ML20095L362
| ML20095L362 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 07/31/1994 |
| From: | Black J, Corkins R, Fron L DETROIT EDISON CO. |
| To: | |
| Shared Package | |
| ML20095L359 | List: |
| References | |
| FOIA-94-507, FOIA-95-A-2 TMTB-0010-0801., TMTB-0010-0801.21-1, TMTB-10-801., TMTB-10-801.21-1, NUDOCS 9601030042 | |
| Download: ML20095L362 (62) | |
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a FERMI 2 MAIN TURBINE' GENERATOR DECEMBER 25,1993 FORCED OUTAGE ROOT CAUSE ANALYSIS REPORT l
JULY 1994 Prepared By Root Cause Analysis Team-J.D. Black __ h R.J. CorkinsWh Mb%g L.G. Fron
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Y EXECUTIVE
SUMMARY
On December 25,1993 the Fermi-2 Main Turbine Generator (MTG) tripped at 1315 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />5.003575e-4 months <br />. The Root Cause Analysis Team identified and evaluated more than 1600 potential causes of the event. The root cause analysis concluded that the event was initiated by the failure of a single eighth stage blade in the front flow of Low Pressure Turbine No. 3.
The Root Cause Analysis Team further concluded that the cause of the eighth stage blade failure is a combination of physical defects and other factors:
1.
Physical defects in the blade which are not operationally related:
a.
The thickness of the blade at the location of the failure was 407c j
less than specified by design documents.
2.
Other factors that may have been major contributors to the failum are:
i a.
rotor-torsional resonance, b.
moisture content of the steam, J
c.
oxygen content of boiling water reactor generated steam.
Confirmation requires completion of finite element analysis, torsional vibration testing to contuin analysis, and fatigue testing. Because of the decision to operate in Fuel Cycle 5 with low pressure turbine seventh and eighth stage blades removed, conditions at the time of failure cannot be duplicated to confirm root cause.
The Root Cause Analysis Team developed recommendations to address all of the above issues in the interim (Fuel Cycle 5) and for the long term (post RF05).
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TABLE OF CONTENTS East 1.0 Introduction 1
2.0 Conclusions 1
3.0 Sequence of Events 2
4.0 Failure Mechanism 3
5.0 Cause Analyses 4
5.1
. Approach 4
5.2 Preexisting Conditions 5
5.3 Torsional Resonance 7
5.4 High Steam Path Moisture 9
5.5 WaterInduction 10 5.6 Unbalanced Steam Flow 11 5.7 Steam Flow Blockage 11 5.8 Materials 12 5.9 Foreign Object 12 5.10 Flow Induced Vibration 12 5.11 Major Resonance 13 5.12 Lacing Spools 14 6.0 Recommendations 15 APPENDICES:
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Time / Events Line
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Event and Causal Factor Chart
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Examples of Analysis Tree and Matrix i
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1.0 INTRODUCTION
On December 25,199'3 Fenni-2 was operating at 93% of licensed reactor power generating 1107 MWe Net. Operators reponed that the plant was operating normally that no abnormal indications were present. At 13:15 hours, without waming, the Main Turbine Generator (MTG) tripped and the reactor scrammed. A turbine blade penetrated Low Pressure Turbine No. 3 (LP-3) Exhaust Hood. Seven vibration caused c damage to the MTG including destruction of the exciter. Hydrogen seal oil, hydrogen, and lubricating oil were released and ignited. The resultant hydrogen and oil fires triggered deluge and sprinkler systems. The severe vibration also damaged General Service Water and Turbine Building Closed Cooling Water supply piping. The resultant oil and water mixture ultimately flooded the Turbine and Radwaste Buildings.
Shonly after the event, site management placed the Turbine Building under quarantine to assure that no evidence related to root cause was lost. A specially formed Turbine Generator Assessment Team developed an Action Plan that contained procedures for the identification, documentation and preservation of evidence. After initial review by turbine and generator equipment expens and a metallurgist, evidence judged to be related to root cause was uniquely identified and placed in controlled storage. A Root Cause Analysis Team (RCA Team) was then formed to conduct a Root Cause Analysis.
The purpose of this report is to communicate the results of the Root Cause Analysis effort and to provide conclusions and recommendations based on informatio,n obtained and evaluated through July 1,1994,
2.0 CONCLUSION
S The RCA Team concluded:
- 1. The MTG tripped as a result of high shaft vibration which actuated the mechanical overspeed trip mechanism. The MTG did not overspeed during the event.
- 2. Thr e m.. m_,initised by the failure of a single eighth stage blade (Blade No. 9) in the front flow of LP-3.
- 3. Blade No. 9 failed through the mechanism of high cycle fatigue.
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- 4. Blade No. 9 was uniquel susceptible to failure because of preexisting conditions t
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- 5. Blade No. 9 may have been subjected to increased steady state and/or cyclic stresses because of any or all of the following: low qualhy steam, low condenser back pressure, rotor torsional resonance excited by electrical system disturbances and/or negative sequence current.
- 6. Blade No. 9 may have had a reduced fatigue life because of the oxygen content in Boiling Water Reactor generated steam.
- 7. Blade No. 9 caused the subsequent failure of four adjacent blades (Blade Nos. 8 thru5).
- 8. Damage to other systems, structures and components, except for 7th stage blading and discs, was consequotial to the failure of Blade No. 9.
- 9. Cracks discovered in 7th stage blade roots and disc serrations during post event examination, existed prior to the event, but were not a cause of the event.
3.0 SEQUENCE OF EVENTS On December 25,1993 Fermi-2 was operating at 93% oflicensed reactor power, generating 1107 MWe net. Condenser back pressure was approximately 1.36 in. Hga, which is among the lowest levels in the operating history of the plant. Operators reported the plant had been operating normally.
c.u Blade No. 9 of the eighth stage front flow (turbine end) of LP.3 of the Fermi-2 MTG
- Y failed at 13:15 hours on December 25,1993. The blade created an approximately 2 ft. by
$2 2 ft. hole in the west side of the exhaust hood and came to rest on a platform above the i E3 West Moisture Separator Reheater (MSR) near a reheat stop and intercept valve. Blade
- "?. 5:2 Nos. 8 thru 5 failed as a result of striking Blade No. 9, but remained in the condenser. A ld blade punctured an approximately 1 ft. by 1 ft hole in the west side of the turbine exhaust
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C,'! E g kC 33 The unbalanced condition associated with the sudden mass loss (approximately 450 lbs) 1~
resulted in shaft vibration at all MTG bearings in excess of recorder range of 37 mils
.E p-p. The MTG overspeed trip was activated and the reactor scrammed. Recorded data
[.9 i.3 indicates the rotor line was running at synchronous speed (1800 RPM) for approximately N" 9 seconds after the start of the event [Ref. 2]. At this time the main generator breaker q
opened. Recorded data further indicated that the machine coasted to 780 RPM in
}; g approximately 100 seconds, at which time the turbine vibration instrumentation signal
~/,3 was lost. Post event inspection of the stub shaft at the front standard, which contains the M:i; :'
two mechanical over-speed trip rings, indicated shaft radial movement of at least 3/16 in.
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TMTB 001o Rev.0 4
This movement exceeds the 1/8 in, design clearance between the shaft mounted rings and trip levers of the mechanical overspeed trip system which accounts for the MTG trip.
The severe vibration of the shaft destroyed the No. I1 bearing and sheared the bolts in the exciter / generator coupling destroying the exciter. Hydrogen seal oil, lubricating oil and hydrogen were released and caught fire. The sprinkler systems and deluge systems triggered by the fire sprayed water into the area that mingled with the oil and the water from damaged General Service Water piping and Turbine Building Closed Cooling Water piping and flooded the Turbine and Radwaste Buildings. One of the vibratory shocks transmitted through the foundation triggered the seismic event recorder.
The Fermi 2 Sequence of Events Recorder print outs, control room log, Shift Supervisor's logs, and selected control room recorded data were reviewed, evaluated, and consolidated into the sequence v events for the period 00:00 hrs on December 23,1993 thru 24:00 hrs on December 25,1993. [See Appendix B) This document was refined and used along with interviews, results of the root cause analysis effort and other information to construct an Event and Causal Factor Chart. [See Appendix C) 4.0 BLADE NO. 9 FAILURE MECHANISM Metallurgical analysis revealed that Blade No. 9 failed due to the mechanism of high cycle fatigue. The fatigue crack initiated about 1 - 1/4 in. above the blade platform on the pressure (concave) side near the trailing edge. The crack propagated to a critical size
%approximately 40 - 50% of the foil cross-sectioQIind the blade failed due to overload.
The separated foil section (approximately 85 lbs) impacted trailing Blade No. 8 and caused it to fail due to tensile overload. Trailing Blade Nos. 7,6, and 5 then failed in succession also due to tensile overload. Remaining front flow eighth stage blades and nearby structures were damaged in varying degrees due to impacts by ejected blades, diffuser fragments and pieces of blade lacing spools. [Ref. 3]
Metallurgical examination of the fracture surface of Blade No. 9 revealed that the fatigue crack progressed in a continuous manner (stable crack growth) with an estimateM
{ninutchom initiation to catastrophic failure (assuming a once per revolution stress cycle). No contribution from stress corrosion cracking was detected. Blade No. 9 was found to be of the proper material heat treated to the specified strength and toughness levels. [Ref. 3]
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5.0 CAUSE ANALYSES i
5.1 Approach a
j The RCA Team utilized the quarantine period to develop its approach to identification of the Root Causes of the Turbine Generator event. In anticipation j
of a very complex problem with many possible scenarios,it was decided to use problem solving tools to facilitate the tracking and systematic elimination of 8
i failure modes.
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Tools used included sequence of events charting, change analysis (Kepner-l Tregoe), and event and cause factor chaning. Integration of these tools provided a i
means of validation and verification of decisions and conclusions reached as the l
analysis progressed.
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An Analysis Tree was developed to provide a relatively simple, graphic method bf assuring that no failure mode was overlooked, panicularly in the early, screening phases of evaluation and de.crmination of causes. The premise is that all possible 4
modes of failure are depicted in a validated diagram, and by addressing each, j
specific tenninal item, the tme failure mode (apparent cause of the problem) will i
become obvious. Team members were assigned responsibility for documenting y yd evaluating each terminal item. While fact-based information was preferred, /
I expen opinion was an accepted basis for a decision.
