ML20059C199
| ML20059C199 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 08/16/1990 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20059C197 | List: |
| References | |
| 50-344-90-21, NUDOCS 9008310110 | |
| Download: ML20059C199 (18) | |
See also: IR 05000344/1990021
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION V
Report No.
50-344/90-21
Docket No.
50-344
License No.
Licensee:
Portland General Electric Company
121 S.W. Salmon Street
Portland, OR 97204
Facility Name: Trojan
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Inspection at: Rainier, Oregon
Inspection conducted:
June 9 - July 21, 1990
Inspectors:
R. C. Barr
SeniorResidentInspector, Trojan
C. J. Bosted
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Senior Resident Inspector, WNP-2
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J. F. Melfi
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Resident Inspector
B. Olson
P
ct Inspector
B//6/W
Approved By:
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P.J.forrill, Chief
Dhte Signed
ReactorProjectsSection1
Summary:
Inspection on June 9 - July 21,1990 (Report 50-344/90-21)
Areas Inspected:
Routine inspection of operational safety verification,
maintenance, surveillt.nce, event follow-up, system engineering, and open item
follow-up.
Inspection procedures 30703 61726, 62703, 71707, 71710, 92700,
92701,93702,and97202wereusedasguIdanceduringtheinspection.
Results
General Conclusions and Specific Findings
This inspection identified a continuing weakness in the licensee's
administrativecontrol.ofsetpoints.Additionallyionsofsafetysyste.o
the operations grc m made
several procedural errors that resulted in actuat
(Section7).
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Significant Safety Matters
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None
Summary of Violation and Deviations
One cited violation identified an inattentive firewatch (Section 3).
Open Itemo Summary
Five LERs, two followup items and one unresolved item were closed.
One
unresolved item. in addition to the previously discussed Notice of Violation
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was identified.
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DETAILS
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1.
Persons Contacted
- J. E. Cross, Vice President, Nuclear
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- W. R. Robinson Plant General Manager
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- C. K. Seaman,Assistart to Plant General ManagerdeneralManager,
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O. P. Yundt
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"G.A.Lievallen,GeneralManager,TrolanExcellence
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- M. J. Singh, Manager, Plant Hodificat ons
J. D. Reid, Manager, Quality Support Services
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- J. W. Lentsch, Manager, Personnel Protection
- A. R. Ankrum, Manager, Nuclear Security
- J. A. Reinhart, Acting Manager, Operations
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- R. M. Nelson, Manager, Nuclear Safety and Regulation
- M. W. Hoffman, Acting Manager, Planning and ControlNuclear Plant Engineeri
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A. N. Roller, Acting Manager
- S.A.Bauer,BranchManager(e,NuclearRegulation
- J. F. Whelan, Manager, Main nance
J.
Mody, Branch Manager, Plant Systems Engineering
D. L. Nordstrom, P^anch Manager, Quality Operations
J.
Taylor, PM/EA Branch Manager
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G.
Rich, Branch Manager, Radiation Protection
R. L. Russell, Brahch Mana
Operations
R. N. Prewitt, Supervisor,ger,lity Systems
Qua
R.
Reinhart, Supervisor Instrument and Control
J. A. Benjamin, Supervisor,, Quality Audits
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J. D. Guberski, Nuclear Safety and Regulation Department Engineer
- W. J. Williams, Compliance Engineer
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- D.
Couch, Compliance Engineer
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The inspectors also interviewed and talked with other licensee employees
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during the course of the inspection.
These included shift supervisors,
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reactor and auxiliary operators, maintenance personnel, plant techniciant
and engineers, and quality assurance personnel.
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- Denotes those attending the exit interview.
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2.
Plant Status
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At the beginning of the inspection period the facility was in Mode 5. The
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plant entered Mode 4 at 4:56 a.m. on June 24, 1990, June 25, 1990, the
to perform Steam
Generator (SG) Crevice flushing.
At 10:35 a.m. on
facility was returned to Mode 5.
At 11:04 p.m. on June 25, 1990, at the
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conclusion of crevice flushing, Mode 4 was entered for the ascent to full
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power.
The lant entered Mode 3 at 8:32
.m. on June 27 1990.
On June
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28, the faci $ity returned to Mode 4 at 7:$7 p.m. to repalt the Auxiliary
Feedwater Pump control system.
The facility reentered Mode 3 at 9:36
a.m. on June 29.
The facility entered Mode 2 on July 5 at 5:03 a.m. and
low power physics testing (LPPT) was performed.
The facility entered
Mode 1 at 6:39 a.m. on July 10 and conducted main turbine testing.
While
conducting Main Turbine Overspeed testing at 2:50 a.m. on July 11, 1990,
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an Unusual Event (UE) was declared based on a perceived stuck open main
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steam safety valve. The UE was terminated at 3:13 a.m.
The facilit
returned to Mode 3 to investigate this event.
