ML20095L372

Interim Status Rept Independent Root Cause Analysis Assessment of Detroit Edison Fermi 2 Turbine-Generator Event on 931225

ML20095L372
Person / Time
Site:	Fermi
Issue date:	07/26/1994
From:	Chiu C, Summy J DETROIT EDISON CO.
To:
Shared Package
ML20095L359	List: ML20095L355 ML20095L362 ML20095L372 ML20095L386 ML20095L403 ML20095L413
References
FOIA-94-507, FOIA-95-A-2 NUDOCS 9601030066
Download: ML20095L372 (40)

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Interim Status Report Independent Root Cause Analysis Assessment of the Detroit Edison Fermi 2 Turbine-Generator Event on December 25,1993 July 26,1994 Prepared by:

N ye%S. Summy

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PrincipalInvestigators:

Mr. Donnell Kidder Mr. Ralph Ortolano Dr. M.S. Mostafa Reviewed by:

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PDR FOIA KEECAN95-A-2 PDR THIS REPORT WAS PREPARED BY FPI INTERNATIONAL FOR THE DETROIT EDISON COMPANY, FERMI 2 NUCLEAR POWER STATION AS A PROPRIETARY REPORT. ANY RELEASE TO A THIRD PARTY REQUIRES WRITTEN APPROVALS FROM BOTH DETROIT EDISON COMPANY AND FPIINTERNATIONAL.

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Table of Contents I

Introduction 1

II Executive Summary III Conclusions IV Recommendations V

Event and Analysis Information i

A.

Significant Time Line Events l

1 B.

Analysis Data VI References Attachments

1. Fermi Independent Root Cause Analysis Engagement Plan

2. Fault Analysis Tree Matrix

3. Timeline of Events

4. Turbine Vibration Alarm List 9-

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Introduction Mr. Paul Fessler, Technical Services Manager Fermi-2, requested FPI International (FPI) to conduct an independent analysis of the Detroit Edison Root Cause Analysis of the December 25,1993 Turbine-Generator event. The following interim status report provides the method by which this was conducted along with the conclusions and recommendations from the independent analysis based on available information as ofJuly 15,1994. This independent analysis was requested to be performed through utihntion of data and analysis compiled by the prunary root cause analysis team of Detroit Edison personnel lead by Mr. George Trahey. FPI was additionally requested by Mr. Len Fron to provide independent oversight of the root cause failure team activities in the form of process monitoring and team effectiveness.

FPI fonnulated an overall approach to this effort as depicted in Attachment 1 in the form of a project engagement plan. The FPI Project Manager reported directly to Mr. Paul Fessler to ensure independence of the FPI activities. Routine information and progress updates, in the form of FPI letters, were provided to Mr. Fessler and Mr. Fron. These updates were to ensure Mr. Fessler was informed ofFPI activities throughout the entire investigation. These letters also provided a means to track the information required by FPI to conduct the independent analysis and also provide information resulting from the FPI analysis back to Mr. Fessler. This information/ status could be used by the Fermi 2 management team as necessary throughout the ongoing investigation.

II Executive Summary FPI formed an independent team of experts with backgrounds in proven methodologies for performmg root cause investigations of this complexity in concert with industry recogmzed turbine-generator and metallurgical specialists. The teams scope was to conduct an independent assessment of the root cause of failure investigation being conducted by Detroit Edison Company cf the Fermi 2 Turbine-Generator event ofDecember 25,1993. FPI provided an independent review of the root cause evaluation methodology, the final determination of the root cause(s), and corrective actions recommended by the Detroit Edison root cause analysis FPI conducted independent parallel reviews of the pertment data and facts, as determined by the Detroit Edison investigation, and arrived at an independent conclusion of the analysis for the root cause of the event which is provided in the conclusion section of this report.

FPI conducted activities both on site at Fermi 2 and offsite at the FPI offices in Califomia. The overallinvestigation was orgamzed through the use ofFault Analysis Trees, see Attachment 2. The Fault Analysis Trees were formulated using the root cause team experts on site at Fermi This methodology ensures that all reasonable failure modes are considered in the investigation and that each failure mode is eliminated as a root cause or eventually concluded to be a root cause. This analysis approach ensures that in the event that conclusive evidence cannot be determined to prove only one root cause exists, that corrective actions can be taken to prevent recurrence of all potential I

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hearun Stams Repan % Ret Ccuse Analyus Assezirurn Decat EAsca Fertru 2.My 26, t994 root causes determmed This can occur when physical evidence needed to pmve a certam root cause is destroyed as a resuh of the failure. In the situation when multip'e potential root causes exist after evaluation of all available evidence then corrective actions to prevent recurrence for each must be implemented or additional testing / monitoring must be performed on the subject equipment on return to service. This was the case with the failure of blade #9. For example, physical esidence was destroyed as a resuh ofthe failure that will prevent determining if a lacing spool could have failed to perform it's design function. Therefore, corrective actions must be taken as if this was the pnmary root cause of the event along with all other additional failure modes remammg.

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9 In the history of the Fermi 2 turbine there have been premature, unexplained failures associated with stages 4,5, and 7 ofthe low pressure turbines. Although corrective actions had been taken for those failures it was not assumed that the root cause associated with those earlier failures was not related to the cause of the stage 7 and E failures observed during the root cause investigation completed as 1

a result of the December 25,1993 event. For this reason an added degree of complexity was I

associated with the root cause of failure of the December 25,1993 event.

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V Event and Analysis Information At approximately 1315 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />5.003575e-4 months <br /> on December 25,1993, the Fermi 2 plant experienced a turbine-Benera.or failure and automatic reactor trip. The immediate cause of the turbine-generator fhilure was not known. The failure resulted in extensive damage to the turbine, generator, connected auxiliary piping, bearings, foundations, exciter, and generator to exciter coupling.

3 The most extensive outwardly visible damage was in the local area of the exciter and coupling to the generator. This included evidence.of a generator hydrogen bum, a sheared generator to exciter t

coupling, destruction of the Number 11 exciter bearing with resultant release of the turnmg shaft into the exciter stator, and sheared or extracted foundation fasteners.

Obvious visual damage to the LP-3 turbine included broken blading in the L-0 turbine end (front flow) row and damage to the turbine shroud and casing where a portion of the #9 of a blade exited the turbine through the outer casmg Damage to the remauung turbine units was not as extensive and no other blade loss occurred in either the HP, LP) or LP2 turbines. Sheared and extracted bearing e

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- Root Cause Analysas A==-amm.Deerwt Lhnen Fanni 2 My 26,1994 cap fasteners and damaged casing seals were evidenced at all sections of the turbine. In panicular there was signiScant damage to the LP-3 front flow diffuser with large portions missing.