In the case of the Fermi-2 MTG failure more than 1600 potential causes were identified that could have contributed to the event. yin order to assure that these many items were addressed, a matrix was developelto track each item to resolution. Examples of the analysis tree and summary pages of the matrix are provided in Appendix D. Working copies of the analysis tree, matrix, and other key information used in the root cause analysis are stored in the Fermi-2 records repository)
In implementing the process it was imponant that the differences between apparent causes and root causes be understood. An apparent cause of a problem is best described as an identified failure mode. e.g., a shaft fails due to high cycle fatigue (the failure mechanism) due to shaft misalignment (the apparent cause). A Im1 cause is best described as a factor that, if corrected, would have prevented the failure from happening, e.g., poor work practices and defective testing that allowed the misalignment to occur.
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mn 0010 Rev.0 The approach described above narrowed the 1600 possible causes down to ten credible apparent causes:
- 1. Preexisting Conditions
- 2. Torsional Resonance
- 3. Moisture / Water
- 4. Unbalanced Steam Flow
- 5. Steam Flow Blockage
- 6. Material 7, Foreign Object
- 9. Major Resonance
- 10. lxing Spools These apparent causes and their disposition are described in the following sections.
5.2 Preexisting Conditions In the course of the investigation of the factors contributing to the failure of Blade No. 9, two categories of preexisting conditions were identified and are believed to have had a significant role in the failure. These conditions are described and discussed below.
The first category is physical defects (not operationally-related). Detailed inspection and metallurgical examinations of Blade No. 9 revealed two characteristics which would make it vulnerable to steady state and cyclic load conditions.1) The trailing edge of the foil section at the point of the fracture was found to be approximately 40% thinner than blades which had not failed. 2) A residual tool raprk was found on Blade No. 9 at the point of initiation of the fatigue crackghe mark was oriented perpendicular to the longitudinal axis of the blade foil. The mark had agharp 45* "V-Notch" geometry and was approximately 0.003" deep 3 oth of these conditions are considered undesirable B
from the standpoint of affect on blade life. [Ref. 3) These defects are not characteristic of operationally-caused wear. The RCA Team considers these two observations to be significant causal factors relative to the failure of Blade No. 9.
If eighth stage blade fatigue life was a generic problem, other blades with some evidence of fatigue cracking would be expected. Visual and non-destructive examination of eighth stage blades removed from the LP rotors revealed no e 1l S
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Rev.0 evidence of such cracking. The trailing edges of all eighth stage blades on the LP rotors were measured. Blade No. 9 exhibited the thinnest trailing edge. This observation was statistically significant in that its measurement was more than three standard deviations from the mean of the total population. Therefore, the fatigue failure problem is not generic, rather it is believed to be limited to Blade No. 9 due to its trailing edge and surface fmish.
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. The eighth stage blade failure on Dec. 25,1993
. Seventh stage blade root cracks observed on LPs 2 and 3.
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. Seventh stage blade root crack identified in 1989 (RFOl). [Ref. 8)
. Fifth stage blade failure identified in 1989 (RFOl) resulting in l
redesigned blades. [Ref. 7]
. Founh stage blade failure identified in 1990 resulting in redesigned shroud under-strapping. [Ref. 7]
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. Turbine / Generator System torsional vibration analysis was not available until requeste.d bf Detroit Edison in February,1994.
. There is no evidence suggesting the BWR operating environment was
@yg considered in the design of the prototypic Fermi-2 blading. [Ref.10] The g I.,;f' concem with the BWR operating environment is the effect ofincreased levels of oxygen in BWR steam (18 ppm) on blade material fatigue strength.
7 The RCA Team focused on two issues, namely that the blade design may not have adequately considered all potential blade loads expected within the envelope of operation of the plant, and the design may not have provided sufficient margin for the expected degradation of the strength of the blade material in the environment of BWR-generated steam and the local conditions of the eighth stage.
[The RCA Team had neither full access to the eighth stage design calculations, nor hard data to substantiate the effects of BWR steam, nor expertise to judge the applied margins. However, based on the successful application of the eighth stage design at two other PWR locations without any failures, the RCA Team n
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Moncluded that the design was not significantly deficienthowever, the RCA j
Team did identify a different blade failure history at Fermi 2 (BWR) compared to sister MTG's at PWRs. There is also a perceived different blade failure history between BWRs and PWRs with other manufacturer's turbines Consequently, the l
RCA Team concluded that the presence of much higher levels of oxygen (1000 ti es)in BWR-generated steam may be a contributor to the failure of Blade No.
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, and it appears that this may not have been considered in the blade design.
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4-f The RCA Team commissioned Stress Technology Inc. (
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. inde ndent analysis of the Fermi-2 eighth stage blades i (n fin repon of results is expected by Ju 9,1994.
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l 5.3 Torsional Resonance I
i Negative sequence current can have an adverse effect on turbine generators if the complete rotor assembly is torsionally resonant at 120 Hertz. The negative sequence current imposes an altemating torque on the generator rotor and turbine rotors, causing the rotors to altemately twist in addition to their normal rotation.
Because of the large size and complex shape of the complete turbine generator i
rotor assembly,it has many frequencies at which it is more likely t'o twist, called torsional resonant frequencies. If the turbine generator rotors are torsionally i
resonant
- 120 Henz, the combination of torque due to negative sequence current and resonance can lead to high stress in the turbine blades.
j There are several sources of negative sequence cunrent but the most common are load distribution and system transients. There is always some unbalance in the system, therefore there is always some source for the torsional resonant excitation j
frequency [Ref.1]
ANSI Standards and manufacturers provide guidelines for acceptable negative sequence current for synchronous generators. There is no comparable standard for turbines. Typical operating negative sequence current, as indicated by the panel meter, is reported to be usually less than one percent for Fermi-2. This indicates that the steady state negative sequence cunent was well within the manufacturer's guidelines and wc!) within the industrf accepted guidelines. At Fermi-2, as well as all other Daroit Edison plants, the negative sequence current is not automatically r4 wrded. This is consistent with industry practice.
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r-Therefore if torsional resonance originated with the electrical system, it would have had to occur with a relatively weak 120 Hz negative sequence current, or as the result of a transient event.
N There were two system transients on December 21,1993, one at about 07:30 hrs.
hd another at about 11:30 hrs. These transients were due to switching of generating units at Ludington, a common event not unique to the time of failure.
These could be the source of an impcise excitation for torsional resonance. There
, ere no subsequent transients up to and including December 25,1993.
w At time of the design of the Fermi-2 Turbine Generator (circa 1970) torsional vibration was considered only for rotors and couplings. Blades and discs were not addressed. This was accepted design practice at that time. More recent analyses have utilized advanced. xxieling capabilities that take into account the flexibilities and interactions of rotors, shafts, discs and blades.
Successful prevention of double frequency torsional resonance requires [Ref. 5]:l 1
. Recognition of the existence and complex behavior of blade-coupled high-frequency torsional modes through appropriate modeling techniques.
. Factory and field testing so specific designs can be verified.
. A design approach with rules that integrate the above steps, enabling the designer to tune torsional mode responses away from 120 Hz.
a A Turbine Generator System analysis for Torsional Resonance of the Fermi -2 system was completed by GEC ALSTHOM in May 1994 [Ref. 6]. They concluded that results were satiyactory. The analyses were reviewed by an independent third party and additional information regarding system parameters which will aid in evaluating the potential for a resonant torsional mode haye been requested. This matter has not yet been resolved.
The RCA Team recogr#ed that the GEC LSTHOM torsional analysis was not validated by any testsy Experience reported by other vendors indicates that computer analysis of toisional resonance without incorporation of test data is invalid, especially at the higher modes in the 120 Hertz rang @onsequently, the RCA Team is unable at this time to prove or disprove torsional resonance as a root cause. Since the Fermi-2 MTG is being reassembled in a different configuration than existed at the time of the event, verification testing is not i
possible. Later testing of the revised rotor assembly and comparison with the I
appropriate torsional model will provide additional useful information.
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NTB 0010 Rev.0 5.4 High Steam Path Moisture The steam supplied to the Fermi-2 turbine is near-saturated, and a significant fraction condenses to moisture as it passes through the tu ine ; team path. Steam exiting last stage blades normally contains approximatel 2%j nioisture. The moisture forms as droplets which impact the rotating and stationary blades and accumulate and are shed from the trailing edges as larger droplets. The moisture is also slung radially by the centrifugal force, accumulating to some depth at the outer ring of the diaphragm. Moisture is removed between stages and piped to feedwater heaters with extraction steam.
p Thermodynamic cycle a.;alyses, using a refined Syntha II model [Ref. 4), indicate steam path moisture content to be up to 1% higher than design heat balance levels due to high load, condenser pressure below 1.5 in Hga, poor MSR performance, operating wi,th Fos. I and 2 feedwater heaters out of service, etc3This is an increase ofjLO expected to be$n the volume of moisture passed by the turbine stage and withi the capability of the stage to pass without damage.
Other observed deleteriou ects of high steam path moisture am erosion of the leading edge of rotating blades. stage efficiency loss. These effects are not a cause of the failure of Blade No. 9.
A postulated mechanism to explain observed turbine blade failures is described as a "proud" olade,i.e. one that projects radially or axially to a greater extent than the majority of the blades. Due to manufacturing and installation variations, one blade will be proud on each row to some exte t. The proud blade is subject to additional loads in the presence of moisture.
nshrouded blade tips act as pumps, propelling the surface moisture through the stage. The susceptibility of a proud blade to damage is a function of many factors, such as blade strength, shroud and grouping arrangements, moisture level, and rotating blade tip clearanchTwo potential failure mechanisms are proposed.
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- a. As the proud blade pumps moisture, it untwists due to the retarding force.
This causes further untwist of the blade to catch more moisture and incrusing the retarding force. At some threshold, the blade becomes overloade.d and experiences permanent deformation or breakage.