At 4:49 p.m. on Jul
13,
1990, the plant entered Mode 2 with Mode 1 entry occurring at 10:1
p.m.
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The plant reached 100% pcwer at 3:10 a.m. on July 17, 1990, and remained
at 100% power until the end of the reporting period.
3.
Operational Safety Verification (71707)
During this inspection period, the inspectors observed and examined
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activities to verify the operational safety of the licensee's facility.
The observations and examinations of those activities were conducted on a
daily, weekly or biweekly basis.
On a daily basis the insaectors observed control room activities to
verify the licensee's ad1erence to limiting conditions for operation as
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prescribed in the facility Technical Specifications.
Logs,
instrumentation, recorJer traces
examined to obtain information on, and other operational records were
plant conditions, trends, and
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compliance with regulations. On occasions when a shift turnover was in
progress, the turnover of information on plant status was observed to
determine if pertinent information was relayed to the oncoming shift
personnel.
Each week the inspectors toured the accessible areas of the facility to
observe the following items:
General plant and equipment conditions.
Maintenance requests and repairs.
Fire hazards and fire fighting equipment.
Ignition sources and flammable material control,
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Conduct of activities in accordance with the licensee's
administrative controls and approved procedures.
f) Interiors of electrical and control panels.
g) Implementation of the licensee's physical security plan.
a) Radiation protection controls,
i) Plant housekeeping and cleanliness.
j) Radioactive waste systems,
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(k) Proper storage of compressed gas bottles.
Weekly, the inspectors examined the licensee's equipment clearance
control with respect to removal of eouipment from service to determine
that the licensee complied with technical specification limiting
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conditions for operation.
Active clearances were spot-checked to ensure
that their issuance was consistent with plant status and maintenance
evolutions.
Logsofjumpers, bypasses,cautionandtesttagswere
examined by the inspectors.
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Each week the inspectors conversed with operators in the control room,
and with other plant personnel.
The discussions centered on pertinent
topics relating to general plant conditions, procedures, security,
training and other topics related to in-progress work activities.
The inspectors examined the licensee's Corrective Action Program (CAP) to
confirm that deficiencies were identified and tracked by the system.
Identified nonconformances were being tracked and followed to the
completion of corrective action.
Routine inspections of the licensee's physical security program were
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performed in the areas of access control, organization and staffing, and
detection and assessment systems.
The ins)ectors observed the access
control measures used at the entrance to t1e protected area, verified the
integrity of portions of the protected area barrier and vital area
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barriers, and observed in several instances the implementation of
compensatory measures upon breach of vital area barriers.
Portions of
the isolation zone were verified to be free of obstructions.
Functioning
of central and secondary alarm stations (including the use of CCTV
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monitors) was observed.
On a sampling basis, the inspectors verified
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that the required minimum number-of armed guards and individuals
authorized to direct security activities were on site,
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The inspectors conducted routine inspections of selected activities of
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the licensee's radiological protection program.
A sampling of radiation
work permits (RWP) was reviewed for completeness and adequacy of
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information.
During the course of inspection activities and periodic
tours of plant areas, the inspectors verified proper use of personnel
monitoring equipment, observed individuals leaving'the radiation
controlled area and signing out on appropriate RWP s, and observed the
posting of radiation areas and contaminated areas.
Posted radiation
levels at locations within the fuel and auxiliary buildings were verified
using both NRC and licensee portable survey meters.
The involvement of
health physics supervisors and engineers and their awareness of
significant plant activities was assessed through conversations and
review of RW) sign-in records.
The inspectors verified the operability of selected engineered safety
features.
This was done by direct visual verification of the correct
position of valves, availability of power, cooling water supply, system
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integrity and general condition of equipment, as applicable.
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Inattentive Firewatch
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On July 24 1990, at approximately 7:00 a.m., during a routine plant tour
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of the auxiliary building, the inspector noted that a continuous fire
watch had been established as a compensatory measure for a missing fire
barrier between the 77 foot and the 93 foot level (fire areas Al and AS,
A6) of the auxiliary building.
The inspector noted that the fire watch
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in that he was sitting in a chair, his eyelids were
appeared inattentive,back, mouth open, and feet extended out in front of
closed head leaning
him.
iheinspectorobservedthefirewatchforseveralminutesandthen
left to inform the Security Watch Supervisor.
The inspector returned and
observed the firewatch for an additional 10 minutes.
The firewatch
remained in the same position.
During this time, the firewatch's
portable communication radio gave a burst of noise and the firewatch
appeared to startle.
He then observed the inspector.
The inspector then
spoke with the firewatch concerning his duties and responsibilities,
Two security guards came shortly tiereafter and relieved him of his
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duties.
The same individual in the same location performing the same duties was
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observed by the NRC to be inattentive approximately two months previous
to the observation made on July 24, 1990.
During the previous
observation, the individual was given counseling, and the licensee let
all fire watch personnel know their expectations as to the degree of
attentiveness desired.
