IR 05000206/1987014
| ML20238F378 | |
| Person / Time | |
|---|---|
| Site: | San Onofre, Cook  |
| Issue date: | 08/31/1987 |
| From: | Andrew Hon, Huey F, Johnson P, Tatum T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20238F356 | List: |
| References | |
| 50-206-87-14, 50-361-87-13, 50-362-87-15, NUDOCS 8709160114 | |
| Download: ML20238F378 (31) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-206/87-14, 50-361/87-13, 50-362/87-15 Docket Nos.
50-206, 50-361, 50-362 License Nos.
Licensee:
Southern California Edison Company
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P. O. Box 800, 2244 Walnut Grove Avenue
Rosemead, California 92770
3 Facility Name: San Onofre Units 1, 2 and 3 Inspection at: San Onofre, San Clemente, California Inspection conduc d-
. y 24 through July 4, 1987
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{3I{f7 Inspectors:
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44J e F.' R.
ey, Senior Resident Date Signed Insp c A,. nits 1, 2 and 3
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f J. E.f, um Resident Inspector Date Signed (P,
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n, Resident Inspector Date Signed Approved By:
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3 87 P. H. A hnson, Chief Date Signed React 6 Projects Section 3 Inspection Summary i
Inspection on May 24 through July 4, 1987 (Report Nos. 50-206/87-14, 50-361/87-13, 50-362/07-15)
Areas Inspected:
Routine resident inspection of Units 1, 2 and 3 Operations Program including the following areas:
operational safety verification, evaluation of plant trips and events, monthly surveillance activities, monthly maintenance activities, independent inspection, licensee event report review, and follow-up of previously identified items.
Inspection procedures 30703, 37701, 37702, 61720, 61726, 62700, 62703, 71707, 71710, 92700, 92701, and 93702 were covered.
Results:
Of the areas examined, no violations of NRC requirements were identified. One violation from an earlier inspection is discussed in paragraph 9.d.
8709160114 070901 gDR ADOCK 05000206 PDR
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l DETAILS 1.
Persons Contacted i
Southern California Edison Company H. Ray, Vice President, Site Manager W. Moody, Deputy Site Manager
- H. Morgan, Station Manager
- M. Wharton, Deputy Station Manager
'*D. Schone, Quality Assurance Manager D. Stonecipher, Quality Control Manager
- R. Krieger, Operations Manager
- D. Shull, Maintenance Manager
- J. Reilly, Technical Manager P. Knapp, Health Physics Manager
- W. Zint1, Compliance Manager D. Peacor, Emergency Preparedness Manager P. Eller, Security Manager W. Marsh, Operations Superintendent, Units 2/3 J. Reeder, Operations Superintendent, Unit 1 V. Fisher, Assistant Operations Superintendent, Units 2/3 R. Joyce, Maintenance Manager, Units 2/3 L. Cash, Maintenance Manager, Unit 1
- T. Mackey, Compliance Supervisor
- C. Couser, Compliance Engineer
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San Diego Gas & Electric Company
- J. Winter, San Diego Gas and Electric
- Denotes those attending the exit meeting on July 6, 1987.
The inspectors also contacted other licensee employees during the course of the inspection, including operations shift superintendents, control room supervisors, control room operators, QA and QC engineers, compliance engineers, maintenance craftsmen, and health physics engineers and technicians.
2.
Operational Safety Verification The inspectors performed several plant tours and verified the operability
.of selected emergency systems, reviewed the Tag Out log and verified-proper return to service of affected components.
Particular attention war given to hou:;ekeeping, examination for potential fire hazards, fluid leaks, excessive vibration, and verification that maintenance requests f
had been initiated for equipment in need of maintenance.
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Post Outage Containment Walkdown (Unit 1)
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The. inspectors performed a walkdown of the Unit 1 containment prior l
to leaving Mode 3 operations following the mid cycle outage of Unit i
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1 for reactor coolant pump seal-and other repairs. The. material
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condition of containment.was observed to be satisfactory with the-following exceptions:-
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'(1);' A condensate drain hose for the. dehumidifier located adjacent L
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to the A reactor coolant pump had a burn hole in it where it-O appeared to have come in contact;with;a hot pipe.
The licensee t
fixed this hose.
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.(2) Several. loose capscrews were observed to be adrift on the tops
~.of Loop A safety injection valve MOV 850A and RHR valve MOV 814..The licensee removed these' loose. items.
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(3) Boric acid crystals were ' observed to have accumulated on the cables'in a. safety related cable tray located under the Loop C safety injection bypass valve, MOV-358.
The inspector noted.
that the packing of. valve 358 continued to leak after outage l;
aintenance.
The licensee cleaned and inspected the affected m
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cat'les and confirmed the lack of. any evidence of degradation.
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The-licensee also stated that boric acid 'was considered in the
. equipment. qualification for these cables.
The. inspector.
requested that the licensee identify what actions'he intends to take to preclude. continued packing leakage on the safety injection bypass valves.
This is an open. item (50-206/87-14-01);
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b.-
Safety Equipment Building Water Tiaht Doors (Unit 2)
While making routine tours of the plant, the inspector noted that the water tight door.which allows access to'the Unit 2 safety
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equipment building had a-high differentia 1' pressure across it.
This condition made it difficult to open the> door and inhibited access to and from the building.
This condition was brought to the attention of the licensee.
c.
Bent Valve Stem (Unit 3)
The licensee identified that component cooling water (CCW) valve H
3HV-6371 had a bent stem and could not be cycled to the closed position.
Valve 3HV-6371 is a containment penetration isolation
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E-399.
The inspector verified that this condition was allowed by (
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the Unit Technical Specifications, paragraph 4.6.3.5.
The licensee maintained the valve in the open position to satisfy the Technical Specification requirements.
- d.
Reactor Coolant Pump Seal Degradation (Unit 3)
On June 7. 1987, the lower seal on reactor coolant pump P-004 began i
to show signs of degradation.
The differential pressure across the
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lower seal began to increase and has stabilized at approximately s
2,100 PSIO.
The licensee was monitoring the condition of the middle
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and upper seals for reactor coolant pump P-004, which thus far
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showed no signs'of degradation.
The licensee was also monitoring j
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the performance' of the: seals with a strip chart recorder which has.
c annunciation capabilities.
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~3.
Evaluation of Plant Trips'and Events l
i Reactor Trip On June 21, 1987 (Unit 3)
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i On June 21, 1987, while the Unit was at 100% power,' steam generator E-088 i
experienced a low water level which resulted in a reactor trip.
Approximately ten minutes before this event, the following annunciators
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were received in the control room:
Steam Generator E-088 Level High-Low
Steam Generator E-088 Level Deviation
Steam Generator E-088 Reactor Trip Override
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Control Element Drive Mechanism Control. System Relay Under-Voltage These annunciators'immediately cleared, and the operators believed that a-momentary loss'in power associated with steam generator E-088 Feedwater
' Control System had been experienced.
The plant was not affected by this i
momentary loss of power, and the operators discussed the. appropriate actions to take in the event of a prolonged loss of power of this sort.
Following this discussion, several dozen control room annunciators illuminated.and the op'erator observed that level was decreasing in steam generator E-088.
The operator proceeded to take the actions which were
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previously' discussed, and'took manual control of the Feedwater Control Valve and its bypass valve for steam generator E-088.
The operator adjusted the controllers for full open valve position, but the valves did not respond. The. reactor subsequently tripped on steam generator E-088'
' low water level.
The operator began taking post trip actions as required by procedure to insure the reactor was shut down and in a stable.
condition.
When the operator checked steam genarator water levels approximately two minutes after the reactor trip, he observed that the water' level indication for steam generator E-088 exceeded 100%, while the water level indication for steam generator E-089 was low in the indicating range.
In addition, the operator noticed that the feedwater pumps had tripped, apparently on high vibration.
As.a result of over-filling steam generator E-088, primary plant pressure decreased below the safety injection actuation setpoint of 1,806 PSIA and a safety injection actuation signal was generated.
Safety injection flow was not observed by the operators at that time because primary plant pressure exceeded the shutoff head of the high pressure safety injection pumps.
The operators placed the plant in a stable condition and restored system alignments to normal in accordance with the operating instructions.
As a result of the
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post-trip review and subsequent investigations, the licensee identified the following sequence of events:
Power was interrupted on phase 8 of the non-1E uninterruptible power supply (UPS) system.
The licensee's investigation (
revealed that a bolted electrical connection was loose and L
apparently had not been tightened during the original j.
installation.
As a result of this loose electrical connection,
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L phase B.of-non-1E UPS began to experience intermittent power-L failure.
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l A prolonged loss of the non-1E UPS occurred on phase B.
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caused a loss of power to the Foxboro Spec 200 computer which supplies' power to the feedwater regulating system for steam
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pnerators E-088 and E-089.
As a result of this-power failure,
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l boy.h feedwater pumps went to minimum speed,'and the feedwater.
regulating valves and bypass valves associated with both steam generators went.to the closed position.
The operator
- recognized that water level was decreasing in steam generator E-088 and took manual control of the feedwater regulating valve and its bypass valve for that steam generator.
The operator tried to open these valves with the controller, but'the valves
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did not respond.
Since power had been lost to the Foxboro Spec l
200 computer, control power was not available to manually open the valves.