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- b. The depth of water that each blade pumps varies around the circumference of the circle of rotation, due to manufacturing and assembly variations, gravity, etc. The resulting retarding pumping force on the blade is a cyclic
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j The RCA Team was neither able to confum nor deny the presence of high
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moisture in the steam as a cause of the failure of Blade No. 9 for the following i
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- a. Blade No. 9 was extensively damaged during the event, so it is not possible to determine if any deformation occurred prior to failure. No 2
i records are available to confum ifit was a proud blade.
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- b. The conditions that existed on December 25,1993 can not be repeated to l
establish a definite cause-effect relationship.
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- c. ' Damage to other blades of the front flow of LP-3 judged to be i
consequential to the failure of Blade No. 9 makes it ditficult to establish if j
any blades were damaged by the presence of excessive moisture.
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- d. Review of the operating history failed to reveal any abnormal event that 1
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resulted in high moisture in LP-3 that was coupled in time to the failure of Blade No. 9.
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5.5 WaterInduction i
A source of dynamic loading of eighth stage blading is water induction involving j
reversal of flow in the extraction / drain lines to the Nos. I and 2 feedwater heaters 4
under conditions which could cause a " slug" of water to impact eighth stage j
blading. The Nos. I and 2 heaters were specifically evaluated because they do not i
have "non retum" valves between the LP cylinders and heater inlet nozzles. An I
i independent review of No. I and 2 feedwater heater system designs for i
conformance with ANSI /ASME TDP-1-1985 concluded that no significant
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deficiencies existed in the heater designs. In addition, no significant structural i
damage, or evidence of a flood up condition was identified during inspection of l
extraction steam piping, heater intemals, and LP turbine cylinder halves. Rapid load reductions can result in interstage turbine pressure becoming less than the heater shell pressure, creating a potential for reversal of fluid flow. A review of operating thtory indicated that no load change had occurred for ten days prior to the event.(Thermodynamic analysis [Ref. 4] and fluid dynamic analysis [Ref.12) concluded that water induction events associated with the Nos. I and 2 feedwater j;
heaters are not likelyyBased on the foregoing the RCA Team concluded that water induction is not a root cause of the failure.
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TMTB 0010 Rev.0 5.6 Unbalanced Steam Flow The following cases of unbalanced steam flow were considered:
- a. Between the three LP turbines. The plant was operated for a period of time in December 1993 with one reheat stop valve closed.
Thermodynamic analysis of the operatir.g condition reveals that this condition results in unbalance between the MSR flows, but produces essentially no effect on the individual turbine section flows. Therefore, this is not a root cause for the failure.
- b. Between the two ends of LP-3 turbine. The steam flow balance between
.the two end flows of the LP turbines is a function of the flow-passing area of each. Visual exarnination of the stationary and rotating blades of LP-3 subsequent to the event revealed no significant difference between the two ends. Consequently this is not a credible failure cause.
- c. Between the stationary or rotating blades. Inspection of the rotating and stationary blades of LP-3, after the event revealed damage to both rotating and stationary blades of the front flow of the eighth stage. The RCA Team concluded that the damage was consequential to the failure of the eighth Blade No. 9, and did not exist prior to the event. All of the rotating and stationary blades of all stages of all the other LP turbines were essentially undamaged capable of passing normal steam flow. Therefore, unbalanced flows between the stationary and the rotating blades was ruled out as a root cause.
5.7 Steam Flow Blockage With the exception of the eighth stage of the front flow of LP-3, no blade damage was observed during disassembly inspection. No foreign objects that could block flow through any of the LP turbine flows were found. Therefore, steam flow blockage was not a root cause.
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Rev.0 5.8 Materials Samples from Blade No. 9 and other blades were subjected to a number of metallurgical, chemical and physical tests. Th blades were found to have been made from the specified material, a modified @-chrome allohd heat treated to specified strength and toughness levels. Therefore, deviation from material specification was not a root cause. [Ref. 3]
5.9 Foreign Object Foreiin objects such as tools, weld slag, valve parts, etc. are an occasional cause of steam turbine bladinc.iamage.[ypically the foreign objects are carried by the inlet steam and cause damage to the admission stage and downstream stages. In such events, typically all blades are damaged to a similar degree, resulting in closing of the flow-passing area of the rotating and stationary blades. Numerous marks are noted on the blade leading edges from the impact of the foreign objects and broken blade piecch Examination of the eighth stage blades following the event revealed none of the characteristics of foreign object damage. No foreign objects were found in the condenser that could have been in the eighth stage. No foreign object damage and no failed blades were observed on the seventh or earlier stages that could have been a source of debris to cause failure of the eighth stage. Therefore, foreign object damage was not the cause of the failure of Blade No. 9.
5.10 Flow Induced Vibration Stalled flutter is a potential failure mechanism of turbine blades that has been observed to occur in free standing blades at low flow, high back pressure conditions. The angle ofincidence of the steam on the rotating blade at low flows is such that unsteady flow, or stall, occurs, identical to airplane wings under similar conditions. If the conditions persist, the blade is subjected to cyclic loads and may fail from fatigue. Turbine blades are generally protected from stalled flutter by providing a trip at high back pressure, typically 5 in. Hga. Fermi-2 has a high back pressure alarm and trip set point of 4.5 in. Hga. An approach to preventing stalled flutter is to provide a continuous tie of the blade tips, such as by the use oflacing spools. Discussions with industry experts indicate that no instances of stalled flutter have been reported in turbine blades with a continuous tie. Since the Fermi-2 eighth stage blade failure occurred at high load, and the
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TMTB 0010 Rev.0 eighth stage blade design utilizes a continuous tie, and there is no evidence to suggest that a lacing spool was lost prior to the event, stalled flutter is unlikely a cause.
Unstalled flutter was ruled out as a cause for the following reasons:
- a. Unstalled flutter has only been observed in free-standing blades.
Since the Fermi-2 eighth stage blades are continuously coupled by lacing spools, the blades cannot vibrate independently as would be required for unstalled flutter.
- b. Unstalled flutter has only been observed in precision-manufactured i
blades. Unstalled flutter requires that adjacent blades vibrate at the
, exact same frequency. Only modem precision forging techniques can consistently produce blades with the required identical natural frequencies. Since the Fermi-2 eighth stage blades were produced from envelope forgings and then machined and hand-finished to final dimensions,it is unlikely that adjacent blades have identical resonant frequencies.
As a further check on blade vibration at high flowh Extended Strouhal c.
Number was calculated for the eighth stage blade row, per techniques of Siemens. The Extended Strouhal Number was calculated to be 0.017E-3, well below the threshold of 0.29 E-3 where self-excited blade vibration was observed in free-standing bladeQThis analysis confirms the conclusion that unstalled flutter is an unlikely cause of the eighth stage blade failure. [Ref. I1]
5.11 Major Resonance Turbine manufacturers typically test assembled blade rows on a prototype wheel to determine resonant frequencies. Accumulated test data and analytical techniques allow these frequencies to be calculated with some degree of precision.
Typically the last two or three stages of turbines require detailed design and test to avoid major resonance. The blades are tuned by design and tested during manufacture so that critical frequencies am avoided.
Experience indicates that blade failures due to major resonance are likely to occur after a few months of service as demonstrated by the fifth stage blade failures at Fermi-2 in 1988 and 1989. Typically many cracked or failed blades are observed s.
C. -
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-[$.ki b. N a....
TMTB 0010 Rev.0 as all of the blades respond similarly to the forces that are common to all of the blades.
Major resonance is not a likely cause of the eighth stage blade failure due to the extensive frequency testing perform:d on the prototype blades during the design phase /3 Campbell Diagram of the eighth stage provided by GEC ALSTHOM indicates the first three vibration modes are 11 cl
'ble resonanchln addition, the long service life of these blad d1 longer service life of similar blades at other plan I
dicates that the blades are well tuned to avoid major r ce. The fact thaamly one blade j
(Blade No. 9) shows evidence of fatigue indicates that the blade row is well-tuned to avoid major resonance.
5.12 Lacing Spools The eighth stage blades are linked by lacing spools with one spool between each blade. The loss of a spool or spools would allow a blade to become free-standing and possibly more susceptible to excitation. The loss of one lacing spool would produce a detectable change in turbine vibration [Ref 9). Review of vibration data and Control Room strip chart data showed no vibration changes indicative of mass loss from the MTG occuncd from the start-up from RF03 to the event on l
December 25,1993. The RCA Team considered a scenario wher~ two lacing i
e spools could come free at one end, but remain in: place on a blade foil, resulting in a free-standing blade. This condition would not change rotor balance and I
therefore could go undetected. The RCA Team concluded that it is extremely unlikely that lacing spools would remain in-placpender a 10,000 lb. centrifugal force) e, -
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i 3
6.0 RECOMMENDATIONS l
j The RCA Team is aware of the decision to operate in Fuel Cycle No. 5 with low pressure
[
turbine seventh and eighth stage blades removed and pressure plates installed and to replace the low pressure turbine steam path in RF05. Therefore, no recommendations l
penaining to return to service with existing seventh and eighth stage blades installed have been provided. The RCA Team recommends the following:
1
- a. Complete a torsional vibration analysis for the Turbine Generator System that will exist in the restart following RF04.
i
- b. Conduct a resonance test during the stan-up following RF04 to verify the torsional vibration mod ' used.
I
- c. Repeat recommendations a and b whenever the main turbine generator system is modified in a manner that affects MTG system response to torsional resonance excitation.
j
- d. Measure and record generator negative sequence current during " start-up" and full j
load operation to characterize seasonal and holiday system tendencies.
{
- e. Review results of any torsional resonance analyses and confirmatory testing j
performed on similar machines.
l
- f. Upgrade MSR to unprove moisture removal efficiency and reheat performance.
- g. Ensure that the replacement steam path component designs address all anticipated service loads and operating conditions.
- h. Ensure that the Boiling Water Reactor steem environment is considered in the design of replacement components.
- i. Ensure that replacement steam path components are manufactured and installed to design specifications.
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15
TMTB 0010 Rev 0' APPENDIX A REFERENCES 1.