Generator damage included a hydrogen burn with the source being through the generator seals. Seal water, cooling water, and lube oil lines were all dam.sged where they pulled away from the turbine and generator. Coast down time was approximately I minutes 46 seconds to 780 RPM. Ingress of air (decreasing condenser vacuum) into the turbine casing through the hole created by the ejection ofblade 9 comributed to this shorter than normal coast down time Exammation of various beanng surfaces revealed damage which was more pronounced on certam beanngs of the turbine and generator.

Information from the alann typer shows that there was a 19 MW electrical disturbance followed by a differential thrust alarm, output breaker opening, and turbine overspeed trip (a more detailed sequence ofevents is included in Attachment 3). Other plant information does not suggest that the turbine was in an~ overspeed condition. The turbine manufacturer (GEC) believes and independent analysis supports, that it is possible due to the vibration of the turbine, the mechanical overspeed trip device was actuated. This caused the turbine overspeed trip device to actuate providing the appearance by station alarms and indications that the turbine tripped on overspeed. The conclusion that the turbine-genemtor rotor system did not overspeed is further supponed by vibration recording synem analysis and physical measurements of movement of the stub shafL There were over one hundred alarms received in the main control room within a period of about 20 seconds as a result of the failure. A partial listing of the alarms is provided in Attachment 3 as well as a complete time line that details the alarms and indications. Following is a list of the most signiScant alarms and a discussion of why that alarm is considered significant in understanding the event scenario.

A.

Significant Time Line Events (in seconds)

TIME ZERO (E+-0) Overspeed electrical circuit fault; the first indication of trouble with the unit.

This alarm is actually the result of two different speed pick up probes reading a preset difference in speed on the turbine shaft As described above it has been concluded that this was the result of vibration ofthe speed pick up probes The turbine was still synchronized to the grid at this time and overspeed above grid synchronous speed (60 Hz) is considered to be possible only if the unit is not synchronized

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E%.007 Thrust beanng oil strainer high differential pressure alarm Normal operation of the turbine maintams this value at about 4.5 psid and the alarm point is 6.0 psid. Reportedly, this alarm comes in any time the unit is upset. This alarm is probably caused by vibration and is significant only from the aspect of an indication of vibration in the turbine generator system.

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- Root Cause Andysis Annesamma.Dueron Easco Fermi 2.My 26.1994 E%.037 Number nine bearmg (turbine end of generator) alarms on high vibration at a set point of 6 mils. This is a shaA rider type vibration probe reading and the bearing had been running at about 3.8 mils up to about five mmutes before time zero when it rose about 0.2 mil. This is the first of many alarms on vibration, see Attachment 4, that tend to increase in magnitude as time increases.

EM.491 Stator water cooling low flow alarm E%.069 Seismic event at alarm settmg of0.01 g - concluded to have been caused by vibration from the turbine.

E%.125 Turbine trip on mechanical overspeed - detemuned to have been created by vibration from the turbine. The unit was still synchroruzed to the grid at this time.

E4.149 Reactor SCRAM as a result of turbine throttle valve fast closure.

E%.197 Generator Liquid Leak high alarm -indicates the presence ofliquid in the hydrogen gas space of the main generator.

E+1.0 Coast down system activates and starts tracking turbine speed. Speed is recorded at 1800 RPM (still synchronized with the grid).

E+2.0 Speed is recorded at I800 RPM (still synchronized with the grid).

E+2.761 Generator hydrogen gas pressure low alarm at set point of 65 psig indicates that hydroge seals have began to fail, concluded to be as the result of vibration.

E+4.0 Speed is recorded at 1800 RPM (still synchromzed with the grid).

E+5.547 Condenser low vacuum alarm is recerved and renaining vacuum is lost very rapidly parti as a resuh of blade 9 penetratmg the casing.

E+8.994 Unit speed commences to drop below 1800 RPM EM.777 TG output breakers open E+9.991 Generator high frequency alarm at set point of 60.5 Hz followed by clearing of the alarm i

then low frequency at a set point of 59.5 Hz. The estunated maximum speed corresponding to 60.75 l

Hz. occurred shortly after the generator output circuit breaker opens. This maximum speed is still well below the overspeed trip setpoint.

E+10.0 Turbine building HVAC trips on high differential pressure (pressure inside the building 10

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pressure recorder records a rapid drop to a minus.05 inches water column then a rapid spike off scale at positive one inch water column. This information is used to confum the time and energy associated with the hydrogen bum pressure spike.

E+12.193 First fire alarm comes in

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. E+20 Number 1I beanng metal temperature alarms on high temperature. This is the Erst beanng metal temperature alarm to come in. All beanng metal temperatures had tracked steady up to this point.

E+31 Number 11 bearing (exciter beanng) self destructs as evidenced by opening of the bearing metal thermocouple circuit. The most obvious apparent damage was localized in the area of the l

exciter and included evidence of a hydrogen burn, a sheared generator / exciter coupling, destruction ofthe Number 11 exciter beanng wit' resuhant release of the turmng shaft into the exciter stator, and sheared or extracted seal, hold down, and foundation fasteners Damage to the LP-3 turbine included five broken blades in the I 0 front flow and damage to the tu6ine shroud and casmg where blade #9 exited the tmbine on the turbine end, left side ofLP-3 hood (north west corner of the hood). Damage to the remaining turbine sections was consequential as a resuh of the loss ofLP3 bladmg Each of the three low pressure turbine shafts indicated some degree of bowing /twistmg resulting from the vibration and cooldown while not on a turrung gear.

Generator damage included a hydrogen burn with the source being through the generator seals and output terminals. Physical evidence revealed indication of burning under the generator, at both ends of the generator and within the exciter enclosure. Review of the U41R801 instrument (Turbine Building Atmosphen Differential Pressure) indicates that prior to the event, the turbine building differential pressure was being maintained at a negative 0.25 inch water pressure. At the event inination, pressure dropped to a negative 0.5 inches water then spiked off scale at grater than 1.0 inch water positive followed by an immediate return to a 0.25 inch water negative value.

Seal water, cooling water, and lube oil lines were all damaged where they pulled away from the turbine and generator. Precise coast down time is indetermmate but was between two and four minutes aided by loss of condenser vacuum from the blade hole in the LP casing.