.The reactor tripped on low steam generator water level.
Although the reactor tripped on low level in steam generator E-088, steam generator E-089 was also losing water level
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i because the loss of power to the Foxboro Spec 200 computer
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affected the feedwater control system for both steam-
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generators.
The operator left the controller for one feedwater
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pump and the feedwater regulating valve and its bypass valve associated with steam generator E-088 in the manual-full open position, and began taking post trip actions.
While the operator was responding to the reactor trip, power
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was_ regained on phase B of the non-1E UPS.
Since power was
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regained on the feedwater control system, feed pump speed increased to approximately 3,200 RPM which is the reactor trip
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l override condition for the feed pumps.
The feedwater regulating valve associated.with steam generator E-089 remained u
l in tho closed position, but its associated bypass valve opened to allow approximately 5% steam generator feedwater flow (these -
are the reactor trip override positions for these valves when they are in automatic control).
Since the controller for the feedwater regulating valve and bypass valve associated with steam generator E-088 was in the manual full open position, these valves opened.
Consequently, steam generator E-088 began to fill with water.
- The operator performed post trip actions in accordance with the emergency operating instructions.
When the operator checked
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steam generator water levels in accordance with the instruction, he cbserved that steam generator E-088 water level exceeded 100% indication and the feedwater pumps had tripped.
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Licensee calculations indicated that a small amount of water l
entered the main steam line.
The plant monitoring system indicated that the feedwater pumps tripped due to excessive
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Overfilling steam generator E-088 caused average reactor l
' coolant system temperature to decrease by approximately 85
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degrees and the reactor coolant system pressure dropped below l
the safety' injection actuation pressureTof l',806 PSIA.
The-pressure continued to drop below the high pressure safety-
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. injection (HPSI) pump shutoff head of approximately 1,450 PSIA, l
L and safety: injection _ flow occurred _for approximately two l
P minutes.
The minimum pressure reached was approximately 1,243 PSIA and the peak HPSI flow was approximately 100' gallons per minute for approximately ten seconds.
Because.HPSI flow was i
short lived, the operator did not notice that flow had occurred during the event and an Unusual Event.was not declared.
l The operators stabilized the plant and maintained hot shutdown
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-(Mode 3) conditions.
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The inspector discussed this event with the licensee to ensure that
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appropriate corrective actions were being taken.
The following issues l
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were discussed with the licensee:
Operator' Response - Due to the power failure that had occurred
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on the non-1E UPS, the-operator placed the controller for steam generator E-088 feedwater regulating valve's and bypass valve.in
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the manual position.
These controllers were left in the manual l
position following the reactor trip while the operator took
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L actions'in accordance with the emergency operating l
instructions.
The licensee has discussed this event with the licensed operators and emphasized the policy that controllers associated with the feedwater control system should not be.left in the manual position when they are left unattended.
The licensee stated that a memorandum would be issued for required reading by the licensed operators and that training on this i
subject would be included in the refresher training program for the licensed operators.
Loss of Pressurizer Level - During this event, reactor coolant l
system shrink caused pressurizer level to decrease into the
surge line.
The licensee stated that this is the expected
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plant response for the amount of cooldown that was experienced.
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During.the event, average reactor coolant system temperature decreased by approximately 85 degrees F which is similar to the
cool down presented in figures 15.1-5 and 15.1-6 of the FSAR.
i These figures indicate that a reactor coolant system average temperature decrease of approximately 80 degrees F will cause i
pressurizer level to drop into the surge line.
The minimum subcooling martin reached during the transient indicated that the surge line did not empty.
II 3 kE Loss of Power to UPS Phase B - The licensee identified a loose
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e'lectrical' connection to be the cause of the temporary loss of l
power.
Other electrical connections associated with the non-1E
UPS system were checked and one other breaker was found with two loose electrical connectors.
Similar power supplies have been checked previously as part of the licensee's ongoing trip j
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reduction program, and no similar connectors have been found to be loose.
The physical appearance of the loose electrical l-connections that were identified indicated that they were not properly tightened during initial installation.
Overfilling of Steam Generator E-088 - The licensee's calculations indicated that water level reached the steam line nozzle (located in the top of the steam generator), and a small volume of water spilled over into the main steam line.
The licensee stated that this section of the main steam piping was designed with sufficient support to allow hydrostatic testing.
Licensee personnel also performed a detailed walkdown of the steam lines to the turbine stop valves and condenser.
Pipe supports and spring can positions were checked and no anomalies were found.
Snubbers on HPSI Discharge Piping - Four small (250 lb)
snubbers were found by the licensee's inspection to have permanently locked up as the result of a minor pressure l
These snubbers have been replaced.
The licensee
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stated that experience has shown these small snubbers to be easily damaged.
Failure of these snubbers has been previously evaluated by the licensee's ongoing snubber reduction program which indicates that these snubbers are not necessary for system operation.
The licensee plans to remove these snubbers during a future outage.
The minor pressure transient occurred j
due to sluggish operation which has been observed in the stop
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check valves at the discharge of each HPSI pump.
Sometimes these valves do not close smoothly, causing a minor pressure transient in the system.
The licensee conducted a walkdown of the system and found no other problems, and an IST was conducted on the_HPSI pumps to verify operability.
The stop check valves in the HPSI pump discharge lines are scheduled for replacement during a future refueling outage.
HPSI Cold Leg Flow Indicator - The licensee's post trip review determined that the HPSI flow indicator in one of the four cold leg injection lines did not indicate flow during the safety injection actuation following the trip.
Subsequent investigation indicated that a zero shift in the flow transmitter calibration existed.
The transmitter was replaced and verified to be working properly before the plant was started up.
The licensee is currently evaluating the cause of the zero shif t that existed in the flow transmitter.
- Reactor Vessel Void Formation - The licensee stated that data collected from the qualified safety parameter display system (QSPDS) indicated that void formation did not occur in the reactor vessel head.
The heated junction thermocouple which provide reactor vessel level indication indicated that the reactor vessel remained full of water.
The inspector examined the licensee's post trip review package to ensure that no anomalies existed in the plant response to this event.
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inspector was satisfied that the licensee had conducted a satisfactory post trip review and that corrective actions were properly completed.
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The licensee returned the Unit to service on June 25, 1987.
No violations or deviations were identified.
4; Monthly Surveillance Activities a.
Unit 1
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The inspector reviewed the following surveillance tests during this report period:
501-12.8-2 Cold Safety Injection System (SIS) and Loss of Offsite Power Test 501-I-2.7 Battery Service Discharge Test on #2 1E Battery S01-12.4-2 Operations In-Service Valve Testing of
HV-852A Feedwater/ SIS Valve After Maintenance The inspection and findings related to the battery test are
discussed in Inspection Report 50-206/87-05.
b.
Unit 2 During this report period the inspector observed the licensee's
conduct of inservice testing of containment spray pump 2P-013.
The inspector verified that this activity was properly authorized in accordance with the licensee's procedures, and was conducted in accordance with engineering procedure 5023-V-3.4.6, " Containment Spray Inservice Pump Test."
c.
Unit 3 During this report period the inspector observed the licensee's conduct of local leak rate testing (LLRT) of the containment purge supply and exhaust valves.
The inspector verified that the LLRT was properly authorized in accordance with the licensee procedures, and was conducted in accordance with procedure 5023-V-3.13 titled,
" Containment Penetration Leak Rate Testing."
l Paragraph 3.6.1.2 of the Unit 3 Technical Specifications limits the measured combined leakage rate for all penetrations and valves j
subject to type B and C tests to 0.6La which equates to 130,287 secm.
In addition, paragraph 4.6.1.7.3 of the Unit 3 Technical Specifications limits the allowable leakage rate for the purge i
supply and exhaust isolation valves to 0.05La, which equates to 10,830 sccm.
The containment purge exhaust valves satisfied the surveillance requirement with a leak rate of 1,058 sccm, but the containment purge supply valves failed the surveillance test with a total leakage rate of 52,275 sccm. Operations was properly notified of this test failure and a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement was entered in accordance with the Technical Specifications.
The licensee factored these leakage rates into the combined total LLRT calculation to
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verify that the acceptable combined leakage rate of 130,287 sccm had not been exceeded.
The calculation indicated that the combined total leakage rate was 71.964 sccm, which was acceptable.
The licensee took actions to clean the valve seats associated with the 8 inch mini purge supply valve and repeated the LLRT.
This subsequent test satisfied the surveillance requirement with a leak rate of
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l 1,272 sccm.
The containment purge supply isolation valves were
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declared operable within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement of the
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Technical Specifications.
I No violations or deviations were identified.
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5.
Monthly Maintenance Activities a.
Troubleshooting Power Range Nuclear Instrument NIS-1206 (Unit 3)
During the plant startup from the mid-cycle outage, prior to reactor q
criticality, the overpower rod stop on NIS-1206 (preset at approximately 20% power) activated prematurely to prevent the operator from withdrawing rods.
After declaring the channel inoperable, Maintenance Order M0 87062978000 was issued to direct the I&C technician to troubleshoot and repair this anomaly which apparently was caused by an optical relay being out of position.
The inspector observed the I&C technician replace the light bulb and realign the optical relay.
