors support the standard 80,000 hour
interval. The target interval for these units may be shortened to
allow for those factors that are unknown.
CONCLUSION
Downloaded from http://asmedigitalcollection.asme.org/POWER/proceedings-pdf/POWER2010/49354/277/4594093/277_1.pdf by Lynda Casey on 10 September 2020
Recent experience has shown that open casing inspection
intervals can be safely extended through the use of modern
analysis and inspection techniques. The advent of more
powerful personal computers combined with a larger
experience base has allowed us to have confidence that the
computer models are providing correct predictions. Actual
inspections have shown that longer inspection intervals do not
compromise safety, but may require additional maintenance
activities or parts replacement once the inspection is performed.
ACKNOWLEDGMENTS
REFERENCES
1.
2.
3.
4.
Cotton, K. C. Evaluating and Improving Steam
Turbine Performance. Rexford, New York: Cotton
Fact, Inc., 2nd ed., 1998.
Diaz-Tous, I. A., Kahn, A. H., and McCloskey, T. H.,
“Solid Particle Erosion Technology Assessment”,
Advances in Steam Turbine Technology for the Power
Generation Industry, ASME, New York, New York,
October 1994.
McCarthy, D., “Improved Impulse Turbine Efficiency,
Performance, and Reliability Through High Quality
Nozzle and Diaphragm Repairs,” The Steam TurbineGenerator Today, ASME, New York, New York,
October 1993.
Singh, M. P., “Reliability Evaluation of a Weld
Repaired Steam Turbine Rotor Using Probabilistic
Fracture
Mechanics”,
Design,
Repair,
and
Refurbishment of Steam Turbines, ASME, New York,
New York, October 1991.
8
Copyright © 2010 by ASME