The inspector subsequently determined that the
firewatch had been at that station since 6:00 a.m. that morning.
The
failure to establish a continuous firewatch is an apparent violation of
technical specification 3.7.9(50-344/90-21-01).
Subsequent review of the incident revealed that the firewatch was
established for corrective actions associated with Corrective Action
Report (CAR) 90-5048.
The barrier was reported inoperable on March 23,
1990.
Technical Specification 3.7.9 states in part that, " Restore the
nonfunctional fire barrier penetration (s) to functional status within 7
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days or, in lieu of any other report required by Specification 6.6.1 or
10 CFR 50.72, prepare and submit a Special Report to the Commission
aursuant to Specification 6.9.2 with the next 30 days ..." The licensee
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las not submitted a Special Report on the inoperable fire barrier as of
the end of the inspection period.
The need to initiate a Special Report
will be be followed up during routine inspection.
One violation was identified.
4.
Engineered Safety Feature (ESF) System Walkdown (71710)
Prior to tre reactor startup from the 1990 Refueling Outage, the
inspectors verified portions of the Service Water (SW) and Residual Heat
Removal (RriR) systems lineups.
The inspectors also reviewed outstanding
Maintenance Requests (MRs) on these systems to identify MRs that needed
to be worked prior to startup.
The inspectors verified that the
housekeeping was adequate and system leakage appeared minimal.
The
inspectors were cor.cerned with the leakage around FE 610 and 611 and
questioned the licensee about the status of work on these RHR
recirculation line flow elements.
The inspectors were informed by the
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licensee that these were to be worked.
During the walkdown, the systems
ap eared to be properly labeled, and the instrumentation was installed
an in calibration.
Subsequent to full power operations, the inspectors walked down portions
of the RHR system.
The system appeared to be satisfactory with the
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following exception:
Valve M0-8703 (hot leg recirculation valve) was
noted to have aight out of 10 bolts missing on the valve actuator
electrical cover and there was boron crystallization on the valve stem.
These observations indicate a weakness in licensee's post outage system
walkdowns.
The licensee wrote a Priority 2 MR (90-8034) to correct the
missing bolts and routine MR (90-8048) to remove the boron accumulation.
The inspectors were informed that there were no open MRs on the valve.
The inspector determihed the valve was not environmentally qualified.
The inspectors will continue monitoring the quality of the licensee's
system walkdowns following planned and unplanned outages.
No violations or deviations were identified.
5.
Maintenance (62703)
On July 11, 1990, the licensee declared an Unusual Event (UE) when three
steam generator safety valves lifted fo11cving an overspeed test of the
Additional concerns were idontified over the operation of
the steam dump system during and following the event.
The inspector
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observed maintenance activities associateo with the troubleshooting
investigation for the steam dump pre.sure controller.
The steam dumps have two modes of control, Temperature Mode and Pressure
Mode.
In the Pressure Mode of control, the steam dumps modulate open
whenever the steam pressure exceeds the established setpoint.
During the
Unusual Event, it was noted that the steam dumps did not open as expected
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in automatic, however they did operate as designed in manual.
Subsequent
to thk , the licensee noted that the controller did not open at the
setpr nt of 9.1 (1092 psig), but it did o
psig). perate satisfactorily when the
controlwasadjustedto 8.9 (1068
The licensee then wrote
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Maintenance Request (MR) 90-7662 to troubleshoot and repair the pressure
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controller (PK-507),
The inspector verified the MR was performed by
qualified personnel, and that the MR instructions were followed.
The licensee investigated the operation of the steam dump pressure
controller.
The licensee determined that the controller was operating
correctly as set.
However, the reset time integrator was found to be set
at 120 seconds as opposed to 90 seconds as designed.
The controller
setting was last established during the 1989 outage.
At the end of the
inspection, the licensee could not identify when the reset time constant
was changed.
The licensee returned the reset setting to 90 seconds.
The
licensee stated that the change in the time response constant would have
had little effect on the transient.
No violations or deviations were identified,
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Surveillance (61726)
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The licensee reloads approximately 1/3 of the core each refueling outage.
For each core reload analytical methods are used to predict basic core
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parameters.
Core performance is evaluated during physics testing prior
to full power operations to verify these parameters.
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Section 10 of the Technical Specifications (TS) allows the plant to
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conduct physics tests for a new core and exceed specific portions of the
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TS by the use of saecial test exceptions.
The licensee used Periodic
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EngineeringTest(PET)13-1,"ReloadCycle13StartupLowPowerPhysics
Tests," which verified the critical boron concentration for certain rod
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configurations, the isothermal and moderator temperature coefficients,
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and tie zero power differential worth, and integral control bank rod
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worth.
The inspector observed the licensee conduct portions of PET 13-1.
These tests help to assure that the values for the Moderator Temperature
Coefficient (MTC) and the shutdown margin are within technical
specification requirements.