NIS-1206 was returned to service in accordance with the M0.
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b.
Repair Body-to-Bonnet Leak on Main Feedwater Control Valve FWS-FCV-456 (Unit 1)
The inspector observed the gasket replacement to repair a body-to-bonnet leak on main feedwater control valve FWS-FCV-456.
The work was properly performed in accordance with M087002881001 and the gasket was verified by QC to be the correct replacement part.
The valve was returned to service without evidence of leakage.
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Repair Feedwater Bypass Valve FWS-CV-142 (Un!t 1)
The inspector observed the replacement of sok cid valve FWS-SV-149, which controls the air supply to valve FWS-CV-142.
The work was properly performed under M087061155004 and the bypass valve was returned to service satisfactorily.
d, limitorque Motor Operated Valve Maintenance (Unit 2)
The inspector observed maintenance being conducted to lubricate the motor operators for limitorque motor operated valves 2HV-9327 and 2HV-9324.
The inspector verified that this maintenance activity was properly authorized in accordance with the licensee procedures, and conducted in accordance with procedure 50123-I-8.28, " Actuators -
Limitorque Valve Actuators Lubrication and Inspection." These valves are high pressure safety injection header isolation valves for reactor coolant loops 1A and 1B, and require environmental
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qualification.
The inspector verified that the lubricant specified i
by the' procedure was' qualified for this application.
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e.
Maintenance Activities Following Reactor Trip (Unit 3)
As a result of the Unit 3 reactor trip, which occurred on June 21, 1987, the licensee conducted troubleshooting and maintenance prior
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to returning the unit to service.
The inspector observed the
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following activities:
Troubleshooting efforts to determine the cause of feedwater j
control system power failure.
- Troubleshooting efforts to determine the cause of failure of flow transmitter 3FT-0341-2, which provides high pressure safety injection flow indication for reactor coolant loop 28.
During the safety injection actuation which occurred following the reactor trip, this indicator did not respond to safety injection flow.
The licensee conducted additional flow tests to verify that the flow transmitter was not working properly,
and the calibration of the transmitter was subsequently checked.
Although the transmitter appeared to respond properly at atmospheric conditions, at elevated pressures the transmitter exhibited a shift in the zero set point which explained the faulty flow indication.
The licensee subsequently replaced the faulty transmitter, and verified that the new transmitter was working properly by conducting l
additional flow tests.
This item remains open pending completion of licensee review to determine the need for additional actions (50-362/87-15-01).
No violations or deviations were identified.
6.
Engineered Safety Feature Walkdown During this report period, the inspector verified the alignment of the AC electrical distribution system and the mechanical and electrical alignment of the diesel generators associated with Unit 3.
These systems appeared to be properly aligned as required by the following procedures:
Operating Instruction 5023-2-13, Diesel Generator Operation (attachments 1 through 4)
Operator Surveillance Test S023-3-3.27.2, Weekly Electrical Dus Surveillance The Diesel Generators appeared to be well maintained and in good working order, and all alignments appeared to be proper.
No violations or deviations were identified.
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7.
-Independent Inspection a.
Outage Summary (Unit 1)
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The unit went off the grid on May 9, 1987, for a planned 41-day mid-cycle maintenance outage.
The maintenance, work included M0 VATS testing of the majority of the motor operated valves, repair of reactor coolant pumps "B" and "C", modification to the steam driven auxiliary feedwater pump piping to minimize the overspeed trip difficulties due to steam condensMion, diesel generator head replacements, and other repair and testing.
Most of these activities were inspected by a special team during June 1 - 12, 1987, with findings as discussed in Inspection Report 50-206/87-05.
Near the end of the outage, the licensee discovered insulation degradation in a number of cables spliced to the containment penetrations.
The inspection and repair work, as discussed in paragraph 7c, resulted in approximately a 10 day delay in unit restart.
i The unit entered Mode 4 on June 24 and Mode 3 on June 28.
Reactor i
criticality was achieved at 11:56 on June 30.
The inspector i
observed the approach to criticality using procedure 501-3-2, " Plant Startup from Hot Standby to Minimum Load".
On July 1, while j
attempting to synchronize to the grid, the control operator l
inadvertently adjusted the generator exciter theostat instead of the voltage regulator.
As a result, generator output voltage raised from the normal 18kv to approximately 24kv and caused a generator / turbine trip.
Since the reactor power was less than 10%
at the time, the permissive prevented a reactor trip.
Subsequent l
inspection determined that the generator, transformer and related cables were not damaged by this event.
The licensee has attributed this event to operator error.
-The inspector reviewed the procedure and interviewed the responsible operations personnel.
At the exit, the inspector emphasized the
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importance of rigorous step by step procedure usage during relatively infrequent and complicated evolutions (especially during plant start ups).
The inspector also noted that events such as this indicate a need for additional emphasis on detailed supervisory overview of plant start.
In this regard, the inspector noted that although the licensee had provided management, as well as supervisory coverage of the Unit 1 start up, this coverage was apparently not formatted to detect or prevent the error which occurred.
The licensee committed to implement corrective actions to prevent recurrence of this type of problem.
b.
Management Monitoring Program The inspector reviewed the licensee's management monitoring program to assess site management's involvement in the status of plant conditions and personnel, in particular the condition of Unit 1 prior to mode escalation from the mid cycle outage.
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The objective of this program is to provide a documented process concerning site management involvement in oversight of plant conditions and personnel performance as well as to promote teamwork and a broader understanding in the resolution of key issues.
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implemented though site directive NGS-D-005 and conducted weekly,
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according to the schedule approved by the station manager.
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results are documented in a Management Monitoring Report.
The inspector reviewed samples of the schedule and monitoring report in particular, areas which were significant to mode escalation after the Unit 1 outage.
From this review and the general condition of
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the plant, it appeared that the licensee's management control system was effectively discharging its responsibilities for continued safe operation.
c.
,P_enetration Cable Insulation Failure Near the end of the mid-cycle outage, during routine megger readings on the control rod drive mechanism (CRDM) circuits, the licensee discovered eleven circuits that failed to meet megger criteria (less than 1 Megohm) and eleven circuits were characterized as degraded (between 1 and 100 Megohms).
Further investigation revealed that the insulation breakdown occurred at the cable " pigtails" spliced to the Conax containment penetrations installed about a year ago.
The pigtails are multi-strand conductors spliced to the solid conductors of the penetration at the vendor to facilitate field splices to the multi-strand field cables.
The pigtail conductors are insulated by a thin dielectric material called "Kapton" which was qualified by Conax in accordance with NRC equipment qualification requirements.
Bundles of the Kapton insulated conductors were protected against mechanical damage by polyolefin sheathing.
The licensee sent samples of failed cable to an independent laboratory for failure mode determination.
To date, the licensee believes that the most plausible failure mode is as follows:
During installation, when the polyolefin sheathing was stripped with a knife, the Kapton insulation was cut.
Additional punctures could also be incurred from other construction and maintenance activities.
Since most of these mechanical damages were small, neither visual inspection nor electrical testing detected them at the time.
However, sometime after installation, moisture penetrated the holes.
Corrosion of the copper by the salt-laden moisture was evidenced by the discoloration (blackened areas and green patches) of the copper under the Kapton insulation outside the containment.
Corrosion of l
the copper conductor forms a solution which ultimately yields sodium hydroxide, which dissolved the Kapton insulation.
This mechanism was demonstrated in the laboratory.
The electrical failure took place after sufficient Kapton insulation deteriorated.
The licensee generated NCR S01-P-6158 to address the damaged cables found, as well as the generic implication to the other cables installed (a total of approximately 5,000 pigtails).
The licensee
,
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conducted a complete reinspection of all of the exposed Kapton insulated pigtails.
The 142 pigtails which were installed with the Dedicated Safe Shutdown System in 1986 were excluded since the pigtails are totally exlosed by fire retarding material.
Spare pigtails not used were also excluded.
A total of 107 cables were repaired.
Repairs were performed by cutting out the defective section, splicing in new cables and wrapping the repaired cables with polyolefin sheathing.
The licensee committed to evaluate long term corrective actions for all Kapton insulated cables.
This item remains open pending completion of licensee and NRR evaluations of long term environmental qualification of Kapton insulation (50-206/87-14-02).
d.
Calibration of Nuclear Instrument Startup Rate Circuits (Units 2 & 3)
The inspector examined the licensee's procedures for conducting calibration of startup rate circuits associated with the nuclear instruments on Units 2 and 3.
As recommended by the vendor's
l calibration procedures, the licensee only requires a single point l
calibration of the startup rate circuits.
In conducting this l
calibration, the licensee verifies that the internal rate circuit is l
functioning properly and verifies that the startup rate meter l
provides the proper indication of 7DPM (full scale) when the internal test signal is applied.
In addition, the licensee verifies that for a zero input, the startup rate meter reads 0 DPM.
Although this does not appear to be the case for startup rate nuclear instrument channels, standard industry practice typically requires a five point calibration check of the circuit.
The inspector requested the licensee to provide his basis for performing only a one point calibration check of the startup rate circuit.
This is an open item (50-361/87-13-01).
e.
Post Maintenance Testing The inspector reviewed the licensee's program for identifying retest requirements following maintenance activities.
In addition, the inspector discussed tne implementation of this program with the licensee.