One or more turbine blades entered the condenser tube bundles under the LP-3 area and pierced condenser tubes resuhmg in the introduction of raw cooling water (typically maintained at about 1.5 to 2 cycles ofconcentration of the Lake Erie cooling water makeup) into the condensate system and ultimately into the reactor vessel.

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- Rest Cause Analysm A=======. Daron Edman Fanni 2. My 26. t994 Flooding of the turbine building basement occurred as the result of ruptured cooling water lines and i

fire protection sprinkler actuation created by the fire at the generator end. It was estimated that approxunately two-thirds of the approximately 500,000 gallons of water in the basement originated from the fire protection system. The flooding created a signiScant detnment to turbine work as a great deal of resources were required to handle such a volume of water until it was successfully discharged offsite. The condenser was required to be used as a temporary storage facility for the water and therefore the turbine was exposed to a very humid environment until the water issue was resolved. This moisture centributed to the corrosion observed on the rotors when they were removed from the casings.

B. Analysis Data The pertment turbine design information is as follows:

Continuous maxunum rating (CMR/

1,100 MWe Rated speed 1,800 RPM H.P. Inlet steam pressure 965 psig at temperature 540 F L.P. Inlet pressure 219.8 psig at temperature 513 F Condenser vacuum 28.5 In Hg Absolute pressure at turbine exhaust 1.5 In Hga Final feed temperature 420 F Maxunum overload rating 1200 MWe

• the unit has been recently upgraded by 5% to 1155 MWE Extraction points:

H.P. cylinder - after stage 5 to #6 H.P.F.W. Heater H.P. Cylinder exhaust to MSR and #5 H.P.F.W. Heater North L.P. & south L.P.- before stage 5, to #3 L.P.F.W. Heater Center L.P.- before stage 3 to #4 L.P.F.W. Heater North L.P., Center L.P., south L.P.- before stage 7, to #2 L.P.F.W. Heater North L.P., Center L.P., South L.P.- before stage 8, to #1 L.P.F.W. Heater The pertinent generator design information is as follows:

Continuous Maximum Rating 1,350 MVA; 1,215 MWe Power factor 0.9 lagging Speed at 60 Hz 1800 RPM

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1 Ternunal voltage 22,000 volts l

Current 33,433 Amps l

Design Spec.

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Excitation at 1215 MWe 5130 Amp,566 Volts,2910 KW 1

Excitation at 1100 MWe 4755 Amp,535 Volts,2546 KW

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Hydrogen Space in generator 4,200 SCF Hydrogen required to fill to 75 psig 29,400 SCFM.

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7 Previous failures at Fenni-2 are as follows:

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h In 1990, a failure of stage 4 blades occurred on LP3 rotor. At the same time the unit was running with LP stage 5 removed and the failures were attributed to the unusually high loadmg on stage 4 with stage 5 rotor blades removed but with stage 5 diaphragms installed.

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All stage 4 blades were replaced in 1991. (Blades removed from LP-1 and LP-2 rotors were 5

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On the replacement blades the original design was retained but understraps were introduced to provide continuous shroud interconnection for additional damping on all flows.

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In 1989, following the finding of cracks in the blade roots all stage 5 blades were removed 9m and replaced with root blocks. The failures were attributed to resonance of wheel or packet modes in frequency range where damagmg vibrations are not normally encountered. Unusual A IT excitation (possibly water accumulation) was suspected.

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blades were replaced and a program of blade replacement or repair was started. The LP-3 rotor had not yet been fully repaired at the time of the current failure. During RF01, LP-1.

4 s: age eight blades were replaced, the best blades from LP-1 were used to replace the worst y

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blades on LP-2 and 3. The removed blades were overhauled and made ready for RF02 when i

all stage 8 blades on LP-2 were replaced. The removed blades were overhauled and made i

i ready for RF03 when the LP-3 blades were to be replaced. A decision was made to defer the j

LP-3 blade replacement until RF04. GEC concurred with the provision that the LP-3 blades be inspected during RF03. This inspection was started but did not produce useable evidence that the blades had not degraded to a serious level.

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j Information from the alarm typer indicates that there was a 19 MW electrical disturbance followed

.by a differential thrust alarm, output breaker openmg, and turbine overspeed trip. The overspeed trip is disputed by the investigators and is not considered to be factual evidence of an actual overspeed j

event. The turbine Manufacturer (GEC) states that the event was caused by the loss of the L-0 bladmg resultmg in an out-of-balance condition to the remaining rotating element. Each blade weighs about 75 pounds. Loss of 5 blades minus the roots and platforms would result in the loss of about 300 pounds from the wheel.

There is no evidence that the turbine trip was from another source other than overspeed with the conclusion being that the overspeed trip was actuated by vibration of the turbine. Compounding the w

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-o.mi ra r.nni 2.Juty 26. it94 problem is that some of the turbine and generator instrumentation was damaged within milliseconds of the initiating event.

The generator output breakers opened as the resuh of reverse current after the turbine throttle valves and intercept valves had closed. There was a minor overshoot of turbine speed when the output breakers opened resulting in a maximum speed ofunder 61 Hz. This is still well below the mimmum overspeed trip setpoint.

The utihty staffprd o assemble a detailed plan to perform inspections and initial disassembly t

of the turbine and generator which was accepted by Fermi management and the NRC AIT which allowed the Turbine Generator Assessment Team (TGAT) to proceed Working with the staff, FPI assisted in the development of a tree analysis diagram that produced approxnnately 1500 termmal items fSt could have contributed to the failure. Because of the detail of the tree, a matnx was developed to allow for computer tracking and focusing of the termmal items to assure that no one detail could be overlooked.

The analysis tree is designed to provide a relatively simple, graphic method of addressing a very complex problem with many possible scenarios. The basic prenuse is that all possible modes of failure are depicted in the validated diagram and that by addressing each specific terminal item, the true failure mod (proxunate cause) ofthe problem will eventually become obvious. In the final analysis, 9

it is the responsibility ofthe analysts to provide documentation for each of the specific termmal items that will provide factual evidence that the termmal item is either a contnbutor to the failure or it is not. However, application of pure logic is an acceptable method for this decision making process, provided, that the logical process is well documented.

The above described process is an indispensable step in arnving at the root causes of a failure. In simpler cases, the process may be totally a mental process, however, it must be conducted. It is important that the difference between a proximate or apparent cause and a root cause be understood if the above process is to succeed A apparent or proximate cause of a problem is best described as failure mode identification such as:

a beanng fails due to fatigue brought about by axial misalignment of_the shaft, or a motor failed due to vibration induced insulation failure brought about by loose slot fillers.