To measure the moderator temperature coefficient, the Isothermal
Temperature Coefficient (ITC) is measured and the MTC is found by
subtracting the fuel effects (Doppler. Temperature Coefficient or DiC)
from the ITC.
Technical Specification Surveillance 4.1.1.4.2.a requires
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that the MTC be measured prior to initial operation above 5% thermal
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power.
The licensee used TS special test exemption 3.10.4 to perform the
test prior to 5% power.
During the physics tests the core was kept at less than 5% thermal power
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and each intermediate range and power range nuclear instrument channel
had been subjected to a enannel functional check within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of
initiating the test.
The reactor trip setpoints were set to less than
25% of rated thermal power.
The licensee was below the Point of Adding
Heat (P0AH)andtheRCSparameterswerestablewiththecontrolrod
position, boron concentration, RCS temperature and pressure set within
the reference bands.
The licensee calculated core reactivity using the reactivity computer,
which uses cycle specific core aarameters ar. input from one nuclear
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instrument channel to measure t1e core reactivity.in values of percent
millitho (pcm).
The values of core reactivity were plotted against RCS
temperature by the reactivity computer.
The value obtained for the ITC
was -1.5 percent millitho per degree Fahrenheit (pcm/oF) during the
cooldown measurement, and -2.7 pcm/oF during heat-up.
The average ITC
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was -2.1 ptm/oF.
The predicted value for tie ITC was -0.8 + 3 pcm/oF.
The value for the DTC was noted as 2.24 pcm/of based the initial (1975)
reload analysis.
An average value of 0.14 pcm/oF was then obtained for
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the MTC which meets the requirement of TS 3.1.1.4.
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The licensee also verified the differential and intparal rod worths for
the control banks.
The licensee monitored the RCS temperature and boron
concentration when taking the control rod worth measurements.
The
licensee maintained the pressurizer heaters on to assure that there was
proper mixing between the RCS and the pressurizer.
The licensee used the
boron endpoint method to determine the rod worths.
The control bank rod
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worths were within the acceptance range s)ecified by the procedure.
The
combined rod worths for control banks A, 3. C, and D were measured to be
3870.5 pcm, which was within the acceptance range of the test (3939 + 394
pcm).
The required shutdown margin by TS 3.1.1.1 is 1.6% delta K/K T1600
pcm).
The reload analysis value for the four control banks was 3939 pcm.
The inspector reviewed the data taken in PET 13-1 and no deficiencies
were identified.
The core physics parameters measured appeared to be
very close to what was analytically predicted by the reload analysis.
Other Issues with Surveillance Observation
During the performance of the core physics test, the licensee was
preparing to implement a new policy change on procedures requiring
ste)-by-step compliance wit 'cocedures.
This resulted in several delays
wit 1 the implementation of H.T 13-1 to allow the procedure to be changed
and/or performed as written.
The inspector observed this process and
identified no problems.
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The inspector questioned the changes to PET 13-1 which were completed at
the request of the Plant Manager.
The inspector observed that the
special test exemptions part of the Technical Specifications have special
surveillance requirements when performing the physics tests.
Two of
these surveillance requirements were to verify rod position every two
hours and thermal power less than 5% every hour.
T1e inspector discussed
the verification of these parameters with the cognizant test engineer who
had been involved with all the core physics testing that had been
performedatTrojan.
The engineer stated that the core status was
continually monitored by the responsible engineers and operators to
assure that the rods did not move inadvertently or that thermal power
exceeded 5%.
Previous revisions of this procedure did not require these
parameters to be documented consequently no proof of compliance with the
technicalspecificationsexIsts.
The inspector was informed that these
new changes would be included in the new revision to PET 13-1.
Ne violations or deviations t.ere identified.
7.
Event Follow-up (93702, 62703, 92701)
Inadvertent Containment Spray Pump (CSP) Start and Reactor Trip Sianal
On June 18, 1990, with the facility in cold shutdown (Moce 5) and
Periodic Instrument and Control Test (PICT) 22-2 " Engineered Safety
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Features Actuation System (ESFAS) Response Time,A being performed on the
B train of ESFAS, an inadvertent start of the B CSP occurred.
On
June 30,(1990, while conducting a different section of PICT 22-2 in hot
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standby Mode 3), an inadvertent reactor trip signal was generated.
The
licensee conducted critiques after each event to collect information as
to the cause of the events.
From subsequent investigation the licensee
concluded the cause of the inadvertent CSP start was a jumper was not
removed during the performance of earlier steps of the PICT.
The
licenseeconcludedthejumperwasnotremovedduetoerrorsin
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communication and procedural noncompliance by technicians.
The licensv
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determined the generation of the inadvertent reactor trip signal was a
result of performing procedural steps out of sequence.
The inspector reviewed the licenseets critique notes and independently
investigated the events.
The inspector reached the same conclusions as
the licensee as to the causes of the events.
Additionally, the inspector
verified licen:re's immediate corrective action for these events and
verified the evtnts were reported per 10 CFR 50.72 and would be-
documented per 10 CFR 50.73.