The folicwing procedures define and implement the post maintenance testing requirements:
Maintenance Procedure 50123-I-1.7, Maintenance Order Preparation, Use and Scheduling Maintenance Procedure 50123-I-1.25, Maintenance Verification Testing General Procedure 501-XV-1.0, Post Maintenance Retest Program General Procedure 5023-XV-1.0, Post Maintenance Retest Program Operations Procedure 50123-0-21, title Equipment Status Control
,
.-
,
i The licensee's procedures provided guidance for specitying testing necessary to verify that the maintenance activity has been properly performed, and applicable procedures for demonstrating equipment operability upon completion of the maintenance activity were specified.
The maintenance planners appeared to have a good understanding of the licensee's post maintenance retest program, and the maintenance orders reviewed by the inspector appeared to include appropriate retest requirements, f.
Steam Generator Modifications (Units 2 & 3)
Prior to the first refueling outage, the steam generators on Unit 2 began to experience premature tube failure.
While the unit was shutdown for the first refueling outage, a section of one of the failed tubes was removed from the steam generator and subjected to a metallurgical analysis.
This analysis indicated that the grain l
structure in the vicinity of the tube failure was long and slender, indicating that the tube was not final annealed. The licensee i
completed a 100% tube inspection in both steam generators by using eddy current techniques, in order to identify those tubes that were
'
not properly annealed.
As a result of this eddy current inspection,
'
the licensee identified a tube wear problem associated with the bat wing supports and the inner diameter of steam generator tubes.
In order to resolve the bat wing wear problem, CE recommended that the licensee plug and stake 284 tubes per steam generator.
The licensee felt that plugging 284 tubes per steam generator was excessive, and implemented a program to plug only the most suspect tubes.
The rest of the suspect tubes would be inspected by eddy current techniques from outage to outage to identify any additional problem areas that might develop.
A similar inspection and repair program was also completed during the first refueling outage on Unit 3.
Currently, steam generator tubes have been plugged on Units 2 and 3 as follows:
Unit 2 Unit 3 Bat Wing Supports 264 253 Final Anneal
24 Other
36 Total 368 313 The inspector discussed this matter with the licensee in order to obtain the current status of steam generator tube inspection results.
The licensee stated that recent steam generator tube inspections do not indicate the need for additional tube staking and plugging at this time.
The licensee plans to continue to monitor steam generator tube wear, but does not anticipate any steam l
generator modifications will be necessary.
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g.
Adequacy of 50.59 Reviews With Regard To Safety Analysis Considerations (Units 2 & 3)
l On March 1, 1987, while Unit 3 was in mode 5, cracks were found in the bonnet of atmospheric dump valve (ADV) 3HV-8419.
The ADV was isolated and repaired during the period March 3-9 while the unit was undergoing reactor startup testing and made escalation to mode 2.
The licensee administrative 1y limited this maintenance activity to seven days and required repairs to be completed prior to unit synchronization.
The Updated Final Safety Analysis Report (UFSAR)
takes credit for the availability of the atmospheric dump valves during certain accident scenarios.
The UFSAR does not indicate that the atmospheric dump. valves will be taken out of service during power operation.
The licensee's safety evaluation does not address the effect of these maintenance activities on the safety analysis considerations presented in the UFSAR.
During the month of April, 1987, the licensee physically clamped containment isolation valve 3HV-4048 in the open position on two
!
separate occasions to perform maintenance on the hydraulic piping
associated with the valve actuator.
Valve 3HV-4048 is the main
'
feedwater isolation valve (MFIV) for steam generator E088.
The UFSAR takes credit in the accident analysis for the operability of 3HV-4048 during a main steam line break inside containment.
The licensee's safety evaluation did not address the effect of this maintenance activity on the accident analysis presented in the UFSAR.
Section 10 CFR 50.59 of the NRC Regulations states that the licensee may make changes in the facility as described in the Safety Analysis Report without prior Commission approval, if the change does not involve an unreviewed safety question.
Section 50.59 states that an i
unreviewed safety quertion exists if the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety, previously evaluated in the Safety Analysis Report, may be increased; or if a possibility for an accident or malfunction of a different type than any evaluated previously in the Safety Analysis Report may be created.
Insofar as the licensee's safety evaluations do not address the safety analyses as presented in the UFSAR, these maintenance activities may have involved an unreviewed safety question.
This item is unresolved pending additional review (50-362/87 ~15-02).
h.
Safety System Availability (Units 1 and 2)
The inspector reviewed the licensee's technical specification action statement tracking system (LC0AR) for Units 1 and 2 during the first quarter of 1987.
The primary purpose of this review was to determine the potential usefulness of the LC0AR system as a performance indicator in the area of safety system availability.
In this regard, the inspector noted that since the LC0AR system tracks the time for which important safety and accident mitigating equipment is unavailable, and for what reasons, this system should
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be.us'eful as a relative indicator of the extent to which 'this
'
L equipment-is'not available to' serve its: intended purposes.
,
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-Some of the' questions which.this type of performance indicator could
'
address' include:
For what reasons are safety equipment being taken out offservice (failure, maintenance,. surveillance)? To what extent.
is: equipment which^is of.the most'importance, from a risk
' perspective,Ltaken.out'of. service and why? How long'is equipment unavailable for different reasons? 1To what extent are several-
'
components in the same train or-in ~ redundant trains being removed:
,
from-service simultaneously (e.g. what.is the integrated impact'on plant safety)?
The preliminary results'of this review'are included as an enclosure to this inspection report.
The inspector requested the licensee to
. review these cata and identify what actions the licensee considers
,
warranted in' regard to utilizing LC0AR data to develop a useful safety system availability performance indicator. This is an open item (50-361/87-13-02).
8.
Review of Licensee Event Reports Through direct observations, discussion with: licensee personnel, or review of the records, the following Licensee Event Reports'(LERs) were closed:
,
Unit 2 2-86-30 CPC DC Power Supply Failure This LER reported that CPC DC power supply failures do not initiate an RPS channel trip or the main control board CPC failure annunciator.
The licensee is currently monitoring the
"CPC Fail"' lights hourly to ensure that additional power supply failures are promptly detected..The licensee' plans to install a design change to correct this problem upon resource availability.
Until the design change has been implemented, the licensee will continue to monitor all "CPC Fail" lights.
Unit 3 3-87-05 Fuel Handling Isolation System Spurious Actuation 9.
Follow-Up of Previously Identified Items
'a.
(Closed) Open Item'(50-206/87-03-01) Excessive Corrosion Buildup In #2 Battery Cell #54 During the previous inspection, the inspector noted what apptared to be excessive buildup of corrosion products at the bottom of the battery case and on some of the plates of battery cell #54.
The licensee' initiated and dispositioned an NCR stating that the observed condition was satisfactory and no action was necessar _ _ - - _
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m.;
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During this inspection, while observing the #2 battery discharge
test,Ethe inspector specifically reviewed'the voltage of cell #54 during the test.
The voltage drop appeared to be normal-by comparing with the rest of the cells as well as related
. specifications. This item is closed.
. b.
(Closed)'Open Item (50-206/87-03-02) NIS 1204 Intermediate Range Nuclear Channel During a previous inspection, NIS 1204 failed low following a reactor trip, due to compensating voltage being out of adjustment.
i probably as a result of detector degradation.
During this inspection period, the detector was replaced..Also, the operating procedure for plant startup, 501-3-2 was revised to include a step to verify that NIS' intermediate range compensating voltage.is properly adjusted. lThis item is closed.
c.
(Closed) Unresolved Item (50-362/87-10-01) Improper Bypass
'
of Plant Safety Function (Unit 3)
This item was unresolved pending additional. review of the safety significance associated with placing a CPC' channel in the bypass condition following a rod drop.
Although it is not good practice to place a CPC channel'in the bypass condition after it has tripped due
.to a. dropped rod, bypassing the CPC channel would not prevent'the reactor from tripping due to multiple rod drops which resulted from a' credible single failure event.
Such-multiple rod drops can only
' occur within a given subgroup, and in that case the CEACs would generate penalty factors to all channels of the CPCs sufficient to
.
cause a reactor trip. Although multiple rod drops due to multiple single failure events are not specifically protected against, significant reactor power tilts that result from such occurrences would be protected for by the variable over power trip function.
l The licensee agrees that a CPC channel should not be bypassed if it has tripped due to a drop rod, and procedure S023-V-2.11 titled,
" Reactor Protection 56A Alarm Response Procedure," has been changed to so state.
This item is closed.
d.
(0 pen) Enforcement Item (50-362/87-05-02) Inadequate Housekeeping and Work Practices Inspection Reports 50-206/87-03, 50-361/87-04, and 50-362/87-05 identified this item as an enforcement issue which was still being evaluated.
This issue is cited as an apparent violation in the Notice of Violation which accompanies this Inspection Report.
10.
Exit Meeting On July 6, 1987 an exit meeting was conducted with the licensee representatives identified in Paragraph 1.
The inspectors summarized the inspection scope and findings as described in this report.
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DESIGlit.TED ORIGINAL Certified By
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b ENCLOSURE
l SAFETY SYSTEM AVAILABILITY TABLES
(Discussed in Paragraph 7.h)
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HOURS IN M01A1'l (IST 031987h 2090 a1 X-SYSTEM FAIL 1JE l
-
MAINT l
SUIN
SYSTEM TOTAL CAUSE % ' HOURS SYSTDI %l
!.