Root causes are, on the other hand, best described as those factors, that if corrected, would have prevented an event (and similar other events) from occurring, such as poor work practices and defective post maintenance testing that allowed axial nusalignment of a shaft to exist. If conditions such as these occur in an isolated case then they would be the root causes, however, if the above practices exist through out the orgaruzation, then the root causes would lie in a higher plane, somewhere in the organizational or programmatic areas.

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laurun Stanas Report. !h Root Cause An Jyns Assammern.Detron Edson Fermi 2. July 26,1994 Bolts holding the upper palm key blocks have fractured (reported previously and seen in photographs).

Bolts holding heat shield in place on the rear of number 1 pedestal are hand tight.

Flat bars to which are attached radial datum pegs on each side of the pedestal are loose -i.e. bolts are in place but are slacked off.

2. NUMBER 2 PEDESTAL (HP-LP)

Generally good condition. A number of bolts which attach the front heat shield to the pedestal and the rear bellows unit to the pedestal can be turned by hand but neither unit appears to have moved.

3. NUMBER 3 PEDESTAL (LPl-LP2) 1 LP2 rear shaft gland bellows fractured. Top half vertical gland assembly to pedestal bolts are hand tight - worst case backed off1/16" Number 7 bearing main holding down bolts (4 off) are all hand tight as too are the horizontaljoint Duts.

Bolts which hold pedestal down to the foundation are hand tight.

LP3 front shaft gland bellows fractured, bolts sheared and assembly rotated as shown in photographs.

Looking through the holes in the top halfgland fabrication there are signs of rubbing on the shaft over a 2" arc, but the view is obscured. However the rubs do n21 appear to be deep.

It was possible to view the number 7 bearing through a hole in the LHS pedestal cover. A sliver of white metal can be seen projecting out 'of the beanng at approximately 45 degrees to the venical.

There is no sign ofblucing of the adjacent shaft and there is no buning of the brass wiper bolted onto the bearing.

Coupling guard looks tight (zero clearance) at TDC -i.e. guard appears to have dropped. Viewed from the hand barring hole the coupling guard appears to be shattered and overlapped in parts.

Viewed from the number 8 beanng vantage point the coupling guard horizontal joint is shattered and distorted.

5. NUMBER 5 PEDESTAL LP3 rear shaft gland bellows fractured. Adjacent oil wiper has a burr at TDC.

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i Keep halfjoint bolts missing on right hand side, other half bolts are hand tight.

Main beanng holding down bolts are hand tight and main bolts holding bottom of pedestal to beanng l

beam are also hand tight.

i Number 8 beanng viewed from the left hand side cover plate hole. No signs of any shaft blueing and i

I no white metal can be seen at rear of beanng or in the bottom of the pedestal.

i No evidence ofBDC rubs on brass wiper bolted on to the rear of beanng 8. Wiper appears to be 3

concentric with the shaft and the bevelled edge of the wiper can be seen.

Number 9 beanng viewed from the rear of the pedestal (both left and right hand) where the rear oil catcher assemblyis missing. Condition of the shaft and beanng smular to number 8 bearing. There is a piece of material lying in the bottom of the pedestal which appears to be a piece of machined casung approxunately 12-16"long by 2" by 2" with three equidtstant spaced holes and fractured ends.

Unable to see where this piece can,e from as the beanng looks intact from the observed angles.

NOTE: This piece is lying in the bottom of the pedestal between number 9 bearing (generator front) j and the generator end of wall of the pedestal.

l The shaft surface between the number 9 bearing and the biological wall is coated with oil. But when j

the oilis rubbed away the shaft surface is shiny and bright. There are only very slinht marks on the shaft surface even though the top and bottom half rear oil catcher assembly was sheared off and thrown clear of the turbine.

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6. BEARINGS l

These beanngs which could be viewed (i.e. 7,8,&9) all appear to be intact and do not appear to have j

rotated within their mountings.

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7. LP3 HOOD j

It appears that the two verticaljoints have given slightly and allowed small amounts of material / liquid i

to seep through (dirty brown in color). The effect is more marked on the rear joint than the front i

joint. There is no similar effect on the LP2 and LPl hoods.

l An internal inspection of the If turbines, in preparation for removing the turbine hoods, was conducted on February 1-2,1994. The inspection report is quoted below:

REFERENCE:

Work Req # 000Z940422 LP-3 20

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.n.iroit ta.oo r.,mi 2. Jury 26.1994 SOUTH (GENERATOR END) - No damage, but lacing spools are rusting. Very humid.

NORTH END: - East side locanng key for outer cylinder has a plate adjacent to it which has rotated, but is still in place under the cylinder.

East side has hole in sheet metal along hood horizontaljoint. This metal is probably a flow guide orjoint protection.

Approxunately 13 stage 8 blades adjacent to the 4 or 5 missing blades { confirmed later to be five} are missing the lacing spools. See sketch attached.

Damaged stage 8 diaphragm, both blades and casting.

Blades on West side in better shape than on east side.

West side 2 pieces of debris, one is sheet metal; other may be a small piece of blade (<3 inches x 3 inches)

LP-2 East side has broken sheet metal cover over outer cylinder horizontaljoint bolts. This is a typical maintenance item and would not affect lifting hood. The sheet metal is normally removed later during outer cylinder disassembly.

LP-1 No damage observed inside hood.

j Photographs taken during this inspection disclosed that there were five blades missing; all broken off near the platform.

An inspection performed on 15 February,1994 of the LP-3, L-0 blades disclosed the following information which is quoted directly:

Blade numbers are from RF-02 per Bill Ackerman, numbered in rotation increasing CCW as viewed from the turbine end.

Blade number 9 is the first failed blade with rotation High certamty of high cycle fatigue from trailing edge forward { sketch provided showing that crack originated at trailing edge and propagated about 6 inches toward the leading edge and the remainmg five inches failed due to overload}.

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intarun Status Raport. s-4-~ A-is Race Cause Anahus Assasseruss. Detroit E& san Fermi 2 July 26, t 994 Fatigue appears to be old, chevroned, oxided, prior to Christmas day.

Blade 8 to 5 appear to be fresh tears due to tensile overload. No obvious fatigue, even at the trailing edge. Crack heights are as follows: 8,11/4";7,11/4",6,11/2",5,11/8" Blade 4 - bent wavy trailing edge 1/2" P-P. 1/2 x 2" high tear in trailing edge at about 24" high, tip to trailing edge. Trailing edge lacing spool is gone, " ripped off'.