Technical and Engineering Services Repon 94J70-21, " Fermi-2 Turbine Generator Assessment Team Root Cause Analysis of the Turbine / Generator Incident of December 25,1993 - Electrical Repon", June 20,1994
- 2. Technical and Engineering Services Repon 94R71-1, " Analysis of DVA Vibration Alarm /Coastdown Magnetic Tape for Fermi 2 MTG", Jan. I1,1994
- 3. Technical and Engineering Services Repon 94V70-13 " Metallurgical Analysis of Fenni-2 LP3 8th Stage Turbine Blading ", June 20,1994
- 4. PEP 94-025, " Thermodynamic Modeling and Analysis of Fuel Cycle 4 (In Suppon of Root Cause Investigation into December,1993 Turbine Failure)",
July 11,1994
- 5. Hurley, J and Welhoe>., 2, ' Turbine Generator Designs and Testing for Prevention of Double-Frequency Torsional Resonance", American Power Conference. April 1989
- 6. GEC ALSTHOM repon " Torsional Vibration of Fermi-2 Rotor / Blade System", Transmittal letter P.M. McGuire to L.G. Fron, May 6,1994
- 7. DER 89-0331 " Manual Scram was initiated due to high MTG vibration" (LER 89007)
- 8. DER 09-1242 " Stage 7 Turbine Blade Root Crack LP-2 Generator End"
- 9. Memo, L.G. Fron to RCA Team. " Analysis of Fermi-2 Main Turbine-Generator Vibration from November 1992 to December 25,1993", Mar. 22, 1994
- 10. Merz and McLellan," Detroit Edison Company Eruico Fermi Atomic Power Plant - Unit 2 Turbine Generator 2 Design Review 46" Long Prototype Last Stage Blade", circa 1973
- 11. Memo, with attachment, D.B. Smith to G. M. Trahey, " Turbine Blade Flutter" July 6,1994
- 12. TMNF 94-0047, " Evaluation of Conditions Which May Cause Reverse Flow from No. I Feedwater Heater to LP Turbine" r:
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- m 12/25,93 4D099 40061 Numerous Caeing Main TLO TroutAs Cleered Trouble Cleared Trouble Cicered Stator Coolard Leakage HI H2 p to bWNM g 09.0923.229 O 09:11:04.899 9 09.50.2F.511 AlarmOcar O E I8 # 338 1
017R12 000R12 011R12 t
Sequences W30 0929:21.897 09:1123 265 09.50:26.151 i 00 02-01:12 M N 288 D
head tank or system Expected - See ON Transfer 119N30 10:31:36 964 5,W?
C.H Log Cleared 06:19:40.338
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SEISMIC SYS NOTE At Ihe ame of the event. eclect SW for vtbredon EVENT / TROUBLE es foNows: PED-1.10. & il SHAFT 9 13:15:47.475 S.P Shat EED HI 6
3 EM 1.10. & 11 8
4 40006 2-8 12 6
9 10 5
40003 Turbine Overspeed Elect Per P. Hudson.1/1044 CKT Fault (dtHrtergized)
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gg 140N30 13:15:47.406 NOTE Also como in W LOAD TRIP
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]
PED 5 mile BRG # 5 - 13:15.47.001 g
BG 4'12154 8 Delta p HI S P.O.01 g Also triggers BRG # 7 - 13:15:47.624
% mm, BRG # 2 - 13:15 47.637 13:15:47.413 BRG #10 - 13:15:47.664 13:15:47.475 j
BRG # 3 - 13:15:47.682 y
BRG # 1 - 13:15:47.739
, i3 4D013 40002
..U '
Main Turbine VIbrn H NOTE: W Run-Up Trip Alemf UA T1 wet 9e VIv Feuil
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BRG #9 - 13:15:47.443 BRG #8 - 13:15:47.482 2.
- 11-13:15:47.532 13:15:47.529 BRG #4 - 13:15:47.514
- 8-13:15.47.599
{
BRG #11 - 13:15:47.530
- 9-13:15 47.600 CU BRG #5 - 13:15:47.534
- 5-13:15:47.908 BFIG #7-13:15:47.558
- 7 - 13:15:47.822 BRG #10 - 13:15:47.582
- 4 - 13.15:47.632 BRG #3 - 13:15:47.598
- 2 - 13:15:47.648 BRG #1 - 13:15:47.617
- 3-13:15:47.654
- 10 - 13:15:47.655 5 1-13:15:47.738 Page B 4 i
.m_-_.
f MAIN STEAM BYPASS VALVES OPEN j
13:15:47.535 13:15:47.531 thru 13:15:47.697 13:15:47.595
?
No1Mndow IFS Actuagon 40005 None t
TuMne 0/5 MediTrip B2 - 13:15:47.555 Gen. Uguld '
- Mah Steam Stop l
SP-110%
B1 Y[
Detector M Velves Close A2 082N30 13:15:47.531 A1 - 13:15:47.562 88N30 13.15:47.803 13:15:47.790 l
No Window I4PS ActueGon 40001 None TurNne Trip fieleyTripped B2 - 13:15:47.581 U/A HP Stop Meh steem Stop-Thrates 81 1
Vefve Fault Velve 1-2 Turbine Trip
{
A2 Y
A1 - 13:15:47.505 i
13:15:47.543 13:15:47.001 13:15:47.791 30089 40001 None f
Main Steam Bypass Turbone ControlViv Feet EW Govemor valves Open Mein Steam Stop-Throtte Closure (B1. B2. A2. & Alf2)
Trouble Vefve 3-4 Turbine Tetp 201N3 13:15.47.587 Betwt 1315:47.544 &.550 13:15:47.897 13:15:47.801 Note: 'VC1 Speed Descrepency Channel 1 ve Channel 3 Speed Signal Mod F t
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- 6 Feedwater Hester ESS Check Volvos Oooo 13:15.48.155 - 13:15:48.356 40028 s
OS Foodwnfor Hester ESS Check V!v Closed 4D009 21PN30 13:15:48.155 Turbine VIbm M - M (See Pg. 4 for Setpoints)
BRG # 9 - 47.871 BRG # 4 - 48.125 40093 BRG #10 - 47.956 BRG # 6 - 48.156 BRG # 11 - 47.975 BRG # 7 - 48.165 DetraHng Tank Turbine BRG # 1.48.073 BRG # 2 - 48.190 End Level HRo BRG # 8 48.064 BRO # 3 - 48.247 221N30 13:15:48.316 40004 Stator Water Flow Low Fault 26 g,.
ESS Check Viv Closed 978 185N30 13:15:47.897 q : o - e.
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Page B-6 s-an u, I
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-! th j,0 Secored l
^ n Approx. i3:16:48.406 L.
3 & 4 Feedwater Healer ESS Check V!vs Close 13:16:46.432 - 13:16:46.706 None 040006 LP Stopnv 3-4 Turthw Trip t.k*tred Actualor (C.tP)
Interceptvtv Fault 077N30 13:15:46.416 161N30 13:15:46.456 04D026 04D025 Main Turt4ne AS Fdwtr Htr Main Turthw 3N Fdwer Hir ESS CheckViv Closed ESS Check Viv Closed 214N30 13:15:46.432 211N30 13:15:46.516 040026 04D026 Main Turbine 4N Fdwtr Htr Main Turbine 4N Fdwtr ESS Check Viv Closed Htr ESS Check Viv Closed 213N30 13:15:48.447 213N30 13:15:48.635 s'
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Mein Turbine 5N Fdwtr Htr IP Exhaust Spreys On Pump Auto Start ESS Check V1v Closed
(<12 psid OR to Gen 025N30 13:15:49.515 (97 GPM Fbw)
(5S Comes h D!ft Pressure) et 13:15:59.382) 091N30 13:15:50.991 032N30 13:15:48.999 040050 215N30 13:15:50 058 Stelor Coolant Pump 040079 hM 04D035 038N30 13:15:49.573 yre M Og LP Exhaust Sprey Emergency Pump Cesing Hydrogen Emergency Pump Auto Auto Start Gee Pressure Low Start (100 PStG 1)
(<10 peld OE to Gen -
040004 Normal 15 peld) 096N30 13:15:50.167 023N30 13:15.51.195 SealOIWGee DIff 034N30 13:15:49.125 Prm W FeuR 153N30 13:15:49.765 2/4 SW w/eny SW 9
~
- L 10 peld x 2 = trip
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High & Faut (SP = 26.5 In Hg) 13:15:52.963 thru 13:15 53.572 040006 04D010 04D10e 040047 Seel OR Strainer Offt.
BRG #6 Shaft DWf.
Condenser Pt. wure High LP bhouet Coaang H2O Pressure High bpenelon Negative (PDC 9107 Rev.C)
Strainer Diff. Press. High 074N30 13:15.51.396 179N30 13:15.52.190 192N30 13:15:52.953 089N30 13:15:53.766 04D004 04D114 040073 Reeffler Coolant Une #4 Thrust BRG 08 Press Generator H2)H2O Diff.
Low Fbw FouM Low (SP = < 8 pelg)
Pressure Low (SP = 104(r Movement) 136N30 13:15 51.556 067N30 13:15:52 599 000N30 13:15:53.091 225N30 13:15:54.099 None 04D006 04D004 040077 Reciffler Coolant Line #4 Seel 08 Strainer DNf.
Condenser Pressure AVR Channel B Tripped to Flow Turbine Trip Pressure High High Feldt (4.5* Hg) 149N30 13:15:51.559 074N30 13:15:52.720 151N30 13:15:53.572 133N30 13:15:55.212
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thru thru i
13:15:55.644 13:15:57.1M j
l 1
l 04M Pt.2006 BRG Og 4D065 None P Lo Faut
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E. N W tow FeuR (< 10 pelg)
String Operated Pump Off 150N30 13:15:55.311 114N30 13:15:57.161 037N30 13:15:57.229 i
040061 04D008 40121 None AVR On ManuelContici Turbbe OE Pump Auto 345 KV Breaker W. Stafor Coolant Start (10 pelg1) 102N30 13:15:55.658 Pos. CF %
Pump Off 00$N30 13:15:55.351 021S31 13:15:57.183 037N30 13:15:57.238 i
040018 04D002 BRG #1 Sher DNf.