CAUSE % HlutS SYSTEM % !
CAUSE % HOURS SYSTEM %
!
HWRS STS % RCBE 1 1
'
AFW 0. 3%
13.5% !
5.7%.
86. 5% 1
~
v-0. 0%
0.Os i 104.
1. 61 - 5.0%
-
AMS 0. 0%
0.0%' !
0. 0%
0. 0% :
0. 81 6 100.0%
!
0.1%
0.3%
CIS.
0. 0%
' O.05
0. 0%
0.0%
.
Od%
1. 100,0%
!
.0%
. Os (
DSD O' 1% J
11.8%
!.
1. 9%
86.2% !
0. 0%
0.0%
!
0.5%
1. 6%
I
.
FPS 75.7% - 3159 87.8% 1 3. 0%.
1. 3% ~ ;
49.8%
393 10.9% !
3600 55.4% 172.2%
FWS 0. 0%
0. 0% !
1. 0%
16 100.0%
0. 0%
0'
O. 0%
i
0.2%
0. 8%
\\'
. MSS 0.0% a 0-0. 0% i 1. 9%
30 100.0% 1 0. 0%
0. 0% !
0.5%
1. 4%
MVS 0. 0%
0.0%
t-0. 05
0.0%
l 10.35
100.0% !
1. 2%
3. 9%
NIS 0. 4%
15 '100.0%
i:
0. 0%
0.0% 1 0.%
0. 0%
15 0. 2%
0. 7%
'
PE 1.7%
19.0%
i 19.3%
306 81.0% ;
0.0%
0. 0%
i 378 5. 8% 18.1%
PMS 0.0%
0.0% :
1.5%
24 100.01 0. 0%
0.0%
!
~ 24 0.4%
1.1%
l RMS'
20.8%
855 40.0%. I 62.8%
997 4.7% !
36.0%
2B4 - 13.3%
2136 32.9% 102.2%
SIS 0. 0%
0.
0.0% !
0,0%
0. 0%
.
1.ps 14 100.0% :
0. 25 0. 7%
.VAC
. 0. 0%
0.0%
!
' 3. 0%
47 100.0% !
0.3
0.0%
f
0.7%
2. 2%
VCC 0.0%-
0.
0. 0% !
0. 0%
0.0%
!
1.01 10 100.05 i
0.2%
0. 5%
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63.41 4119'
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24.4% 1566
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12.1%
789 i
64 %
,
BtELIRINRRY CONClif510NS i
,
_
1. At fin Protection and ihdiation Honitoring systens are the major cause of safety systes unavaila pth.88% of the total outage time.
,
2. The Post becident Sampling systes nas out of service for 18% of the tine t'e plant was operating,
. 3. The Auxiliary Feedwater systw was the acddent uitigating system with the highest unavailability (
,
.
4.
Equipaent failure was the mest frigomt cause of r,afety systes unavailability (63%).
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SAFETY SYSTEM LNNRILABILITY SlNIARY W90)
(AIT 2 HOURS IN MODE 1 11ST OTR 1987h 2076 BTE%
FAILURE _
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SYSTEM TOTAL i
CR1SE 1 HOURS cSYSTEM %'
CAUSE % HOURS SYSTEM 1 :
CAUSE 1 HOURS SYSTEM $
l HOURS SYS % EBE 1 1
-
0.0%
0.0%
4. 3%
104 100.0% :
0.0%
0.0%
IM 2. 25 5.0%
B 21.7%
21.9% !
7. 9%
190 49.0%
5. 9%
113 29.1% :
388 8. 2%
18.7%
B-4.3%
32.7% :-
1.5%
67.3%
0.0%
0. 0% !
$2 1.1%
2. 5%
$
0. 3%
33.3% !
0.15
66.7% !
0.0%
0.0%
!
0.15 0.15 B
0,05-
0.0%
'!
0. 25
46.2% -
0. 4%.
53.8% ;
0. 3%
0. 65 D
0. 0%
EPR. t 0.05
ERR I
0. 0%
ERR
0. 0%
0. 0%
B 0.05
0. 0% 1 4.8%-
116 82.9% !
1. 3% -
17.1%
140 3. 0%
6.75 3..
g 0.0%
ERR
!
0. 0%
ERR 0. 0%
ERR l
0. 0%
0. 0%
L 8.7%
34 100.0% !
0. 0%
0.0% !
. 0.05
0. 0% 1
' 34 0. 7% -
1. 6% '
F 0.05
0. 0% :
7. 55 180 100.0% !
0. 0%
0. 0%
180 3. 85 8. 7%
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4.1%
!!.9% 1 0.25
3.7% i 6. 05 114 B4.4% !
135 2. 95 6. 55
0.05'
ERR I
0. 05
ERR I
0. 0%
ERR
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O-0. 0%
0.0%
l 0.0%
0.0% 1 0. 0%
0.0%
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2. 25 42 100.05 l
0. 95 2.05 0.0%
0. 05 1 0. 15
1.5%
7. 05 133 98.5% !
135 2.9%
6.5%
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6. 6%
26 100.0% !
0.0%
0. 0%
0.05
0. 0% :
0.6%
1. 35 21.5%
B4 2. 7% 1 68.9% 1658 52.5%
i 74.1% 1416 44.8% !
3158 67.1% 152.15
'
'f 0. 05
0. 0% i 0. 15 2 100.0% i 0. 0%
0. 0%
. 05 0.1%
0. 05
0.05
0. 35
80.0% 1 0.1%
20.0% !
0. 2%
0. 5%
0.0%
0. 05 1 0. 2%
5 100.0% 1 0.0%
0.0%
!
0.1%
0. 25 9.25'
32.1% !
0. 75
15.25 1 3.1%
52.7% !
!!2 2. 45 5.45
' 0. 3%
!
4. 8% 1 0. 85
90.5% 1 0.1%
4. 8% i
0.4%
!. 05 0.05
ERR I
0. 0%
ERR
0. 0%
ERR
0. 05 0. 0%
E3.3%
61.5% i 2.4%
38.5% !
0. 0%
0. 0% !
148 3.1%
7. !$
F2 B. 3%
391
!
51.1% 2406
40.6% 1911
4708 PRELIMIERY CONCLUS! INS
_ - -
The Radittien Monitoring systes was the ma,Jor cause of safety systes unavailability with 67% of the t The Plint Protective and Nuclear Instrumentation systems were the accident mitigating systems 3stly due to surveillance.
,
2]intemnce was the most frequent cause of safety systes unavailability (515), mostly involving Ra Statal DC power systems mere umvailable 75 of the time, due to failure or natntenance.
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AUX FED ETER 1 CCS CONTAlf4ENT COOLIE
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CONTAllMENT ISOLATION (, 41 t,
.CRS QNTAlteENT SPRAY DSD ED!CATED SEJ1DOWN FPS FIRE PROTECTION
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FWS FEED WATER
'i MSS MIN STEAM MSS'-
MAIN STEAM MVS WNTILAT!W SYSTD6
$
PAS.
POST ACCIENT SA8 FLING
RCS REACTOR COOLANT-RMS.
RADIAT10N PUNITORING SDC'.
SHJTION COOLING SIS SAFETY INJECT 1 W I
SWC SALT WATER COOLIE
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TOK!C MS ISCLATIN UCC -
VCLUE CONTRRJCmRSIN
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TOTAL'00T TIME: 411 7
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FWB G-10 STM AFW 3. 4.1,2.4.3 i F.
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" 1187 21. 03feb 8
. 03feb 18 10.
AFW A ~
610S ELEE AFWP 3.4.3,3,4.1 1-f I
/187L21. 054rb'i 9 L 054eb 13 4-
' DSD CV956-DSD S MPt.E J. 20 1 F
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"I 87) 40 ' ' 02-Alr 30
.04-Mar 7
FPS.
10E Sj 21 3.14 1 F
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148. FPS IA201 DCSWQRN/F-77 3.14.VI.A 1 F
'1 87 14 16-Jan' !.
27-Jan 14
.277-FPS F-79 -
STQ XF4 41 SPRAY DET.
3.14 VI.A 1 F 1.87 17.: '22-Jan 4* 03-Feb 10 289 FPS F71.[
' FIRE ZDNE 7 (NEE RM)
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F
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1 87 26 - 114eb 8 05%e 13 533 FPS
ZOE 5 DET 3.14.VI.A 1 F
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~1 87 22 - 06-Feb 10 05-Mar 9 647' FPS j
LO FDAM SYS AND DET 3.14 III,IV 1 F
- 187 c 9 12-Jan 11.
04 * r.7 1220 FPS F-77,78'
LUDEDIL/D U FEED AREA 3.14 1 F
.
E 1 87.33
^ 224eb 18 23 4eb 9
NIS THT,G1.E 7 G ON 3.11 1 F
' 1. 87 J/ ' ' 25feb 15 28-Feb 15 72. PAS B0i40H ETER 3.20.A 1 F 1 87' 15' '16-Jan 10 22-Jan 14 -
148 RMS RTh1257 CON 1'RADIA7 ION HIGH 3.5.10 1 F
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. START CLOSE DUT-
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DATE.' W.
f0URS SYS N COMPWENT NAPE LCO e E
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D 5 L 1 B7. '49 iO-Nr 16 11-Nr 4-
AFW B.