Blade 3 - cracked at platforTn radius from tralhng edge 1 1/2", angled 45 degrees to tangent of blade.

Tearin tralhng edge 24" height. Tip bent about 3" against rotation. Crack is 1 1/4" from platform ofleadmg edge ofblade 2. Crack is a tear. Appears (that the blade} is untwisted about 30 degrees Blade 2 - tip bent against rotation about 3" over last foot, also untwisted about 30 degrees.

Cracks in blades 1 and 3 result fro., movement towards generator.

Blade 1 - crack 1 1/2" from platform about 4 3/4" long from trailing edge tear. Tip also bent against rotation about 6" and untwisted about 30 degrees.

Blades 64-59 have tip damage, relatively minor in comparison, also missing lacing spools.

Wheel position 27 on the turbine end blade marked "turb. cycl I blade 48", intact lacing spool appears to be in place, has a ding in the trailing edge at 4" high, approximately 2" high by 1/2" deep.

Fluorescent magnetic particle inspection, performed on 26 February,1994 of the front flow L-0 row of blades disclosed that there were additional indications on blades as follows:

Blade 2,3,4 have multiple intermittent linear indications in and propagating from the lacing spool holes. Maximum length of 7/8" Blade 41,42,43 have one linear indication within the impacted area located approximately 1/4" from then platform on the trailing edge of the blade.

Blade 64 has multiple intermittent lir. ear indications on the convex side of the air foil, approximately 1" from the platform oriented perpendicular to the longitudinal axis of the air foil The indications start 1" from the trailing edge to 13/8", total length of 1 1/4" Blades I and 3 had protective tape covering an area from the platform to approximately 3" above the platform (installed to protect known indications from dye contamination).

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.o.ma % r i 2.uv u im Flourescent magnetic particle inspection, performed on 26 Febmary,1994 of the generator end L-0 row of blades disclosed that there were indications on blades as follows:

Blade 53 has two knear indications on the convex side of the air foil, S/8" from the platform oriented perpendicular to the longitudinal axis of the air foil. One indication is 1 1/4" TO 21/4" from the trailing edge (total length 1"), the second indication is 3 3/8" to 41/4" from the trailing edge (total length 7/8"). The location of these indications are where the platform to the air foil. This area has mirfaceirregulanties (ridges) that the magnetic particles are held to. Other blading have these same surfaceirregularities but did not show indications by MT. These indications were later polished out and were determined to be inconsequential r

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VI References

1. Metallurgical Analysis ofFermi 2 LP3 Eighth Stage Turbine Blading, Detroit Edison Technical and Engineering Services, Report No. 94V70-13, dated June 20,1994

2. Failure Diagnostic Guidebook,1991 Failure Prevention Inc., Chong Chiu, Ph.D.

3. Fermi 2 Turbine Generator Assessment Team Action Plan, January 14,1994 Rev.1 l

l

4. Root Cause Guidebook,1989 Failure Prevention Inc., Chong Chin, Ph.D.

5. Steam Turbe Blades: Considerations in Design and a Survey of Blade Failures, EPRI CS-1967 i

Topical Report August 1981 1

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l

6. Survey of Steam Turbine Blade Failures, EPRI CS-3891 Final Repon March 1985 l

7. Summary of FPI Metallurgical Analysis of Stage 8 Failures by Dr. Mostafa

5. Memo: Mr. Ralph Ortolano to hir. J. Summy,

Subject:

Input for Root Cause Analysis Report i

dated July 25,1994 l

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i Attrinment I FermiIndependent Root Cause Analysis Engagement Plan 1

1

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ENGAGEMENT PLAN

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FOR THE FERMI ROOT CAUSE ANALYSIS 'OF TURBINE GENERATOR EVENT OF DECEMBER 25,1993 l

Purpose:

Provide the outline that will be followed to ensure FPI satis 6es the requirement of successfully assistmg Detroit Edison Company perform a detailed root cause analysis of the turbine generator event that ocairred on December 25,1993. Per the Fermi Investigation Manager's request FPI will perform this as an independent analysis team.

Scope:

FPI will perform an independent review of the root cause analysis of the turbine generator fault that occurred on D~~har 25,1993. This by request ofthe Fermi Team Manager involves the following:

~

r-Indepe. 'edly monitor initial Fermi 2 Turbine <renerator Assessment Team (TGAT) o activities and make recommendations to Mr. Len Fron, Team Maraccr.

Independently assess the TGAT Action Plan and A"=^=am used to perform o

inspecions and provide feedback to the Team Manager, l

Assist in the pg. don of a detailed Failure Modes chart for determining the various i

o failure modes to be investigated in completing the root cause po Independently assess information, to be provided by the TGAT, to ensure root cause[

\\

efforts are rigorous. This will include items such as the event time line, machinery l

history, indust:y information pertinent to the event, etc.

Perform independent analysis rmry to determine the root cause(s) of the turbine-o generator failure. These analyses will typically consist of metallurgical analysis of failed components, chemical analysis, stress analysis, model projections, etc.

6 Provide a detailed report of the FPI activities with an explanation of the root cause(s) and recommended corrective actions to prevent recurrence.

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Background:

At approximately 1315 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />5.003575e-4 months <br /> on December 25,1993, the Fermi 2 plant experienced a turbine-generator failure and automatic reactor trip. The immediate cause of the turbine-generator failure is not known. The failure resulted in extensive damage to the turbine, generator, connected auxiliary piping, bearings, foundations, exciter, and generator to exciter coupling.

s s,

i-The most extensive outwardly visible damage is in the local area of the exciter and coupling to the generator. This includes evidence of a hydrogen explosion and fire, a sheared generator to exciter mmh'- destruction of the after (outboard) exciter beanng with resultant release of the turning shaft into the exciter stator, and sheared or extracted foundation fasteners.

Obvious visual damage to the IJ-3 tmbine includes broken blading in the L-0 generator end row and damage to the turbine shroud and casing where at least one portion of a blade exited the turbine through the outer casing Damage to the remaining turbine units is unknown but sheared and extracted bearing cap fasteners and damaged casing seals is evidence of some damage to all sections of the turbine Generator damage includes a hydrogen burn with an apparent source through the generator seals.

Seal water, cooling water, and lube oil lines were all damaged where they pulled away from the turbine and generator. This resulted in loss of these services while the unit was still rolling. Coast down time is indeterminate but appears to have been approximmedy 4 - 5 minutes, probably without sufficient lubricating oil or seal oil.