4D123 4D144 bpenekm Poeltive Turbhe Emergoney 08 345 KV Bresher Gen Fleid Breaker Open Pump Auto Start (10 psigl) 174N30 13:15:55.992 Pos. CM Open 006N30 13:15:55.644 Of7S31 13:15:57.164 142N30 13:15:57.306 040018 BRG #6 Sher DNf.
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ESS CheckW Closed tm Flow FmAt Cleared 813:15:59.239 (SN Closes et 13.15.50.058) 187N30 13:15:57.397 218N30 13:15 59.382
~
40004 40027 Stator Water Flow to FatAt 18D027
- 5N Fdwtr Htr ESS Re Alam Check W Closed 185N30 13:15:58 038 (Originally Closed et 008P90 13:15:59 599 13:15:50.068) 215N30 13:15:59.815 21U Turbine Butding HVAC Tripe
+
1 13:15:58.226 GMFrM.%
None 13-15:58 234 Racttner Coolert Une #1 167N30 13:15'59 894 Lo Flow Turbine Trip 4D070 098N30 13:15:59.945 Gen. Inlet Water Temp Hi t* *.
278N30 13.15 58 530
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Page B-11
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APPENDIX C EVENT & CAUSAL FACTOR CHART FERMI 2 MAIN TURBINE GENERATOR EVENT e
r,p g Blade No. 9 On Front Fkm of LP. 3 Falle WItNn One Revolutlos InMetes in s
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APPENDlX C EVENT AND CAUSAL FACTOR CHART Lwing nyerogen ne.ctor Scrome On o.o
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Turbine Control Velve Y
Are Destroyed And ResuRs in Fire See og Y
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Rotor-Line Due To h Are Dameged N
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System Actustes e
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Blade Failuree Other Structures
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in Rotor Line Are Damaged E
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LP-3 TURBINE FAILURE BLADE FAILURE
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CODE TITLE coro REFERENCE NO.
DONE SIG BL-1 BLADE FAILURE
- }'. T@tH1 aflf.Mif.4 Mn.. JW.D"M3AMUW8 5,TF BL-1 A MECHANICAL WEAR AND /OR FRETTING
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BL-1 A l.1 DESIGN q
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1 0
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( BL-1 A1.2 INSTALLATION D. SMITH TO G. TRAHEY TURBINE BLADE FAILURE: 4/5/941 1
0 u.
BL-1 A1.3 OPERATION
- M D. SM11H TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
BL-1 A1.4 MANUFACTURE w;
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BL-1 A1.4.2 RATED SPEED D. SMITH TO G TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
ero BL-1 A1.4.3 SPEED CYCLES D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE 4/5/94 1
1 0
o' BL-IA1.5 REPAIR W
D. SMITH TO G. TRAHEY; TURBINE BLADE FA: LURE; 4/5/94 1
1 0
l BL-1 A2 LASHING SPOOL i
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': t TG EUI' BL-1 A2.1 DESIGN im.. D. SM11H TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 I
I I >p BL-1 A2.2 INSTALLATION D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 I
I 1
BL-1 A2.3 OPERATION
- P..m D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE
- 4/5/94 I
i 1
BL-1 A2.4 MANUFACTURE M
i M.'
Nl4 M + :(.Pi? ~ 'id; @Ti M jQTS; I,E BL-1 A2.4.1 TURNING GEAR r4 e D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE 4/5/94 1
1 0
BL-1 A2.4.2 RATED SPEED M."l> D. SMITH TO G. TRAHEY: TURBINE BLADE FAILURE 4/5/94 1
1 0
t BL-1 A2.4.3 SPEED CYCLES
. M F-D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 O
BL-1 A2.5 REPAIR
.W D. SMITH TO G. TRAHEY; IURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A3 SHROUD 1:!>.6M;F2Df31NPty.YEC 4l-W h ' $_".F R E l @ UE: PI T'I!'. W BL-I A3.1 DESIGN
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1 0
BL-1 A3.2 INSTALLATION M U: D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A3.3 OPERATION
- b D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE
- 4/5/94 1
1 0
BL-1 A3.4 MANUFACTURE
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.i % D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A3.4.2 RATED SPEED i, y D. SMITH TO G. TRAHEY; TURBlNE BLADE FAILURE: 4/5/94 1
1 0 g BL-1 A3.4.3 SPEED CYCLES 9. D. SMITH TO G. TRAHEY; TURBlNE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A3.5 REPAIR iii1 R D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A3.6 RUBBING J. 4. D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A4 IENNONS (PJ d S W'W f
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BL-1A4.1 DESIGN r' D. SMITH TO G. TRAHEY; IURBINE BLADE FAILURE; 4/5/94 1
1 0
BL-1 A4.2 INSTALLATION D. SMITH TO G. TRAHEY; IURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1 A4.3 OPERAllON D. SMITH TO G. TRAHEY TURBINE BLADE FAILURE: 4/5/94 1
1 0
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7/13/94 7:12 PM Page D-2 pl & *, %
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APPENDIX D LP-3 TURBINE FAILURE BLADE FAILURE code nTLE 0 010 REFERENCE NO.
DONE SIG BL-1 A4.4 MANUFACTURE u f#; W.E L3fW ".'Bif M rijyrR@ gggnagg M W; q)-
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BL-I A4.4.3 SPEED CYCLES D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 if:
1 1
0 J-N BL-1 A4.5 REPAIR D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
'i en D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-2A2 FLUID WEAR (EROSION) v t. P F "N TI M T t.5.: Mit?TA'
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- %a D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-2A2.1.2 SOUD PARTICLE EROSION Mi* D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
BL-2A2.1.3 STEAM QUAUTV DEGRADATION p;b BL-2A2.2 TRAluNG EDGE D. SMITH TO G. TRAHEY: TURBINE BLADE FAILURE: 4/5/94 1
1 0
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1 0
BL-2A2.2.3 STEAM QUAUTY DEGRADATION C
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BL-2A2.3.2 SOUD PARTICLE EROSION M
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1 0
i BL-181 A2 BLADE CONSTRUCTION 4]d h D. SMITH TO G. TRAHEY: TURBlNE BLADE FAILURE; 4/5/94 1
1 1
I BL-181 A2.1 LOOSENESS 3:lN D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1B1 A3 NOZZLE PASSING 1 h. D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1BI A4 BLADE TO DISK INTERACTION in M !itiF% M.t'fjj M f. h7'd 4 r '.i:" UPjff (# SR iTN 1 ~W4 T
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1 0 [
s BL-1BI AS STATIONARY STRUCTURE
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BL-181 A6 OFF FREQUENCY OPERATION BL-181 A7 STATIONARY BLADE CONSTRUCTION
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R. CORKINS ELECTRICAL REPORI 1
1 O
D. SMITH TO G. TRNIEY: IURBINE BLADE FAILURE: 4/5/94 1
1 0
. A.
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1 I
l BL-1818.2 CONDENSATION SHOCK WAVE D. SMITH TO G. TRAHEY; TURBINE BLADE FLUTTER; 7/6/94 I
I I
i BL-1B1B.3 STALL FLUTTER D. SMITH TO G. TRAHEY; TURBINE BLADE FLUTTER; 7/6/94 1
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7/13/94 7:12 PM Page D-3 IQ~
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e APPENDIX D LP-3 TURBINE FAILURE BLADE FAILURE CODE OFLE coro REFERENCE NO.
DONE SIG BL-1B IB.4 VORTEX SHEDDING D. SMITH TO G. TRAHEY; TURBINE BLADE FLUTIER; 7/6/94 1
1 1
BL-1818.5 EXCESSIVE MOISTURE mi RCA REPORT 7/94 BL-1BIC RUBBING 1
1 1
r,. i ~ L. FRON LTR ON VfBRATION ANALYSIS
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BL-1 BID SHAFT VIBRATION 1
1 0
L. FRON LIR ON VIBRATION ANALYSIS 1
1 0
BL-1 BID.1 IORSIONAL LOADING
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1 1
BL-1 B lD. l.1 NEGATIVE SEQUENCE CURRENT
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1 1
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1 1
BL-1C3 TRANSIENTS
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o APPENDIX D LP-3 TURBINE FAILURE BLADE FAILURE
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CODE TITLE Goto REFERENCE NO.
DONE SIG BL-ID CHEMICAL INTERACTION M7:t D. SMITH TO G. TRAHEY; TURBfNE BLADE FAILURE; 4/5/94 BL-IDI HYDROGEN EMBRITTLEMENT D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
I I
O BL-ID2 CORROSION r;
B1102.1 IGSCC D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
Q BL-102.2 TGSCC D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE 4/5/94 1
1 0
j BL-ID2.3 INTERtATH D. SMITH TO G. TRAHEY: TURBINE BLADE FAILURE: 4/5/94 1
1 0
< 1),
t1 i D. SMITH TO G. TRAHEY; TURBlNE BLADE FAILURE: 4/5/94 1
1 0
BL-ID2.4 PITTIN G
'i ? D. SMllH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
1 0
BL-ID2.5 EROSION / CORROSION 7-D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0)
BL-l E MATERIALS D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-1E l CONSTRUCTION D. SMlIH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-lE2 MANUFACTURE D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE: 4/5/94 1
1 0
BL-lE3 REPAIR ibm D. SMITH TO G. TRAHEY; TURBINE Bt iDE FAILURE; 4/5/94 1
1 0
BL-lE4 INTERSitTIAL EMBRITTLEMENT r lt D. SMITH TO G. TRAHEY; TURBINE BLADE FAILURE; 4/5/94 1
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l orcAL$THoM FERMI 2 TURBINE GENERATOR INCIDENT 25TH DECEMBER 1993 ROOT CAUSE INVESTIGATION CONCLUSIONS BASED ON INFORMATION AVAILABLE UP TO 30th JUNE 1994
SUMMARY
On 25th December 1993 the Fermi 2 turbine generator shed five last row blades from the front flow of the LP3 rotor.
The resultant mechanical unbalance caused extensive consequential damage during run down.
GEC'ALSTHOM has worked closely with the DETROIT EDISON COMPANY (DECO) to establish the root cause of the incident.