6-10 STM AFWP 3.4.1,3.4.3 3 M
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AFW B 6-10-STM AFWP 3.4.1,3.4.31 M-
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DSD D/6 3.20 1 M j
' :: 87 2 - 06-Jan 13 07-Jan 14
DSD F66 DIESEL GEN-3.14 1.
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! 87 4 07-Jan 20 -
09-Jan 20 48-FPS FIRE SYS DIST P!P!te 3.14.A.1.e
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! 87 L39 27-Feb 9 27-Feb 15
'6 Fl6 FEED /STM FuGW MISMATCH 3.5.1 1 M
.! 87. 31
'19-Feb 9 19-Feb 19
FWS FM-456 3.5.1 1 M 1 87 ' 50-
!!-b r 12 12-Mar 18
' 30 MSS LT-3400A 3.5.7.1 3 M 1 87 41-'03-Nr 5 07-Mar 15 106 PAS B0EN ETER 3.20 1 M ci.87-6-08-Jan11.;
16-Jan 19 -
200 PAS BORW METER 3.20 1 M 187 lo 14-Jan13 15-Jan 13
PRS RPI FOR ROD K-6 3.5.4 1 M
-
'l 87-29'
184eb - 9 21-Feb 17
RMS R-1256 M IN STEAM 3.5.10.B 1 M 187?24-10-Feb'9 16-feb 17 152 RMS RT-1256 MIN STEAM 3.5.10 1 M 1 B7. 38 26-Feb 7 04-Nr 19 156 RMS R-1219 STACK NIELE BAS 3.5.9 1 M
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1 87 25 10-Feb 8 21-Feb 17 273 StS-R-1235 AREA /PRD1 S$ MON 3.5.10 1 M-1 87 35 23-Feb 22 09-Mar 22 336 RMS R-1218 LIQ RE WASTE 3.5. B 1 M 1 87 8 12-Jan 8 14-Jan 7
VAC B D/6 82 3.7.1.R.2 1-M
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MlURS SYS N COMPWENT NAE LCO 8 E
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?! 8748. - OHlar 8 OMr.14
MSB CONT H2 MON 3.6.3 1 S
_-
__-
_ _ _ _ _ _ _ _
l_ 1 87 36 ~24-Feb14 24-Feb 15
CIS A-SEDLENCER 81 3.5.5 1 S
! 1 87. 18'
28-Jan 9 30-Jan 14
1 S 1 87 ? 1r - !$-Jan 11 21-Jan14 147 FPS 480V 2 HAL94 SYS 3.14.IV.8 1 S
- 1 87 7 08-Jan 13 16-Jan 14 -
193 FPS 480V 2 FIRE DETECTION 3.14 1 S
.
l 1.B7. 3, 06-Jan 11 09-Jan 20
MVS MVS-A-33 3.12
S 187 28' 17-Feb 9 17-Feb 11'
2.
MS RT-1255 3.5.10 '
1 S l'87 46 07-Mar 11 07-Mar 15
RMS R-1212 3.5.5 1 S 1 87. 45 06-Mar 12 06-Mar 16
RS R-1212 3.5.5 l'
S 1 874 47
09-Mar 8 11-Mar 2
RMS R-1217
,
3.5.8 1 S 1 87 42 03-Mar 8-
- 05-Mar 11
RMS R-1258 3.5.10 1 S 1 87, 34 23-Feb 8.
26-feb 7
RMS R-2101 1 87_ 30f _'18-Feb 17.
23-Feb 7 110- RMS R-2100 3.5.8 1.
S 1.87r43 03-Mar 8 03-Mar 22
SIS RWST LEVEL IND 3.5.6 1 S 3.5.8 1 S 1 87. 22 - 04-Feb 10 04-Feb 20 10 -VCC B 6-8B SD CHAR 6ING PlMP 3.3.1
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C TDTAL DUT TIME: ' 163 R
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I
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D'S d. YD 6 -
DeTE HR -
DATE.' }R.
M)LRS SYS N COMPINENT NAE LCO 8 E
E.
,. _ _
---
- 2 87 84'
27-Feb 6 27-Feb 12 S
AMS TE011141 TC RTD 3.3.3.5 1 F
,
l 2 87 23 - 17-Jan 22 19-Jan~.9-35. AfE B QSPDS CH B 3.3.3.6 1 F 2 87' 31-25-Jan 15 27-Jan 11
3.3.3.6
F-
-
2 87~ 66 16-Feb 8:
16-Feb'9
.1 CIS
' WO506
. 3.6.3 1 F 2 87 -46'
05-F eb 23 -
06-Feb !!
12 ' MSS PSVB407 S/6 SAFETIES 3. 7.1.1 '-
3 F 2 87 44 ~ 05-Feb 16 -
06-Feb 14
MSS PSV88.07 S/6 SAFETIES 3.7.1.1
.1 F
,2 87 22 :16-Jan 18-16-Jan 23 5'
NIS AB CEAC2 CEAC SENSOR 20 3.3.1 1 F 2 87:. 3 05-Jan 7 05-Jan 18
. 11 NIS B CPC Of a 3.3.1 1-F 2 87-: 47 05-feb - 8 06-Feb 10
RCS-RCS ETIVITY 3.4.7 3'
F-2 87 34 27-Jan 18 27-Jan19-1-
VAC B A06 2A06 FEED FROM 3A06 3. 8.1.1 1-F
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- - -. --
. - -. - - -
-
- - - - - - - - - - -
- - - - -
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LCOAR LOG T
C TOTR. DilT TIME: 325-R M A A
- LCDAR 4 ~
START CLOSE DUT I
,
0- U D$
' U YR #
HXJRS SYS N 00@(NENT fpE LCD #
'E E.
-
2 87 18 15 4an 6 15-Jan 10
F W AB SMJBDER 3.7.6 1 M 2'87 43 ' 054eb 2 054eb 10
AFW A P141 FWP, W4731, 4763 3. 7.1. 2 1 M 2 87' 86 ' 02-Mar 12 02-Aar 21.
FW AB P140 FW TR A/B 3. 7.1.2 1 M 2 87'89 03-Mar 8 03-Mar 22
AFW B P504'
F WP TR B 3. 7.1. 2 1 M 2 87.11-12-Jan 4 15-Jan 1
3. 7.1. 2 1 M 2 87 70 '184eb 8 18-Feb 15
AE PT0353Al CMT WR PESS 3.3.3.6 1 n 2 87 '41 04feb 8 04-Feb16
AMS B L4918 QSPDS CH B 3.3.3.5 1 M
- 2 87 38-02-Feb 6 02-Feb 22
AE E370/371 3.9.12
-N J 2 87 50 06-Feb 8 07-Feb 16
M-
~ 2. 87 35 -28-Jan 8 02feb 15 127 AMS B ME371 FHB PACU TR B
'3.9.12 1 M
'2 873 40 05-Feb 13 05-Feb 14
CIS W4052 3.6.3 3 M
.2 87 55 06-Feb 20 06feb 21
CIS W4051 3.6.3 2M L2 87. 74 21-Feb 12 21-Feb 18
CRS HV9367 WlE INSP 3.6.2.1 1 M 2 87 61 11-Feb 13 11-Feb 18
.$
NIS A LO91 CPC G A 3.3.1 1 M
- 2 87 57 09-Feb 20 09-Feb 22
, 2 87 '21'
16-Jan 1 16-Jan 3
SDC W9336 SDC SUCT ISOL 3.6.3 1 M
- 287 83 26-Feb 7 26-Feb 15
SIS A W9324 HPS1 ISOL TR A 3.5.2 1 M 2 87 56. 06-Feb 21 08-Feb 22
SE A D36 SWC TR A 3.7.10 1 M i
2 87 8 DB4an 20 094an : 0
SWC A Pil2 SWC PMP 112 TR A 3.7.4 1 M 2 87 63 12feb 17 12-Feb 18
VE B M06 3A06 BKR 18 3.8.1.1 1 M
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TOTAL DUT TIE: 401 R
M A A
0 0 LCOAR I START.
CLOSE DUT
'I D S 9 VR 8
. DATE HR-DATE. HR.
HOURS SYS N COWCNENT NAE LCD #
E E. '
9 87 ~ 71 19-Feb 6 19-Feb 8
AMS B L396 POST LOCA H2 MON B 3.6.4.1 1 S
% 87 28 ' 21-Jan 8 21-Jan 13
AMS A ME370 FHB PACU TR A 3.9.12 1 S h
8 87 -1 02-Jan 10
.02-Jan20
3.3.3.6 1 S
!
%87'42. 05feb 6 05-Feb 17
AE A L3%
POST LDCA HS poi A 3.6.3 1 S f 87 42. 05-Feb 6 054eb 17
AMS A L396 PDST LOCA HS MON A 3.6.4.1 1 S
! 87 24 19-Jan B 22-Jan 10
AE B L3%
POST LOCA H2 MON B 3.6.4.1 1 S
! 87.