The licensee's long term corrective actions
will be evaluated during the revier of LER 90-26.
MispositionedSafetyInjection(_SI) Pumps'ControlSwitch
At 9:36 a.m. on June 29,iencies, facility operational mode was changed 1990, after re
controller seismic defic
from Mode 4 (hot shutdown) to Mode 3 (hot standby).
One prerequisite
(technical specification 3.5.2) for the mode shift was to have both
safetyinjectionpumpsinautomatic.
At approximately 2:00 p.m. on
June 29, 1990,d that both SI pump control switches were,in aull-to-lock
during the swing shift crew watch relief the oncoming
crew identifie
(off) vice automatic, as required by plant conditions.
Boti SI pump
control switches were immediately placed in automatic.
Per 10 CFR 50.72,
the licensee immediately notified the Nuclear Regulatory Commission via
the Emergency Notification System (ENS).
Licensee investigation of the event concluded the SI pump control
switches were not correctly positioned because plant operators relied on
Mode 3 prerequisites from the June 27 transition to Mode 3, vice
reverifying the prerequisites were met for the June 29 transition.
In
thelicensee'sreviewofGeneralOperatingInstructions(GOI)1-2, ired
" Plant
Heatup-Hot Shutdown through Hot-Standby,"ing the SI pumps in automatic
they found that all requ
steps had been oerformed except for plac
(Step 3.6.2.d .
recurrence inc)luded counselling the operators involved, having theLicensee imm
involved operators provide a training session to their peers on this
event, and revising requirements for procedural compliance.
Previous to
this event, PGE operators were only required to follow procedures in the
sequence they occurred in the procedure when the prerequisites required
verbatim compliance.
The revised PGE requirement for verbatum procedural
compliance is to follow procedures in segeunce except when the
procedure's prerequisites state verbatim compliance is NOT required.
The inspector attended the licensk critique of the event, reviewed the
PGE all employee bulletin on the change in requirements to procedure
compliance and verified operator awareness of the change.
The ins)ector
concluded, due to the low core decay heat inventory and the availaaility
of the other Emergency Core Cooling System pumps,is event in LER 90-29.
this event was of minor
safety significance.
The licensee will report th
Heactor Coolant System (RCS) Flow Technical Specification (T.S.) Changes
On November 7 1989, the licensee and Westinghouse had a telephone
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conferencecalltodiscusstheaffectsofinstrumentuncertaintiesonRCS
flow and technical specifications associated with RCS flow.
The
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conversation was required to resolve previous operational concerns
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identified in Licensee Event Reports (LERs) 89-20, " Reactor Coolant
Average Temaerature Surveillance Performed Without Accounting for
Instrument Jncertainties," and 89-22, " Reference Temperature Value Used
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in Rod Control System Higher Than Value Used in Safety Analysis,"
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respectively.
During the discussion, Westinghouse (the reactor vendor)
told PGE that the RC5 flow value (354,000 gpm) for T.S. 3.2.3, "RCS Flow
Rate and FR " did not include instrument uncertainties and should be
revised (365,390 gpm) to include the instrument uncertainties.
PGE did
not consider an immediate change to the technical specification was
required since actual plant RCS flow was 371,539 gpm which was above the
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accident analysis required flow rate.
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On December 4, 1989, Westinghouse, via a memorandum to the Manager of
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NPE), documented that PGE could increase
Nuclear Plant Engineering (97% as long as RCS flow was maintained greater
reactor power to 100% from
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than 366,390 gpm.
On May 18, 1990, Westinghouse, via a telephone conversation, notified PGE
that after internal Westinghouse discussions on RCS flow with respect to
Trojan,itbecameapparenttherequiredvalueforRCSflowwasactually
371 700 vice 366,390 gpm.
Additionally, Westinghouse indiceted that the
minImumRCSflowrequirementcouldnotbechangedforeitherT.S.3.2,3,
"RCS Flow Rate and FR," or T.S
3.2.5, " Departure from Nucleate Boiling
(DNB) Parameters." The apparent RCS flow margins in these specifications
do not exist because other accident analyses were encompassed by these
specifications.
BecausetheactualmeasuredflowforTrojanduring
previous cycles had been-less than 371,700 gpm (371,539 gpm),the
licensee requested Westinghouse reanalyze to support a lower flow.
On
May 22, 1990, the licensee wrote corrective action request (CAR) 90-5167
to document the deficiency.
On May 30 1990, Westinghouse provided PGE
thereanalysisthatindicatedanRCSflowof 368,4)00 gpm was acceptable.
On June 5, 1990, after the Systematic Assessment of Licensee Performance
(SALP)meetingatTrojan thelicenseeinformedtheProjectManagerof
the RCS flow concern and, indicated PGE would be placing a more
restrictive administrative limit on themselves for RCS flow while the
technical specification change was being processed.