Interim reports were provided in March and April 1994 and this further report has been produced at DECO's request to assist them in making submissions to NRC.
It summarises GEC ALSTHOM's conclusions based on the evidence available at 30th June 1994.
The root cause has not been established with 100% certainty but there is confidence that it was due to the presence of abnormal water in the LP3 turbine.
Metallurgical examination of the fracture surface supports this conclusion and there is experience of water damage to other LP stages at Fermi 2 as a result of poor drainage of bled steam spaces.
The isolation of LP heaters in the LP3 cylinder during September 1993 could be a contributory facter.
A detailed torsional analysis of the complete rotor system has been carried out.
This eliminates torsional excitation of the rotor system as a potential root cause mechanism.
Fatigue cracks in LP stage 7 blade roots, stress corrosion cracking of LP stage 7 disc heads, the LP3 stage 5 rear dise head and LP3 rear steam balance holes were not a factor in the incident.
They are however indicative of the presence of water and questionable steam chemistry over a long period.
Stage 7
and 8
blade rows have excellent vibration characteristics.
These were established, at the time of manufacture, by rotational tests on a full size test wheel and confirmed by further rotational tests on a production rotor.
These tests show that the critical resonances are well clear of the operating speed range.
Identical blades used on other large nuclear turbines have been trouble free for more than twice the Fermi 2 operating hours.
This supports the conclusion that the failure of a single last stage blade was a consequence of abnormal circumstances at Fermi 2.
d
1.
INTRODUCTION l'
On 25th December 1993 the Fermi 2 turbine generator was
=
operating at full load under nominally steady state conditions when five adjacent last row (stage 8) blades on the LP3 front (south) flow fractured.
One blade (blade 9) penetrated the exhaust ' hood.
The resultant mechanical
{
unbalance caused extensive consequential damage during run down.
There was no prior indication from operational
}
parameters of the impending failure.
1 GEC ALSTHOM have worked closely with the Detroit Edison Company (DECO) to investigate the reasons for the failure.
{
Wam4 nation of the evidence supports the conclusion that the first major mechanical incident was the loss of a i
I single last stage blade (blade 9) on the LP3 front flow.
{
The fracture of the next four blades (blades 5-8) on the same row was a consequence of this single blade failure.
The following are unconnected with the incident:
i l
This report summarises background information regarding the j
Fermi turbine, gives details of relevant parts of the i
investigation and discusses various rogt cause scenarios which have been avam4 ned.
These lead to the conclusion that the abnormal presence of water in the turbine was responsible for the last stage blade failure and that water j
provides a common link between the present stage 8
i failures, cracking of stage 7 and earlier failures of LP stage 5 blading.
In view of this, particular attention has been focused on the design and operation of the feedheating system.
I 2.
BACKGROtMD TO LP TURBINES The LP turbines were designed specifically for use on large j
1800 rpm wet steam nuclear turbines, seven of which were t
manufactured in the 1960's/1970's.
Table 1 lists the turbines involved together with their operational hours upto December 1993.
This shows that although Fermi 2 was the irst t r
ed, it has the shor lif i
The lead unit Kori 1 I
has operated success y for more than as long as Fermi 2.
Identical stage 7 and 8 blades with side entry roots were used for each contract but there are inevitably variations 3
i i
4 T
1 4
.m-e 2
in steam flow rate and Permi 2 is not the most highly loaded.
There are differences in the blading for the earlier stages to accommodate different bled steam requirements and general changes in Company design philosophy,;<e.g. on the later turbines pinned root blade fixi~ng
.Taced the earlier straddle root designs used at T,_g;
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[Rivetedcoverbandsareusedtolinkthemovingbladesffor all but the last two stages which employ a continuous interconnection between blades.
This eliminates the i
possibility of individual blade vibrations and thereby reduces vibratory response, particularly under buffeting loading and eliminates any susepptibility to flutter.
This interconnection is pro,vided byta single row of split D type lacing wire on stage 7 cand by lacing rods on ' stage 8.
Both methods have been su'ccessfully used on a wide range of turbines.
The provision of extraction steam to LP heaters before both stage 7 and B is a common feature of this class of turbines, although different feedheating systems are in i
use.
Apart from Fermi 2, which operates with a boiling water reactor (BWR),
all other applications are with pressurised water reactors (PWR).
The higher levels of oxygen generally present in BWR steam can lead to a reduction in material resistance to fatigue and stress corrosion.
3.
FERMI 2 LP BLADING EXPERIENCE This section provides a brief summary of damage found during previous inspections on certain stages of the Fermi 2 LP blades and outlines remedial actions taken.
i 3.1 LP Staae 8 Prior to the 25th December incident there had been no experience of similar blade damage on the Fermi 2 last stage blades or any of the sister turbines elsewhere.
At Fermi 2 there was a long delay between the completion of the turbine installation and the commencement of commercial operation.
There were extended periods (circa 20,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />) of turning gear operation which resulted in significant wear of the lacing rod holes.
Similar wear has been observed on the other turbines but this was generally less severe, reflecting shorter periods of turning gear operation.
This problem was overcome by the installation of ripple springs beneath the blade roots to reduce the tip rock which can occur due to the absence of centrifugal loading 9
e
l.
3 at' turning gear speed. Ripple springs were installed on all last stage blades at Fermi 2 during RF01 (1989) and a rolling programme of last stage blade replacement was instituted.
A set of new last stage blades was installed on the LP1 rotor during RF01.and refurbished blades on the l
LP2 rotor during RF02 (1991).
A limited amount of remedial work'was carried out on LP3 during RF01 when 6 front flow and 4 rear flow blades with excessive lacing hole -wear were replaced with less worn ex LP1 blades and a number of larger lacing rods were fitted.
It is of interest to note j
that the five fractured blades did not include any of these replacement blades but one of the replacement blades (blade
- 10) immediately preceded blade 9.
GEC ALSTHOM racommended that the LP3 blades should be replaced during RF03 (1992) but prior to the outage DECO j
indicated that they intended to defer this until RF04 (1994 ).
GEC ALSTHOM's acceptance was conditional on
. repeat meast.ements of lacing rod / hole wear being carried l
out to confirm that there had been no significant deterioration.
In the event DECO chose not to employ GEC l
ALSTHOM technical service support during RF03 and it only 4
became apparent during the present investigation that i
practical difficulties had prevented the taking of reliable I
repeat measurements.
For reasons discussed below the i
. lacing hole wear itself is not considered to have been a i
significant f actor in the failure of the five front flow I
blades.
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3.3 LP Stace 5 During the RF01 inspection a number of failed stage 5 blades were discovered on the LP2 rotor and cracked blades were found on all three cylinders.
In addition, a small N
4 number of staga 5 dise hsid crccks ware found on ths LP1 flow.
Metallurgical examination rear flow and LP2 front confirmed that the f ailure mechanism was high cycle fatigue i
and it was concluded that this resulted from abnormal excitation of modes whose frequencies were in the range where damaging vibration is not normally encountered.
Water ingress was cosidered to be the source of. abnormal Further inspection revealed the presence of a excitation.
large volume of water in the LP2 cylinder due to a blocked restricted drain and it was subsequently discovered that drainage in LP1 and LP3 cylinders could also cause water build up during service.
The primary remedial action was to ensure that adequate drainage of the LP cylinders and bled steam lines was maintained at all times. In addition, modified blades with l
As increased frequency margins were installed during RF02.
a'short term measure the turbine was operated for one fuel cycle with stage 5 blades removed while replacement blades were being.aanuf actured.
The effectiveness of the actions taken is reflected in the fact that no further f atigue cracking of the staoe. 5 blade.s.
3
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occurred.f',. '
1 or disc heads has i
3.4 LP Staae 4 During the period in which the turbine'was operated with stage 5 removed, f ailures of stage 4 blades occurred on the LP3 front and rear flows and there was some associated disc head cracking.
It was concluded that this was a result of the abnormal loading produced due to the absence of stage 5.
Identical replacement blades with continuous shrouding were fitted during RF02 when the new stage 5 blades were installed.
The absence of any subsequent failures of this stage at Fermi 2 or any of the sister turbines confirms the i
conclusion reached at the time.
4.
REVIEW OF SALIENT INFORMATION This section deals with significant features of inspections carried out after the 25th December incident.
Four main areas are considered, namely:
a) stage 8 blades b) stage 7 blades c) other LP stages d) feedheating system
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4.1 Staae 8 Blades The most significant evidence was provided by the fracture surface from blade 9 on the LP3 front flow which showed that a fatigue crack had initiated close to the trailing 1t" above root platform.
It approximately{th
- edge, approximately 5'
before the steady propagated for centrifugal. load caused ductile f ilure of the reduced section.
Magnetic particle inspection (mpi) revealed no evidence of f atigue on any other LP3 front flow blades, including the fractured blades (5-8), even though many of these had tears or impact damage.
l MPI was also_ carried out on the stage 8 blades from the l
other flows but did not reveal any cracking. The damage on these rows was limited to rubbing of the feather tip which i
j would have occurred during the run down with high i
unbalance.
j-Metallurgic 1 examination has confirmed that there were no material abnormalities or prior damage which may have j
contributed to the failure.
It was observed that the trailing edge of blade 9 in the immediate vicinity of the i
crack initiation point was thinner than for other blades at i
the same position, although there is at least one other LP3 front flow blade with practically the same trailing edge carried out thickness.
Subsequent detailed measurementsj with a travelling microscope on the aerofoil hter it had been sectioned for metallurgical examinatioQshowed that this effect was extremely localised and the blade was not inherently weak. There was a small machining mark close to the crack initiation point on blade 9 and similar marks were observed on other blades.
Luring the initial examination of the fatigued portion of the fracture surface, striation counting had been used to deduce that the period from initiation to final fracture was limited to the few hours immediately prior to the incident. Subsequent more detailed analysis carried out by l
GEC ALSTEM metallurgists has shown that the assumed fatigue striations were in fact secondary cracks. There is l
no known relationship between the spacing of secondary cracks and propagation rate and therefore the original hypothesis suggesting rapid fatigue crack growth rate is not supported.