Information from the alarm typer shows that there was a 19 MW electrical disturbance followed by a differential thrust alarm, output breaker opening, and turbine overspeed trip. Other plant information does not suggest that the turbine was in an overspeed condition. The turbine manufacture (GEC) believes it is possible that due to the vibration of the tmbine, the mehanical overspeed trip device was actuated, thus causing the turbine to trip on overspeed. GEC also believes that the event was caused by the loss of the I 0 bladmg (it is not known how many blades have separated) which resulted in an out-of-balance condition to the remaining rotating element.

C===Emg the problem with respect to data from the turbine is the fact that much of the turbine and generator instrumentation was damaged within a short period of the event initiation.

FPI has been requested by the utihty to provide an oversight review of the root cause analysis as conducted by the plant staff team. Jeff Summy and Don Kidder arrived at the plant Monday, January 3,1994 and began this process Mr. Len Fron has been designated as the Manager for the Turbine-Generator root cause. During the first week, the activities were mostly related to review of team fonnation and action plan strategy. The entire turke-genemtor and condenser areas are under quarantine by the NRC AIT and therefore inspection and repair activities will proceed slowly i

untilroot cause is understood.

It is clearly the desire of Fermi Management to determine the root cause and implement corrective actions to prevent recurrence before the unit is restarted. This is expressed repeatedly to the team by Mr. Fron and is in the Mission and Goals of the TGAT Action Plan.

Approach:

Overall Project Coordmation will be through either the Project Director, Jeff Summy, or the Assistant Project Director, Don Kidder. These individuals should be informed of any significant issues, difficulties, or requirements of FPI investigators assigned to the Fermi 2 Turbine Generator Root Cause Project.

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• Since a fim: schedule ofacovities is not known at this time it is requested that the following schedule be used as a " flexible" guide to plan from. Routine communications will be provided from Don or Jeff to the FPI team to ensure all personnel are aware of current plans.

Date(s)

Activity Investiestor r-T January 12-13 Condenser entry, inspect Kidder / Summy removeloose debris.

January 14-15 Degas Generator Kidder January 16-19 Initial tu6ine bldg walk Mostafa / Summy down, catalog, lab analysis January 20-24 Initial tusine, generator, Onolando / Summh exciterinspections January 25-29 Tu6ine, generator, exciter Onolando / Chen /

disassembly Kidder Febmary 1-10 Complete material analysis Mostafa / Kidder Febmary 11-16 Complete Root Cause Analysis Chiu (Team)

Note: It will be determined at the actual time that a particular activity occurs what resources will be required on-site and for what purpose.

A project coordination meeting / conference call will be conducted with all project panicipants on FridayJanuary 14,1994. A review of the known facts will be conducted and discussed with the team.

p' pidirsary schedule will be ^==ad o ensure the correct resource (s) are listed for the activitX t

and that the resource will be available at that time. A review of the Failure Modes chan constructed 1

[by Don Kidder will also be conducted to ensure all failure modes are included in the investigation 2

Ifspedfic data is needed when you are not actually on-site please contact Don or Jeff so that we are not impacting the Fenni site personnel. It is requested that each investigator keep a log of their activities associated with this project and specifically those activities that are conducted on-site.

Please provide a copy of those log sheets with a copy ofyour time sheets to Jeff at the San Clemente office at the end of each pay period. Each investigator will be required to submit a report at the completion of the project detailing their involvement, conclusions, recommendations, and any information necessary to support the complete root cause effort.

The above acuvities will be conducted at the Fermi site with the exception of material analysis which will most likely be conducted at the Detroit Edison Analysis Laboratory in Detroit.

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Expectations and Deliverables:

It is expected of the FPI Fermi 2 Turbine-Generator Root Cause Failure Team to work closely in conjunction but in an independent fashion with respect to the root cause analysis with the Fermi TGAT. It is further expected that the FPI Team will support the schedule as defined by Detroit Edison.

The FPI Team will provide a detailed and acairate root cause analysis using all available technologies, industry experience, and FPI resources in a cost effective manner. Based on the root cause(s),

recommended corrective actions will be provided which if adopted will prevent or mitigate recurrence.

/e Date:

/ IE N Prepared by "

WefS.'Summy i

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8 FERMI-2 MTG EVENT TIE 11NE TIME EVENT TIME 1315 LAPSE 47.406 O/S ELCT CKT FAULT 0

47.413 THRUST BEARING STRAIN HI D/P 0.007 47.443 BRG 9 HIVIB ON SHAFT @ 6 MIL 0.037 47.475 SEISMIC EVENT S.P. 0.01 G 0.069 i

47.482 BRG 8 HIVIB ON SHAFT AT 6 MIL 0.076 47.514 BRG 4 HIVIB ON SHAFT AT 6 MIL 0.108 47.526 BRG 11 ON LOAD ON PED AT 5 MIL 0.12 47.529 UA THROTTLE VLV FAULT 0.123 47.53 BRG 11 HI VIB ON PED AT 3 MIL 0.124 47.531 TURBINE O/S MECH TRIP 110%

0.125 47.532 BRG 11 RUN UP OF PED AT 5 MIL 0.126 47.534 BRG 5 HI VIB ON SHAFT AT 6 MIL 0.128 47.538 BRG S ON LOAD ON SHADFT AT 10 MIL 0.132 47.543 TURBINE TRIP RFLAY TRIPPED 0.137 47.544 TURB CONTROL VLV FAST CLOSE 0.138 47.555 RPS AuOATION 0.149 47.558 BRG 7 HI VIB ON SHAFT AT 6 MIL 0.152 47.582 BRG 10 HI VIB ON PED AT 3 MIL 0.176 47.587 ELECTRIC GOVERNOR TROUBLE 0.181 47.591 BRG 9 ON LOAD ON SHAFT AT 10 MIL 0.185 47.598 BRG 3 HI VIB ON SHAFT AT 6 MIL 0.192 47.599 BRG 8 RUN UP ON SHAFT AT 10 MIL 0.193 47.6 BRG 9 RUN UP ON SHAFT AT 10 MIL 0.194 47.601 BRG S ONIDAD ON SHAFT AT 10 MIL 0.195 47.603 GEN LIQUID LEAK HI ALARM 0.197 47.606 BRG 5 RUN UP ON SHAFT AT 10 MIL 0.2 47.617 BRG 1 HI VIB ON PED AT 3 MIL 0.211 47.622 BRG 7 RUN UP ON SHAFT AT 10 MIL 0.216 47.623 BRG 4 ON LOAD ON SHAFT AT10 MIL O'.217 47.624 BRG 7 ON LOAD ON SHAFT AT 10 MIL 0.218 47.632 BRG 4 RUN UP ON SHAFT AT 10 MIL 0.226 47.637 BRG 2 ON LOAD ON SHAFT AT 10 MIL 0.231 47.648 BRG 2 RUN UP ON PED AT 5 MIL 0.242 47.654 BRG 3 RUN UP ON SHAFT AT 10 MIL 0.248 47.655 BRG 10 RUN UP ON PED AT 5 MIL 0.249 47.664 BRG 10 ON LOAD ON PED AT 5 MIL 0.258 47.691 U/A HP STOP VLV FAULT 0.285 47.697 MS BYPASS VLVS OPEN 0.291 47.738 BRG 1 RUN UP ON PED AT 5 MIL 0.332 47.739 BRG 1 ON LOAD ON PED AT 5 MIL 0.333