TheProjectManager
said he agreed with the licensee's approach and requested at the earliest
possible convenience marked up copies of the technical specifications be
provided for his review.
On June 25 1990,theOregonDepartmentofEnergy(ODOE) resident
inspectorInformedtheNRCresidentinspectort1atataPlantReview
Board (PRB) meeting which he attended, a change to the RCS flow technical
specification was discussed.
Since the resident had not been previously
appraised of the issue, he conducted a followup inspection.
1
From this inspection, he learned the above history.
He also learned PGE
was intending to restart from the 1990 Refueling Outage without havmg
the T.S. change ap3 roved by the NRC.
The inspector was also concerned
that the licensee lad presented the reload analysis for Cycle 14, which
included changes to the RCS flow rate, to the PRB for the PRB's review.
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The inspector expressed his concerns to licensee and to NRC Regional
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management.
As a result, the licensee sent a draft Licensee Change Ap)11 cation (LCA)
to NRC for review which was reviewed on June 30, 1990.
Tae staff
requested PGE take RCS flow measurements at 90% and 100% power to assure
that the RCS flow had not dropped below the new analyzed limits.
During
thesetests$0the RCS flow was measured at approximately 377,00 gpm.On
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July 13, ion. ,In the LCAthe licensee formally submitted the Licensee Change
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Applicat
the licensee concluded that the new T.S. values
didnotinvolveasignifIcantreductioninthemarginofsafety.
The
,
licensee concluded that there was a small change in the RCS Protection
setpoint for Over Temperature Delta Temperature (K1 constant is now 1.41
versus 1.42 previously).
The licensee also determined that there was no
change in the DNB safety analysis and there was no reduction in the
margin of safety with respect to DNB.
This item remains open pending the inspector's review of the
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June 25 1990 PRB minutes and assessment of the appropriateness of not
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submittingaLCAeponlearningTechncialSpecification3.2.3and3.2.5
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wereincorrect(50-344/90-21-03).
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Unusual Event (UE) and Reactor Shutdown
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At 2:19 a.m., on July 11, 1990, with the facility in Mode 1 at
approximately 7% reactor power, the licensee, to verify the operability
of the main turbine overspeed trip mechanism, commenced Periodic
OperatingTest(POT)18-4,"MainTurbineOverspeedTripSystemTest." As
a test prerequisite the steam dumps were placed in automatic and set at
1092psigwiththeIntentionthatthesteamdumaswouldopenduringthe
test and prevent power operated relief valves ()0RVs) and main steam
safety relief valves (MSSVs) from actuating.
The main turbine was
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tripped at 2:32 a.m. and the facility entered Mode 2 at 2:36 a.m.
At
,
2:40 a.m., licensed plant operatv5 noted that the steam dumps (SDs) and
the secondary power operated relief valves (PORVs), which were expected
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to have automatically opened on increasing steam pressure, had not
opened.
The control operator briefly cycled the SDs from automatic to
manual and back to automatic which resulted in the expected SD operation.
At 2:49 a.m. the control room operator was notified by an auxiliary
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operator that the main steam safety relief valves (MSSV) were opsn.
At
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2:50 a.m. the shift supervisor declared an Unusual Event (UE) because he
concluded the MSSVs had failed to shut.
At 2:55 a.m., plant operators
began reducing reactor coolant system (RCS) temperature to reduce steam
temperature and pressure in order to get the MSSVs to reset.
At 3:02
a.m., all the MSSVs shut.
At 3:13 a.m., the licensee exited the UE.
The
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event raised questions over the proper functioning of the MSSVs, PORVs
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and the SDs.
At 5:40 a.m., the licensee as a conservative measure, shut
down the reactor and entered Mode 3 and tested the MSSVs, PORVs and SDs
for proper operation.
Testing of the MSSVs identified the MSSVs had o>erated as designed, i.e.
the MSSV lift and shut settings were correct.
urther licensee
evaluation of the event identified that the training the licensed
operators had received led the operators to believe the MSSVs would reset
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(shut) at higher pressures than the valves actually shut.
Testing of the
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PORVs identified that the PORVs did not functione as designed.
Due to
thelargeincrementsonthePORVsetpointscale(25lbs.)ftedbetween30
and the drift
tolerance of the controller output the PORVs actually li
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to 37 1sig higher than set.
Additionally,thelicenseedeterminedthat
the PORV controllers proportional band setting (full open to full close)
was incorrect (750 psig vice 60 psig).
The licensee concluded the
incorrect setting of the proportional setpoint had a limited affect on
this event because the MSSV settings were within the as-found settings
for the PORVs.
Licensee investigation of the event could 1ot determine
>
when the controller was improperly set.
Testing of the steam dumps
identified that the steam dumps functioned as designed; however
understandingbyboththelicensedoperatorsandtiesystemengIneersof
,
SD controller operation when in automatic and the steam pressure control
mode was weak.