The detailed SEM (Scanning Electron Microscope) examination of the micro fracture surface showed that the cracking was It transgranular with no signs of intergranular facetting.
showed a beachmark at a distance of 60mm from the i
[also 1
g crack initiation site.
This precedes a deviation in the fracture path direction which takes the form of a ridge adjacent to the convex surface of the blade and a smaller trough adjacent to the concave surface. This is consistent with shear stress being applied during this phase of crack growth.
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In order to investigate these observations further a test i
set up using last stage blade material programme wasThis work is ongoing but the main conclusions specimens.
l reached so far are:
i (i) the lack of intergranular facetting indicates l
that the dynamic stress was small relative to the steady stress.
(ii) a change in steady stress due, for example, to a step change in the blade loading, a shut'down or b'
overspeed can produce beachmarks of the typef~
observed on the fracture surface.
(iii)
Periods with no significant crack growth due to reduced cyclic stress could occur without leaving i
1 significant evidence (beach marks) on the fracture surface.
)
'The relevance of these observations is dicussed in section 5.1.
4.2 Staae 7 Blades exanination of stage 7 has revealed cracking in both MPI blade roots and dise head serrations.
d The inspections carried out did not reveal any obvious reason for the greater concentration of cracks on the LP2 or the absence of cracks on the LP1 rotor.
front flowthere is a general correlation with the damage
- However, observed on stage 5 during RF01.
It was observed that the blades were easier to remove from the LP1 than either of This may indicate some difference in the other two rotors.
the steam quality between the cylinders but this has not been quantified.
e rIn all cases the cracks are in the root top neck and appear
)to have initiated inboard of the root inlet face on the concave side of the blade.
There are significant e eut a
__.___7._.____-____________
in the crack depth but the most severe have
[ var'iations extended across the root inlet face.
A number of the most severely cracked blades have been broken open to enable more detailed examinationQ: In each case the main features of the fracture surf ace a'Ye the same as those observed on the blade which was replaced during RF01, i.e. high cycle f atigue, multiple initiations, clearly discernible arrest marks and significant oxidation.
This indicates slow interrupted growth consistent with the cracks having propagated over a long period which could be number of years and they may even have stopped.
The nature of the fracture surf ace is different from that observed on the LP3 front stage 8, blade 9 and it is clear that the stage 7 cracks were not a consequence of the 25th December incident.
Stage 7 dise head cracking has not been analyzed in such great detail as the blade root but extensive cracking has Initial been f ound on all flows including the LP1 rotor.
examination suggests that the cause of the cracking is stress corrosion and although further analysis is being
' carried out here is little doubt that this will be confirmed.
s two different mechanisms are involved i
(f atigue for the blade roots and stress corrosion for the disc heads) it is extremely unlikely that one is the j
consequence of the other but it i robable that steam environment may provide a common 11 4.3 Other LP Staces Non destructive examination of the other stages of LP blading has revealed a disc head crack,on stage 5 of the rear flow of the LP3 rotor.
As with the disc head cracks on stage 7, final confirmation of the crack mechanism has yet to be obtained but after initial examination it is thought to be due to stress corrosion.
It should be noted that during RF02 the GEC ALSTHOM Technical Service Engineer reported significant disc head corrosion in the LP3 cylinder and recommendations were made to minimise operation of the condensate system with the condenser at atmospheric pressure.
It is extremely likely that the steam environment contributed to both the stage 5 and stage 7 disc head cracks.
Apart from the effects of consequential tenon and shroud rubbing which occurred during the unbalanced run down on 25th December, no other LP blading damage was observed.
Early reports of crack indications on LP2 stage 4 disc heads were incorrect.
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There was no evidence of the passage of any foreign objccts through the earlier stages of the LP3 turbine which may have been responsible for damaging the front flow stage 8 blading.
4.4 Feedheatino System In RF01 when the stage S blade failures were discovered abnormal quantities of water were discovered in the LP2 cylinder due to blocked drains. There was also evidence of inadequate drainage of bled steam lines in the LP1 and LP3 cylinders.
GEC ALSTHOM expressed concerns at that time about the operation of the extraction steam drainage and a number of recommendations for improvement were made.
The number 1 and 2 LP feedheaters which extract steam from before stage 7 and 8, are located in the condenser neck beneath each LP cylinder.
The heaters unique to the LP3
)
cylinder ere isolated on the condensate side for approximately two weeks in September 1993.
This was the first time that any of these heaters had been isolated at Fermi 2 and therefore particular attention has been focused on the way in which this was done and the general mode of operation of these heaters.
Initially the situation was extremely confused because the written procedure for removing either heater from service requireded that both the normal and emergency heater shell drain valves should be closed. If this had been carried out, conditions would have existed for the heaters to flood
- and, since there are no non return valves in the corresponding bled steam lines, water ingress into the LP3 turbine would have been inevitable.
After further investigation it was established that this approach was not used and a temporary procedure had been written which restricted isolation to the condensate side only.
No changes were made to the shell drain valves which continued to operato in response to the level control system.
DECO are confident that this revised procedure was used and provided that the level control system was functioning correctly, the heater drains should have dealt with the water extraction flows in the bled steam lines.
A general inspection of the system is presently being carried out and to date the following has been revealed:
the arrangement of bled steam pipes to number 1 and 2 heaters is identical for each LP cylinder.
there are undrained horizontal sections of pipe from the front flow but not from the rear flow.
small negative gradients were measured in some of the LP3 front pipe runs.
9 a variety of foreign objects.have been retrieved from the pipe runs and heater inlets. These include part of a wooden plank, a sling, a hammer head and safety helmets. Some of these were specific to the LP3 and it is also clear that they were there before the incident.
In view of their concerns about the operation of the feedheating system GEC ALSTHOM conducted a separate review of its ability to remove water and preserve the steam path integrity. This has shown that it does not conform with their practice nor with the ANSI /ASME specification TDP 1985 (Recommended Practices for Preventing Water Damage to Steam Turbines Used for Electric Power Generation). One area of particular relevance is that the LP heaters operate with significant water levels in the heater shell. As this water is at saturation temperature any pressure drop, due for example to a load reduction, will result in water
' flashing off' in the heater and cause a transient flow reversal in the bled steam lines. This would interrupt the water extraction flow from the turbine and could force slugs of water from the heater into the main steam path.
Historically there have been problems with water levels in heaters at Fermi 2 which are controlled by automatic drain valves. Initially the control for these valves was provided by differential pressure transducers with water filled legs which are known to be unreliable, particularly when operating close to saturation conditions or under sub atmospheric pressures.
During early operation is reported that it was necessary to override the control system to ensure that heaters remained adequately drained.
J A significant improvement was made when the differential pressure transducers were replaced by conventional level 1
detectors, although it was necessary to increase the water i
level in No.2 heater to obtain satisfactory performance.
4 Nevertheless, GEC ALSTHOM still has a
number of reservations about the operation of the system. These are principally related to lack of independent controls and the j
' absence of any on line testing facilities.
For each heater two level detectors are used both of which are mounted from the same~ tapping points with common source manual-isolation valves. One detector operates both the normal and emergency drain valves and the second provides signals for control room indications and alarms.
Hence if l
normal drainage were lost due to a detector malfunction the emergency' back up would also fail to function.
Alternatively, if a leakage or blockage were to occur in the common lower leg, or one of the manual isolation valves was inadvertently closed, the heater would flood but the control room indications could appear to be normal.
The checks carried out after the incident did not identify the status of the manual isolating valves.
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DECO believe that other operational data indicates that the system was functioning correctly but as this is based on spot readings the possibility of transient malfunction remains. GEC ALSTHOM have recommended that tests should be carried out to confirm the satisfactory operation of the level control systems and the absence of any heater tube leaks.
GEC ALSTHOM and other manufacturers have had experience in the past of inadequate b ed steam drainage resulting in water damage to blading This led to the adoption of LP heaters situated in the condenser neck which operate with a minimum quantity of standing water within the heater shell. In such arrangements manometric loops or orifice plates in the drain lines eliminate the need for control systems and valves 2 This not only provides a
less complicated, maintenance free system but has the additional advantage that it is fail safe. In view of the difficulties of access associated with BWR plant such systems offer significant idvantages.
5 ROOT CAUSE DISCUSSION 5.1 LP Stace 8 Blades The evidence overwhelmingly supports the conclusion that the first major mechanical event was the loss of a single last stage blade (blade 9) in the front flow of the LP3 rotor.
Metallurgical examination has shown that on that blade a high cycle fatigue crack initiated at the trailing edge approximately 1t" above the root and propagated until the reduced blade section was no longer able to withstand the steady centrifugal force. Fracture mechanics analysis carried out for the blade material confirms that the fatigue crack had extended beyond the minimum critical depth.
There is no evidence of fatigue on any other stage 8 blade in the damaged row, including the four fractured blades immediately following blade 9, or the five other identical blade rows on the turbine.
Under normal conditions, fatigue of these blades would not occur because this blade row has excellent vibration characteristics. These were established by rotational tests on a full size prototype wheel when the blade was initially developed and were later confi.rmed by further r tational tests on a production rotor. These tests showed hat the maj or critical resonances of the low order wheel modes likely to cause damag:
vibration are well clear of the loperatingspeedrangej ig. 1 shows the Campbell diagram derived from the tests he long trouble fre the other similar uni and also at Fermi 2 i
prior t the incident confirms the validi.ty of the test r sults and the soundness of the blade design $
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11 The absence of resonant cond ons is supported by detailed analysis.
he lack of intergranular metallurgical facetting on the fracture sur ace of blade 9 indicates that the dynamic stress was small relative to the steady stress, which would not be the case for a blade in resonance.
Further evidence is obtained from tests on blade material specimens which showed that once a crack had been initiated it propagated with relatively low dynamic stress The tests also showed that the beach mark part way acrossl I
the fracture surface of blade 9 could be caused by a change in the steady blade loading.
If this was due to the loss of centrifugal stress it indicates that the crack initiated before the last shutdown on 17th September 1993 but after the penultimate shut down on 14th August 1993.
[ Alternatively, there may have been an abnormal event during operation which produced a substantial transient increase in the blade load. If so, an earlier similar event could have been responsible for the crack initiation.
In this case both events would have had to have occurred after theJ last shutdown.