l.

FERAD-2 MTG EVENT TIME INE TIhE EVENT TIhE 1315 LAPSE 47.79 M.S. STOP VLVS CLOSED 0.384 47.682 BRG 3 ON LOAD ON SHAFT AT 10 MIL 0.276 47.791 M.S. STOP, THROITLE VLV TRIP 0.385 47.871 BRG 9 HIVIB ON SHAFT AT 10 MIL 0.465 47.897 STAT WAT LOW FLOW 0.491 47.956 BRG 10 HIHI ON PED AT 4 MIL 0.55 47.975 BRG 11 HI HI ON PED AT 4 MIL 0.569 48.073 BRG 1 HIHI ON PED AT 4 MIL 0.667 48.084 BRG 8 HIHI ON SHAFT AT 12 MIL 0.678 48.125 BRG 4 HI HI ON SHAFT AT 12 MIL 0.719 48.155 6S FD HTR ESS CHFCK VLV CLOSED 0.749 48.156 BRG 5 HIHI ON SHAFT AT 12 MIL 0.75 48.165 BRG 7 HIHI ON SHAFT AT 12 MIL 0.759 48.19 BRG 2 HIHI ON SHAFT AT 12 MIL 0.784 48.247 BRG 3 HI HI ON SHAFT AT 12 MIL 0.841 48.316 DETRAIN TK TURB END HI/LO 0.91 48.356 6N FD HTR CHECK VLV CLOSED 0.95 48.406 COAST DOWN SYSTEM STARTS 1

48.406 TURBINE AT 1800 RPM 1

48.416 LP STOP/IV 3-4 TRIP 1.01 48.432 4S FD HTR CHECK VLV CLOSED 1.026 48.447 4N FD HTR CHECK VLV CLOSED 1.041 48.458 INitKCEYr VLV FAULT 1.052 48.516 3N FD HTR CHECK VLV ROSED 1.11 i

48.635 4N FD HTR CHECK VLV CLOSED 1.229 49.125 LOSS H2 SEAL OIL 1.719 48.705 3S FD HTR CHECK VLV CLOSED 1.299 48.989 H2 SEAL OIL PUMP AUTO START 1.583 49.406 TURBINE AT 1800 RPM 2

49.125 H2 SEAL OIL PUMP AUTO START 1.719 49.454 REC 11FIER COOL LINE #4 LOW FLOW 2.048 49.515 LP STOP/1-3-5 TRIP (E. MSR) 2.109 49.573 STAT COOL PUMP AUTO START 2.167 49.765 SEAL OR/ GAS DIFF PRESS FAULT 2.359 49.77 SEAL OIIJGAS DIFF PRESS LOW 2.364 50.058 SN FD HTR CHECK VALVE CLOSED 2.652 50.167 H2 GAS PRESSURE LOW 2.761 50.311 GL ^.ND STM PRESS 2.905 50.991 LP EXHAUST SPRAYS ON 3.585 51.185, LP EXHAUST SPRAY EhERG PUMP ON 3.779

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FERM1-2 MTG EVENT TIME LINE 1

TIME EVENT TIME 1315 LAPSE 51.396 SEAL OIL STRAIN HI DP 3.99 51.406 TG IS AT 1800 RPM 4

51.S $ i RECTIFIER COOL LINE #4 LOW FLOW 4.15 51.559 REC 1&ER COOL LINE #4 LOW FLOW TRIP 4.153 52.19 BRG 6 SHAFT DIFF EXPANSION NEGATIVE 4.784 s

52.599 THRUST BRG OIL PRESS 1.DW <8 PSIG 5.193 52.72 SEAL OIL STRAIN HI DIFF PRESS 5.314 52.953 CONDENSER PRESS HIGH 5.547 53.091 H2/H2O DIFF PRESS LOW 5.685 53.572 CONDENSER HI FAULT 4.5

• Hg 6.166 53.766 EXHUAST SPRAY STRAINER HI DP 6.36 54.099 THRUST BRG NEG WEAR PRE-TRIP 6.693 55.212 AVR CHAN B TRIP 7.806 55.311 BRG OILPRESS LOW FAULT <10 PSIG 7.905 55.351 TURBINE OIL PUMP AUTO START 10 PSIG FAT LTNG 7.945 55.644 TURBINE EMERG OIL PUMP START 10 PSIG FAT T TNG 8.238 55.658 AVR ON MANUAL CONTROL 8.252 55.992 BRG 1 SHAFT DIFF EXPANSION POS 8.586 56.367 BRG 6 SHAFT DIFF EXPANSION NEG 8.961 56.4 TG AT LESS THAN 1800 RPM 8.994 57.161 GEN DIFF RET-AY STRING OPERATED 9.755 j

57.183 345 KV BREAKER POS C.F. OPEN 9.777 57.184 345 Kv BREAKER POS C.M. OPEN 9.778 57.229 E. STAT COOLING PUMP OFF 9.823 ~

Y-57.238 W. STAT COOLING PUMP OFF 9.832 57.308 GEN FIELD BKR OPEN 9.902

[

l 57.397 GEN FREQ HI/LO 9.991 i

58.036 STAT WTR FLOW LO FAULT 10.63 58.53 GEN INLET WTR TEMP HI 11.124 59.382 SS FD HTR CHECK VLV CLOSED 11.976 59.599 FIRE ALARM 12.193 59.694 GEN FREQ HI/LO 12.288 59.714 REC 1w1ER LINE 1 LO FLOW FAULT 12.308 s