The system engineers and the licensed operators believed
the steam dumps, when in automatic, would open immediately and control
steampressure,wheninfact,thesteamdumpswereadjustedtofullyopen
on large (approximately 1000 psig) differences from set control pressure.
Additionally, the licensee also found that the controller reset
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integrator was actually set at 120 seconds vice 90 seconds.
The licensee
could not identify when the steam dump reset time integrator was misset.
Further licensee investigation determined licensed operator training does
not teach the details on the operation of the steam dumps when the
controller is in automatic and steam pressure control mode of operation.
As corrective action for this event, the licensee plans to train licensed
operators on the specific operation of the steam dump controller and the
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HSSVs.
Additionally, POT 18-2 and GOI 3-1 will be revised to alert the
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operators to the constraints of operating the steam dumps in the pressure
control mode.
The licensee also verified the present settings of both
the steam dump controller and the PORV rentroller are now at the correct
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design valuts.
The licensee will describe this event and their
corrective actions in LER 90-33.
As part of event response and followup, the resident inspector attended
the event critique, discussed the event with the Plant General Manager
and discussed with the facility licensed operators their knowledge of the
implemented corrective actions.
The resident verified that with a MSSV
blowdown (reset) value of 20%, the licensee safety analysis for a steam
generator tube rupture (SGTR) event with 1% failed fuel would not exceed
10 CFR 100 limits.
The licensee's immediate corrective actions appeared
conservative and appropriate to the inspector.
The licensee had a previous similar event occur in September 1984.
In
the 1984 event, the steam generator PORVs were set at approximately
1260 psig.
A transient occurred and the steam generator MSSVs lifted.
The control room staff was informed that the MSSVs were lifting by the
oncoming shift crew.
The licensee reduced steam generator pressure in
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order to close the MSSVs with last MSSV shutting at 890 psig (24%
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blowdown which was greater than design values).
The corrective actions-
for LER 84-17, " Delayed Reseating of Mair. Steam Safety Valve and Reactor
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Trip," were noted in letters from Mr. Withers to Mr. hartin dated October
3 and November 2, 1984.
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Some of the long term corrective actions to be taken for the
September 1984 event were to mark the normal setpoints on various
,
evaluate control room indicators for PORV setpoints,
controllers,irability of providing capability to monitor P55V position,
evaluate des
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and establish controls and routine checks on various instruments and
controllers in the control room.
The licensee labeled the controllers to
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give the nominal setpoints.
On May 24, 1985, the licensee, even though
all the controllers were set at 1125 psig and the actual setpoint setting
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of the controllers was two to three percent higher on all the
controllers, evaluated PORV setpoint on the control room indicators and
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concluded that the PORV controller setpoint had sufficient precision to
verify that the controller setpoint was set at a) proximately 1125 psig.
On December 3, 1985, the licensee, even though tie control operator had
evaluated the need and concluded
to be informed the safety had lifted,isted.
sufficient control room indication ex
During the July 1990 event,
I
the operators again had to be informed by personnel external to the
control room that the MSSVs had lifted and the indication on the
,
controllers was insufficient to assure lifting of the PORVs at desired
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pressures.
Based on the July 1990 event it appears the licensee's
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correctiveactionsfortheSeptember198$eventdidnotpreventarepeat
,
occurrence.
Further inspector followup of this event will occur during
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the review of LER 90-33.
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No violations or deviations were identified.
8.
Follow-up of Licensee Fvent Reports (92700)
LER 90-01, Revision 0, (Closed), " Failure to Test Containment Personnel
Air Lock Equalizing Valve Compromised Containment Integrity Due to
Procedural Inadequacy." Licensee followup of failed surveillance,
Periodic Engineering Test (PET) 5-2 " Containment Local Leak Rate Testing
(LLRT),"identifiedthatthesurveillancedidnottesttheContainment
Personnel Airlock inboard equalizing valve for leakage.
The licensee
concluded the cause of the event was both the design of the door's
equalizing system and an inadequate procedure.
The licensee confirmed
PET 5-2 was adequate for leak testing the outboard Containment Airlock
doqr and its equalizing valve, inboard door equalizing valve.but was only a
inboard door seal and not the
Licensee
corrective actions incTFded (1) submitting an exemption request (April
18,1990) for not conducting a local leak rate test on the inner door
equalizing valve (2) revising the surveillance procedure and (3)
evaluating a modification to the airlock door equalizing valve.
On June
8, 1990 the NRC approved the exemption request.
The basis of the
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approvalwasacceptanceanalternativemethodofpressurizingbetweenthe
valve seals at reduced pressure and ratioing the as-found leakage to
design accident pressure.
The inspectors documented previous inspections of this event in NRC
inspection reports 50-344/89-33 and 50-344/90-11.
Additional inspection
in this period included a review of the revised surveillance procedure,
verification that the local leak rate test for the containment airlock
was within acceptable leak rate criteria (using the new procedure), and
verification that the integrated leak rate test was within leakage
criteria.