5-06-Jan 13 06-Jan 14
CRS P021 SPRRY OtEX ADD 3.6.2.2.B 1 S
? 87 80 23feb 23 24-Feb 5
CRS P020 10 DINE EMVAL 3.6.2.2 1 S
! 87 73 20feb 8 2bfeb 11
NIS 2 CEAC2 3.3.1 1 S
! 87, 96. 05-Mar 8 05-Mar 11
NIS C JYK0993 EXCORE CH C 3.3.1 1 S
!87'33 27-Jan 11 27-Jan 14.
NIS C JYK0993 EXCORE Di C 3.3.1 1 S
? B7 '32 27-Jan 7 27-Jan 10
NIS A JYK0991 EXCORE CH A 3.3.1 1 S 2 87-68 17feb 8 174eb 11
NIS AB CEAC1 3.3.1 1 S
? 87 67-16 feb 8 16feb 12
NIS D LO91 CPC Di D 3.3.1 1 S
? 87 17 14-Jan 14 14-Jan 18
?87 62 - 12-Feb 8 124eb 13
! 87 39 ' 03feb 6 034eb 11
NIS B JYK0992 EXCORE CH B 3.3.1 1 S
! 87 65 13-Feb 13 13-Feb 19
NIS C LO91 CPC Di C 3.3.1 1 S
? 87 4 05-Jan 9 05-Jan 18
NIS B JYK0992 EXCDE CH B 3.3.1 1 S
' 87 25 - 19-Jan 13 19-Jan 23
NIS AB CEACI CEAC 3.3.1 1 S
9.
09-Jan 8 09-Jan 20
NIS A LO91 CPC Of A 3.3.1 1 S
)
87 13 12-Jan 20 13-Jan 14
NIS B LO91 CPC CH B 3. 3.1 1 S
' 87 29 22-Jan 10 23-Jan 20
NIS A LO91 CPC 04 A 3.3.1 1 S 87 6 07-Jan 9 07-Jan 11
PE L194 PMP VIBRA 11CN MON 3.3.3.10 1 S 87~ 49 06feb 6 06-Feb 9
PMS L194 PMP V!BilATION MON 3.3.3.10 3 S 87 54 064eb 23 06feb 24
PPS D LO32D PPS CH D 3.3.1 2 S 87 53 06-Feb 22 064eb 23
PPS C LO32C PPS Di C 3.3.1 2 S 87 51 06feb 18 06-Feb20
PPS A LO32A PPS Di A 3.3.1 2 S 87 52 OS-Feb19'
064eb 22
PPS B LO320 PPS Di B 3.3.1 2 S 87 16 14-Jan 7 14-Jan 11
PPS A LO32A PPS CH A 3.3.1 1 S 87 27 21-Jan 6 21-Jan 12
PPS PPS LOGIC MRTall 3.3.1 1 S 87 7 08-Jan 8 08-Jan 14
PPS C LO32 PPS CH C 3.3.1 1 5 87 64 13-Feb 6 13-Feb 12
PPS D LO32 PPS CH D 3.3.1 1 S 87 60 11feb 7 11-Feb14
PPS A LO32A PPS Of A 3.3.1 1 S
@7 40 ' 04feb 7 044eb 14
PPS C LO32C PPS Of C 3. 3.1 1 S G7 12 12-Jan 7 12-Jan 15
@? 19 15-Jan 7 15-Jan15
PPS B LO32 PPS CH B 3.3.1 1 S G7 26 20-Jan 7 2& Jan 15
PPS PPS LOGIC MATRIX 3.3.1 1 S
@7 15 13-Jan 21 14-Jan15
PPS P!3202B COND VAC LO42 3.3.3.5 1 S G7 14 13-Jan 21 14-Jan 15
PPS P!3599B-CDND VAC LO42 3.3.3.5 1 $
@7 69 184eb 6 19feb 12
PPS MATR11 3.3.1 1 S
@7 37 30-Jan'0 3&Jan 9
RMS FT3772 BPS EUI SUMP DISCH 3.3.3.8 1 S
@7 81 24feb 8 24-Feb 18
RMS FT40'5 S/S BLDN FLOW 3.3.3.8 i S G7 72 19 feb 8 19feb 10
SIS B PO!8 HPS! TR B 3.5.2 1 S
,
D
._
g-7 I-T F bh W
-
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,
LCDAR LOG T
C i
TOTAL OtR TIME: 64 %
R M A A
0 U LC03 9 START CLOSE DlR I
D S U YR #
DATE HR DATE. FR.
HOURS SYS N COMPCNENT NAE LCO 8 E
E.
_
_.
_.
.-
! 87 32'
21-Feb 6 21feb 10
AFW B 6-10 STM AFWP 3.4.1,3.4.3 1 F 1 87 21 03-Feb 8 03feb 18
__AFW A_
BIOS ELEC AFWP 3.4.3,3.4.1 1 F 1 87:21 0Ffeb 9 05-Feb 13
DSD CV956 DSD SAMPLE 3.20 1 F 187 17 22-Jan 9 03feb 10 289 FTS F77 FIRE ZCDE 7 (ENS RM)
3.14.B.4
F'
-! B7 22 06feb 10 05-br 9 647 FPS LO FDAM SYS AND DET 3.14 III,IV 1 F 11 87 40 02-Mar 10 04-N r 7
FPS ZDE 5-21 3.14 1 F 1 87 12 15-Jan 10 21-Jan 14 148 FPS XA201 DC SW6R RM / F-77 3.14. VI. A 1 F 1 87 9 12-Jan 11 04 * r 7 1220 FPS F-77,78 LUBEDIL/CHENTED AREA 3.14 1 F i
i
! 87 26
!!-Feb 8 05-Mar 13 533 FPS ZOE 5 DET 3.14.VI.A 1 F 1 87 14 16-Jan 1-27-Jan 14 277 FPS _
F-79 STA IFMR #1 SPRAY DET.
3.14.VI.A 1 F 1 87 33 22-Feb 18 23feb 9
NIS THIMBLE 7 CADM 3.11 1 F 187 37 25feb 15 28-Feb 15
PAS BORON METER 3,20.A 1 F 1 87 --5 08-Jan 4 06-Feb 15 707 RMS R-1221 STACK 10 DINE 3.5.9 1 F 1 87 15 16-Jan 10 22-Jan 14 148 RMS RT-1257 CGIT RADIATION HIGH 3.5.10 1 F 1 87 27 17-Feb 8 20-Feb 14
CFW B Fr10 STM AFWP 3.4.1,3,4.3 1 M
! 87 49 10*r 16 11%r 4 12 _ AFW B 6-10 STM AFWP 3.4.1,3.4.3 3 M 1 87 16 - _ 23-Jan 8 23-Jan 13
DSD D/6 3.20 1 M i 87 2
& Jan 13 07-Jan 14
DSD F65 DIESEL BEN 3.14 1 M 1 87 4 07-Jan 20 09-Jan 20-
FPS FIRE SYS DIST PIPITS 3.14.A.1.e 1 M 187 31 19-Feb 9 19feb 19
FWS FM-456 3. 5.1 1 M 1 87 39 27feb 9 27-Feb15
FWS FEED /STM FLOW MISMATCH 3.5.1 1 M j
1 87 50 11-Mar 12 12-Mar 18
MSS LT-34004 3.5.7.1 3 M 1 87. 6 08-Jan 11 16-Jan19 200 PAS BORON PETIR 3.20 1 M 187 41 03-Nr 5 07 + ar 15 106 PAS BORON METER 3.20 1 M 1 87 10 14-Jan 13 15-Jan 13
PMS RPI FOR RCD K-6 3.5.4 1 M 1 87' 35 23-Feb 22 09-Nr 22 336 RMS R-1218 L10 RAD WASTE 3.5.8 i M 1 87 29 18-Feb 9 21-Feb 17
RMS R-1256 MAIN STEAM 3.5.10.B 1 M 1 87 24 10-Feb 9 16-Feb17 152 RMS RT-1256 MAIN STEAM 3.5.10 1 M 1 87 25 10-Feb 8 -
21-Feb 37 273 MS R-1235 AREA /Pl0 E SS MON 3.5.10 1 M-1 87 38 26feb 7 04 * r 19 156 __ _ RMS R-1219 STACK NOB 1I GAS 3.5.9 1 M i 87 8 12-Jan 8 14-Jan 7
VAC B D/6 42 3.7.1.A.2 1 M 1 87 48 09-Mar 8 09-N r 14
AMS B CONT H2 MON 3.6.3 1 S
'1 87 36 24-Feb 14 24-Feb 15
_CIS A SE(UDER #1 3.5.5 1 S 1 87 7 08-Jan 13 16-Jan 14 193 FPS 480V RM FIRE DETECTION 3.14 1 S 1 87 11 15-Jan 11 21-Jan 14 147 FPS 480V RM HALON SYS 3.14,IV.8 1 S 1 87 18 28-Jan 9 30-Jan 14
S 1 87 3 06-Jan !!