59.815 5N FD HTR CHECK VLV CLOSED 12.409 59.945 RECIRIER COOL LINE 1 LO FLOW TRIP 12.539 60.167 REClelER COOL LINE 4 LO FLOW TRIP 12.761 60.194 REC 11MtR COOL LINE 3 LO FLOW TRIP 12.788

4 Turbine Vibration Alarm List 1

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l BEARING VIBRATION DATA

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+ _ _ _ _ _ _ _ _ + _ _ - _ _ _ _ - + _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ -

! 47.443 i O.037 IBRG 9 HI VIB DN SHAFT C 6 MIL

+ - _ - _ - _ _ _ + _ _ - _ - _ _ _ + - _ - _ _ _ - _.. - - - _ _ _ _ _ _ _ _ _.. _ - _ _ _ _ _ _ _ - _ _

i 47.482 i O.076 IBRG B HI VIB ON SHAFT AT 6 MIL

! 47.514 1 0.108 IBRG 4 HI VIG ON SHAFT AT 6 MIL

+ _ - _ _ - _ _ _ + _ _ _ _ _ - _ _ + _ _ _ _ _ _ - - - - _ _.. _ _ _ _ _ _ _ _ _ _ - - _ _ _ - _ _ - _ _

l 47.526 i O.128 IBRG 11 ON LOAD ON PED AT 5 MIL

+ _ _ _ _ _ _ _ _ + _ - _ _ _ _ _ _ + _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

! 47.53 i O.132 IBRG 11 HI VIB ON PED AT 3 MIL

+ _ - _ _ _ - - _ + - _ _ _ _ _ _ _ + _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _

! 47.532 1 0.152 iBRG 11 RUN UP DN PED AT 5 MIL

+-_---___+_____-__+_________________.._____________

l 47.534 l 0.185

!BRG 5 HI VIB ON SHAFT AT 6 MIL

+___--___+________+__

i 47.538 ! O.192 lBRG B ON LOAD ON SHADFT AT 10 MIL

+ - _ _ _ _ _ _ _ + _ _ _.-

__+

l 47.558 i O'.193 lBRG ? HI VIB ON SHAFT AT 6 MIL

,________+____-

+_____-_-_-__-_ __===_____________

i 47.S82 0.194

!BRG 10 HI VIB ON PED AT 3 MIL

+________+________+

l 47.591 ! O.195

!BRG 9 ON LOAD ON SHAFT AT 10 MIL

+- __-___+____

_+-_________________________________

! 47.598 i O.2 IBRG 3 HI VIB ON SHAFT AT 6 MIL

+-_______+____-___+__---_____-___--______________--__

l 47.599 i O.216 lBRG B RUN UP DN SHAFT AT 10 MIL

+____---_+-_-_____+______________-___________-_____--

i 47.6 i O.217 IBRG 9 RUN UP ON SHAFT AT 10 MIL

+ _ _ _ _ _ _ _ _ + - _ _ _ _ _ _ _ + _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -

! 47.601 i O.218 IBRG 5 DN LOAD ON SHAFT AT 10 MIL

+_______-+___

=+______-____________--_____________

i 47.606 ! O.226

!BRG 5 RUN UP DN SHAFT AT 10 MIL

+-_-_____+--___-__+_____._-_-______--_____---________

i 47.617 1 0.231 IBRG 1 HI ON PED AT 3 MIL

+________+-_______+__-____-_-_____________________-__

! 47.622 i O.242 IBRG 7 RUN UP DN SHAFT AT 10 MIL

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+ _ _ _ _ _ _ _ _ + _ _ _ - _ _ - _ + _ - - _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ - _ _ - _ - - _ _ _ _ _ _

r 1 47.623 ! 0.248

!BRG 4 DN LOAD ON SHAFT AT10 MIL

+

+________+___-

-+___________-_-__-___=-

i 47.624 : 0.276 IBRG 7 DN LOAD ON SHAFT AT 10 MIL i 47.632 : 0.465 IBRG 4 RUN UP DN SHAFT AT 10 MIL

+--___-__+-_______+________-____--____--_____________

i 47.637 I O.678 IBRG 2 ON LOAD ON SHAFT AT 10 MIL

+--______+_____-__+____-______-______________________

i 47.648 ! O.719 lBRG 2 RUN UP DN SHAFT AT 10 MIL d

+________+________+_-__---_____-___-______________-__

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l 47.654 :

0.75 lBRG 3 RUN UP DN SHAFT AT 10 MIL

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+ - - - -. _ _ _ _ + - _ - _ _ - - - + _ _ - _ _ - - _ - - - _ - _ - - - _ _ - _ _ _ - _ _ _ _ _ - - _ _ _

l 47.655 : 0.759

!BRG 10 RUN UP DN PED AT 5 MIL 0

o--_----_+_-_-_-__+-_-__--___-__-_____-_____-_______-

l 47.664 : 0.784 BRG 10 DN LOAD ON PED AT 5 MIL 5

i 4

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+________+__&_____+__________________________________

l 47.738 I O.841 lBRG 1 RUN UP DN PED AT 5 MIL l

+__

___+________+__________________________________

! 47.739 i lBRG 1 ON LOAD ON PED AT 5 MIL

+ _ _ _ _ _ _ _ _ + _ _ _ _ _ _ _ _ + _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

l

! 47.682 !

IBRG 3 ON LOAD ON SHAFT AT 10 MIL l 47.871 1 IBRG 9 HI VIB ON SHAFT AT 10 MIL

+__ _____ ________ ____ ___________________ __ _______

i 47.956 i

!BRG 10 HI HI ON PED AT 4 MIL

+________me._

______e__

! 47.975 I lBRG 11 HI HI ON PED AT 4 MIL

! 48.073 1 IBRG 1 HI HI ON PED AT 4 MIL

__e______

! 48.084 i

!BRG B HI HI ON SHAFT AT 12 MIL e_

+________e________._________________________

! 48.125 :

IBRG 4 HI HI ON SHAFT AT 12 MIL ei.__

! 48.156 i

!BRG L HI HI ON SHAFT AT 12 MIL

+________+________+__________________________________

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I 48.19 i

IBRG 2 HI HI ON SHAFT AT 12 MIL

+________+________+-____-________________-_________-_

l 48.247 lBRG 3 HI HI ON SHAFT AT 12 MIL 1

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i PEDESTALVIBRATION ALARMS IN ORDER OF OCCURANCE i

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