- The well proven vibration characteristics, absence of resonance, presence of the beach mark, and the fact that only one blade suffered fatigue damage leads to the conclusion that some abnormal event happened.
At Fermi 2 there were no signs of foreign objects having passed through the LP3 turbine prior to the incident but the recent discovery of old debris in the bled steam lines means that this cannot be discounted as a pcssible source of damage to blade 9.
However, based on the past history of drainage problems at Fermi 2, the concerns about the heater isolation and markings on fixed and moving blades which indicate the presence of water in all three LP cylinders, it is considered most likely that blade 9 suffered water damage.
Homogeneous mixtures of steam and water in the later stages of LP turbines can increase the general level of excitation and cause erosion. They do not generally present a serious problem and there is no practical limit to the quantity of entrained water. The situation is quite different if slugs of water are present.
These may be due to reversal or blockage of bled steam flow causing an interruption in the normal water extraction process, or as a result of steam boiling in the bled steam line/ heater and forcing water back into the turbine.
between the high velocity blading and a 'small Impact consolidated mass of water can exert large impulsive forces capable of producing major deformation of blades.
The water mass will break up immediately on the first impact and the effects will be restricted to only one or two e.
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blades. Observations of damage on turbines which are known to have experienced water problems confirm that often only a small number of blades can be affected.
It is concluded that this is the mechanism which affected i
blade 9 of the LP3 front flow.
In' principle, blades in any one of the six last stage rows could have suffered in this way but the prior trouble free operation of stage'B blading suggests that this was a consequence of an exceptional combination of circumstances coupled with special features unique to the LP3 front flow.
One such circumstance was the period in September 1993 when the LP3 cylinder number 1 and 2 LP heaters were taken out of service. Fermi 2 had never operated in this mode before and it is entirely possib.' e that the initiating water damage occurred at that time particularly since load was reduced prior to returning the heaters to service so that the reduction in pressure could have caused water in the
, heater to f' ash off.
Furthermore the last shutdown before
.the 25th December incident occurred after the heaters had been returned to servicdand it has been shown that the beach mark on the fracture surface could be consistent with ashutdowng It is
- possible, but not essential to the general explanation, that impact with slugs of water could have caused sufficient distortion for the lacing rod connection between blade 9 and its immediate neighbours to be lost, thereby causing that blade to become' free standing with different vibration characteristics.
GEC ALSTHOM philosophy for last stage blade rows is to provide continuous blade to blade interconnection, and t here was never any design intention that the Fe 2
t e blades should ee standin.
sum musumum-mm meni
13
.alitially loss of lacing rods had been discounted as there was no supporting evidence from the rotor vibration records to indicate a balance change of sufficient magnitude.
It is now believed that a mechanism for losing the lacing rod connection involves a single blade twisting so that one end of two adj acent rods comes free whilst the other ends remain in place in their respective blades.
The free rods would bend outwards under the influence of centrifugal force and could remain booked in the blade with no change of rotor unbalance. (rhe additional rod mass close to the tip of the resulting free standing blade would cause a further small frequency reduction (approximately 0.5Hz) beyond that measured in the tests.
Stress calculations indicate that it is possible for a rod to bend in this way without fracture and this was also confirmed by static testscarriedoutbyDECO]
Lacing rods are normally trapped in position by the blades and therefore considerable thought was given to the possibility that the worn lacing holes may have been a f actor, particularly since significantly greater wear had been measured on the front flow during RF02.
- However, blade 9 was by no means the most severely worn blade and measurements taken after the incident showed that, in general, there had been no significant increase in wear since RF02.
It is therefore considered that lacing hole wear alone was not responsible for the loss of lacing rods.
r Similar conclusions have been reached with regard to the locally thin trailing edge and the presence of a machining mark on blade 9.
For the fundamental vibration mode of the 4 blade, the point of highest stress coincides with the crackX position and this would be the position of failure with or without these two features.
m Awareness of other North American experience of failures of long blades due to shaft torsional excitation led to a detailed analysis of the Fermi 2 rotor line being carried out.
The results of this analysis and the available evidence from site (e.g. only one cracked blade, lack of system frequency variations, no reported abnormal negative sequence currents) do not support this as a possible root
- 'cause 'intthi's case-Furtherraiscussion hbout'thb7Eofsf6nal
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analysis for both stage 7 and 8 blades is given below in section 5.4.
The higher oxygen levels present in BWR steam inevitably has some impact on the fatigue strength of the blading material. Under normal circumstances the design margins are such that this is not significant but the reported higher corrosion in the LP3 cylinder and the presence of stress corrosion cracking on other stages suggests that the steam chemistry at Fermi 2 may not always have been optimum and mT l
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could have been a contributory factor.
as is frequently the case in such incidents, Summarising, that there is a lack of totally conclusive evidence but which is available indicates the root cause to be' the presence of abnormal quantities of water within the turbine.
5.2 LP Staos 7-Although both stage 7 and 8 blade cracking is associated with fatigue, thare are a number of differences which indicates that one is not a consequence of the other. These include:
no fractures of stage 7 blades (1) the fracture surfaces are quite different. Those (ii) on stage 7 are long term, with clear signs of acrest.
the distribution of cracks is more widespread on (iii) stage 7 with the greatest concentration on the LP2 rotor there is extensive stress corrosion cracking of (iv) the stage 7 disc heads ed The vibration characteristics of this stage were confi by full size rotationa ests prior to service an the hows that the low order cri ca
[campbelldisgram(fig.2) resonances are well cl of the operating speed rang This together with the long term nature of the crack the absence of any root fractures and the propagation, trouble free operation of this identical blade on other turbines eliminates resonance of low order wheel modes as
- c. factor.
It is more likely that there were periods of unusual operation at Fermi 2 which introduced abnormal intermittent excitation of higher order modes which are not normally considered to be of significance.
greater number of cracks on the LP2 rotor, and the The general correlation with the earlier stage 5 damage, raises the the possibility that they may well have initiated at sacte time as the previous stage 5 failures which were also There was clear evidence most severe in the LP2 cylinder.
of water in the LP2 cylinder at that time together with bled steam drainage problems in the other two cylinders.
Subsequent water incidents may have been responsible for further intermittent crack growth but it is also possible that, once the cracks had initiated, normal levels of background excitation were sufficient to promote growth.
factor in this case is the possibility that j
An important poor steam chemistry has contributed to reduced f atigue I
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The extensive stress corrosion cracking found on strength.
the disc head suggests that this is a high probability.
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MlULl_lhd1111N 15 The torsional analysis. carried out (see section 5.4 below) showed that the frequency of the all in phase tangential mode for this stage is well clear of both 60 and 120Hz.
This eliminates torsional vibration as a possible root cause of stage 7 damage.
It had initially been ' suggested that lack of contact between the lacing wire and blades may have been a contributory factor but subsequent examination of the lacing holes and wire showed this not to be so.
b.3 Stress corrosion Crackino In addition to the stage 7 disc head cracks, it is also thought that the cracks found on the LP3 stage 5 rear flow disc head and the LP3 steam balance hele:s are due to stress corrosion.
There are a number of factors which influence stress corrosion but the previously observed
. corrosion /pf ting of parts of the LP3 rotor suggests that i
steam chemistry is the important ingredient in this case.
l he degree to which a more severe steam environment could exist in the LP3 cylinder than elsewhere is open to debate but the two following factors may be significant:
(1)
It was observed in RF02 that, during condensate \\/
recirculation under atmospheric conditions,the LPY \\
cylinder was streaming with warm condensation - ideal x
conditions for pitting and local yielding which can lead eventually to stress corrosion.
This is almost certainly due to the recirculating connection being at the LP3 end of the condenser.
Recommendations were made at that time to minimise these conditions.
(ii) Examination of MSR outlet temperature records indicated that the steam entering the LP3 cylinder is approximately 50*F cooler than the design value. This would lead to greater wetness in the LP3 cylinder.
5.4 Torsional vibration It is well known that there is a potential risk of exciting vibration of long turbine blades by electrically induced torsional oscillations of the rotor system, and there have been a number of failures of other manufacturers turbines which have been attributed to this.
It was therefore natural to consider torsional vibration as a possible root cause for both stage 7 and 8 blades, particularly since it was only after the Fermi 2 turbine generator was designed that the possibility of exciting vibration in this way was fully recognised and appropriate calculation methods dnveloped.
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This leads to the following j~' conclusions:
The st 8
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The st e8bl nd mode ncy is well clear of 12
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clear of 60 and 120 z, an the margins are suf ciently large not to require a more detailed analysis.
The mode whrse fr osest to 120 Hz is a second LP torsional mode r the full rotor line with some coupled stag 'B blade s nd mode.
This is considered to be satisfactory.
It is likely to be difficult to excite electrically as the generator is in its first mode shape.
This will result in strong energy cancellation. It is also sufficiently removed from the blade natural frequency to result in relatively low blade torques.
_J 6.
CONCLUSIONS (a)
The 25th December 1993 incident at Fermi 2 was caused by the high cycle fatigue failure of a single last stage blade (blade 9) on the front flow of the LP3 rotor.
(b)
The initiation mechanism was due to impact with a slug of water and higher excitation forces existing due to the presence of water.
(c)
There is past experience of water induced blading damage at Fermi 2 resulting from inadequate drainage of the bled steam spaces.
(d)
Deficiencies in the effectiveness of the heater drains system indicates a high probability that they have contributed to this problem.
The initial stage 8 damage may have occurred when the LP3 heaters were isolated during September.
(e)
The previous trouble free operation of this blade design at Fermi 2 and elsewhere indicated that the failure was a consequence of abnormal circumstances at
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Cracking over an extended period of the LP stage 7 blade roots can also be attributed to the abnormal presence of water.
(g)
Stress corrosion cracking of stage 7 disc heads, the LP3 rear flow stage 5 disc head and LP3 rear flow steam balance holes' indicate that there may have been deficiencies in the Fermi 2 steam / water che.mistry at some time.
These would cause a reduction in both fatigue strength and stress corrosion resistance.
(h)
Torsional excitation of the shaft system has been eliminated as a potential root cause.
PMM JULY.1994 1
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