09-Jan 20
MVS MVS4-33 3.12 1 S 167 47 09-Nr 8 11-Mar 2
RMS R-1217 3. 5. B 1 S 1 87 28 17-Feb 9
- 17feb 11
RMS RT-1255 3.5.10 1 5 1 87 46 07-N r 11 07-Mar 15
RMS R-1212 3.5.5 1 S
.1 87 42 03-Mar 8 05-Mar 11
MS R-1258 3.5.10 1 S 1 87 30 18-Feb 17 23-Feb 7 110 RMS R-2100 3.5.8 1 S
! 87 45
& m r 12 06-Mar 16
MS R-1212 3.55 1 S 187 34 23-Feb 8 26 4eb 7
.ftf_,
R-2101 3.5.8 1 S 1 87 43 03-Mar 8 03-Mar 22
SIS RWST LEVEL IND 3.56 1 S I 87 22 04feb 10 04feb 20
VCC B G-88 SD CHAR 61N6 PUMP 3.3.1 1 S j
e i
_
. - -
---. - _ _
_
-
-
. - -
-
,
LC0AR LOG T
C TOTAL Olli TIES 64 %
R M A A
0 0 00-START CLOSE OLIT I
D 5-G #
DATE HR DATE.
HR.'
WURS SYS N COMPINENT NAE LCD 8 E
E.
F 84 27-Feb 6
.274 eb 12
MS TE011141 TC RTD 3.3.3.5 1 F F'23 17-Jan 22 19-Jan 9
AMS B DSPDS O B 3.3.3.6 1 F F 31 25-Jan 15-27-Jan 11
,,mS_,,,
PIl023A2 E088 WR PRES 3.3.3.6 1 F 17 66 164 eb 8 16-Feb 9
CIS WO508 m T LES SAMPLE 3.6.3 1 F F 46. 05feb 23 06-Feb 11 12'
MSS PSV8407 S/S SAFETIES 3.7.1.1
F-
@ 44 05-Feb 16 06-Feb 14 22, MSS _,,
PSV8407 S/S SAFETIES 3.7.1.1 1 F F 3 05-Jan 7 05-Jan 18
NIS B CPC CH B 3.3.1 1 F F 22 16-Jan 18 16-Jan 23
NIS AB CEAC2 EAC SENSOR 20 3.3.1 1 F F. 47 05-Feb 8 06-Feb 10
RCS RCS ACTIVITY 3.4.7 3 F 7 34 27-Jan 18 27-Jan 19
VAC B A06 2006 FEED FROM 3A06 3.8.1.1 1 F F 18 15-Jan 6 1FJan 10
W W AB.
SNLBBER 3.7.6 1 M F 89 03-Mar 8 0341ar 22
AFW B P504 AFWP TR B 3. 7.1. 2 1 M P 86 02-Mar 12 02-Mar 21
AFW AB P140 AFWP TR A/B 3. 7.1.2 1 M P ' 11 12-Jan 4 15-Jan 1
AFW AB P140 AFW PMP 1R A/B 3.7.1.2 1 M P 43 05feb 2 0Ffeb 10
AFW A P141 AFWP, W4731, 4763 3. 7.1. 2 1 M j
P 50 06feb 8 07-Feb 16
AMS A L491A QSPDS CH A 3.3.3.6
M'
? 70 18-Feb 8 184eb 15
AMS PT0353Al CNKT WR PRESS 3.3.3.6 i M
? 35 28-Jan 8 02feb 15 127 AMS B ME371 FHB PACU TR B 3.9.12 1 M
? 38 02-Feb 6 02-Feb 22
MS E370/371 3.9.12 1 M P 41 04-Feb 8 04-Feb 16
AMS B-L491B QSPDS CH B 3.3.3.6 1 M 7 55 06feb 20 06feb 21
CIS W4051 3.6.3 2 M 7 43 05-Feb 13 05-Feb 14
CIS W4052 3.6.3 3 M
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21feb 12 21-Feb 18
CRT~
W9367 WIRE INSP 3.6.2.1 1 M
) 61 11-Feb 13 114eb 18
~ IS A LO91 CPC CH A 3.3.1 1 M N
'
09feb 20 09-Feb 22
16-an 1 16-Jan 3 2 -SDC HV9336 SDC SUCT ISOL 3.6.3 1 M
'
26-Feb 7 26 feb 15
S!S A HV9324 HPSI IS(1. TR A 3.5.2 1 M
%
084 eb 21 08feb 22
SWC A E336 SWC TR A 3.7.10 1 M-8 08-Jan 20 09-Jan 0
SWC A P112 SWC PMP 112 TR A 3.7.4 1 M
12feb 17 12feb 18
VAC B 3A06 3A06 BKR 18 3.8.1.1 1 M
21-Jan 8 21-Jan 13
MS A ME370 FHB PACU 1R A 3.9.12 1 S i
05feb 6 05-Feb 17
AMS A L3%
POST LDCA HS MON A 3.6.3 1 S
'
02-Jan 10 02-Jan 20
AMS A L491A DSPDS CH A 3.3.3.6 1 S
19-Jan 8 22-Jan10
AMS B L3%
POST LOCA H2 MON B 3.6.4.1 1 S
0542b 6 05feb 17
MS A L396 POST LOCA HS O N A 3.6.4.1 1 S
19-Feb 6 19feb 8.
AMS B L396 POST LOCA H2 MON B 3.6.4.1 1 S
.
06-Jan 13 06-Jan 14
CRS 9021 SPRAY CHEM ADD 3.6.2.2.B 1 S
23feb 23 24feb 5
CRS P020 10 DINE REMOVAL 3.6.2.2 1 5
20-Feb 8 20feb !!
NIS AB CEAC2 3.3.1 1 S
'
22-Jan 10 23-Jan 20
12feb 8 '
12f eb 13
09-Jan B 09-Jan 20
17-Feb 8 174eb !!
NIS AB CEAC1 3.3.1 1 S
13-Feb13 13-Feb 19
27-Jan 11 27-Jan 14
NIS C J"K0993 EXCORE CH C 3.3.1 1 S
'
19-Jan13 19-Jan 23
NIS A8 CLACI CEAC 3.3.1 1 S
14-Jan 14 14-Jan 18
32 27-Jan 7 27-Jan 10
NIS A JYK0991 EXCORE CH A 3.3.1 1 S
)
1643b 8 16feb 12
- l i
_ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ - _ - - - _ - _ - _ - _ _ - - _ _ - - - - - _ _ - - - - - - - - - - - - - - - - - - - - - - -
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DUT.
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HOURS SYS N COMPONENT MME LCO #
E E.
i 2 87 4 05-Jan 9 05-Jan 18 9-NIS B JYK0992 EXCORE CH B 3.3.1 1 S
"287;38: 05-Mar 8.'
'05-Mar 11
NIS C JYK0993 EXCORE CH C 3. 3.1
.S 2 87. 39
'03 Feb 6 03-Feb 11E
NIS B-
' JYK09T EXCORE CH B 3. 3.1 1 S
,
L287.13 12-Jan 20 13-Jan 14 18 - NIS B
.. LO91 -
CPC W B.
3.3.1 1.S 2 87 6 '07-Jan 9 07-Jan 11
PMS L194 PMP VIBRATI(N MON 3.3.3.10 1 -S
'
'2 87-49: 06-Feb - 6 06-Feb 9
PMS L194 PMP VIBRATION MON 3.3.3.10 3 5 2 87 '54 06-Feb 23 :
06 f eb 24
PPS D LO32D PPS CH D 3. 3.1 2 S 2 87 60.
11-Feb 7 11-Feb 14
PPS A LO32A PPS CH A 3.3.1 1 S
, 2 87 16 14-Jan.7 14-Jan 11-
PPS A.
1S
- 2 87-22 12-Jan 7 '
12-Jan 15
PPS B LO32 PPS CH B 3.3.1 1'S 2 87 51-06-Feb 18.
06 4 eb 20
PPS A LO32A PPS CH A 3.3.1 2 ~ S
'287 69'
18feb 6.
194 eb 12.
PPS ETRIX
~ 3. 3.1 1'S'
' 2 87 40 04-feb 7 04-Feb 14
PPS C LO32C PPS CH C 3.3.1 1 S 2 87 19 ~ 15-Jan 7 15-Jan 15
PPS B LO32 PPS W B 3. 3.1 1 S l2 87' 14 13-Jan 21 14-Jan 15
PPS PI35998 COND VAC LO42 3.3.3.5 1 S 2 87 26 '20-Jan 7 20-Jan 15
PPS PPS LOGIC MTRIX 3.3.1 1 S
"2 87 7 08-Jan 8 06-Jan 14
S-2 87 27 21-Jan 6 21-Jan12
PPS PPS LOGIC MTRIX 3.3.1 1 S
'2 87 33 064eb 22 064eb 23
PPS C LO32C PPS CH C 3.3.1 2 S
'
2 87= 52 06feb 19 06-Feb 22
PPS B LO32B PPS CH B 3.3.1 2 S
'
2 87 64 134eb 6 13-Feb 12
}
287 13'
13-Jan 21'
14-Jan 15
PPS PI3202E
- COND VAC LO42 3.3.3.5 1 S
'
2.B7 37 30-Jan 0 -
30-Jan 9
RMS FT3772 BPS M UT SUMP DISCH -
3.3.3.8 i S 2 87. 81 24-Feb 8 24-Feb 18
RNS FT4055 S/C BLDN FLOW 3.3.3.8 1 5 2 87 72.
19-Feb 8 19-Feb 10
'2 SIS B P018 HPSI TR B 3.5.2 1-S
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