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LER 90-11, Revision 0 and Revision 1, (Closed), " Control Room Emergency
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Ventilation System Unfiltered In-leakage Exceeds F5AR Value Due to
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Missing Duct Sealant." on March 30 1990, the licensee determined
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unfiltered air in-leakage for the B train of control room emergency
ventilation system (CB-18) exceeded the aaximum allowed accident analysis
value of the FSAR (25.5 cfm vice 10 cfm).
The licensee verified that the
other train of control room emergency ventilation (CB-1A) was always
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operable with the exception of times when maintenance or surveillance
testing was in progress. -The licensee concluded the ducting was damaged
during a repair of a CB-1B seismic sup> ort during the 1989 Refueling
Outage.
The licensee also concluded t1e cause of the event was
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incomplete post-modification testing and that design documents did not
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identify that epoxy paint was being used as a temporary sealant until the
ducting was replaced.
Licensee corrective actions included repairing the
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damaged ducting, correcting the design basis documents, and replacement
of tie control room emergency ventilation ducting in 1992.
The licensee
also changed procedures to ensure adequate post maintenance testing
following work on ventilation ducting and revised drawings to indicate
the epoxy sealant was a part of the pressure boundary.
The inspectors verified the above mentioned corrective actions were
completed or scheduled as appropriate.
The inspectors reviewed the
results of the 1990 ventilation leak tests and verified no releases had
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occurred between June 1989 and May 1990 that could have resulted in
exposure to plant operators.
As a course of routine inspection
inspectors will follow-up on the effectiveness of the licensee's, the
corrective actions.
This item is closed based on licensee completed and
proposed corrective actions.
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LER 90-13, Revision 1, (Closed), " Control Room Emercency Ventilation
Disabled Due to Door 25 Being Closed." This revisec
LER provided
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additional information with respect to the cause and corrective actions
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for the event.
The licensee concluded the cause of this event was
inadequate implementation of administrative controls and personnel error.
As corrective actions,ked the ability to pressurize the control room withthe l
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a chain and lock, chec
the emergency ventilation system and issued a lessons learned summary to
allTrojanemployees.
Additionally, the licensee is planning a permanent
modification to be installed by November 30, 1990, that will eliminate
the need to have the door open.
The inspectors verified the above corrective actions were performed or
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scheduled as appropriate.
Additionally, the inspectors discussed with
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the Plant Manager the requirements to verify that implemented
compensatory administrative controls are frequently surveilled for
adequacy.
The inspectors assessed this event to be of minor safety
significance since a positive control room pressure was achievable.
The
inspectors, as a part of routine followup inspection, will continue to
evaluate the licensee's implementation of administrative controls.
This
item is closed based on licensee completed and proposed corrective actions.
LER 90-14, Revision 0, (Closed), " Error ir Oricinal Classification and
Building of a Ventilation Boundary Wall Could Fave Rendered Control Room
Emergency Ventilation System Inoperable Due to a Seismic Event." Initial
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inspection of this event is documented in NRC Inspection Report
50-344/90-16.
Additional inspection found that had a seismic event
occurred, the ventilation boundary wall would not have collapsed even
though it may not have retained its design function as a pressure
retaining boundary.
Because a seismic event is not expected to cause a
design basis loss of coolant accident or toxic exposure to the control
room operators, the inspectors concluded the safety significance of this
event to be minor.
The licensee's corrective action was to redefine the control room
ventilation boundary (after having structurally reinforced and
seismically qualified boundary walls exterior to the wall described by
this event).
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The inspectors reviewed the boundary wall reinforcement and changes with
the design engineer, as well as the most recent surveillance test to
verify the emergency control room ventilation pressurization surveillance
met technical specification requirements.
Based on the licensee's
corrective actions and the minor safety significance of the event, this
LER is closed.
No violations or deviations were identified.
!
9.
Followup of Open and Unresolved Items (92701, 92702)
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Unresolved Item 90-02-02, (Closed), "Both Trains of Containment Hyc'rogen
vent System Inoperable." The A train of the containment hydrogen vent
- ystem was declared inoperable in 1989 due to the sample point not
i
providing a representative sample under low flow conditions.
The B train
sample point was modified to provide a representative samplo.
On January
24, 1990, the B Emergency Diesel Generator (EDG) which provides emceency
power to the B train hydrogen vent system was removed from service for
maintenance leaving no operable Hydrogen Vent Systems.
The B trait was
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returned to service on January 25, 1990, which was
within the 30 day
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Limiting Condition for Operation (LCO) of technical specification 3.6.4.3.
The cause of the event was inadequate coordination of work.
As
corrective action the licensee implemented a Plan of the Day that is
reviewed by all plant managers.
The safety significance was minimal
since the facility operated within the technical specifications.
This
item is closed.
Unresolved Item 90-16-01, (Closed), " Evaluation of Licensee's Degraded
Posts on Station Battery."
)
During the pe formance of a maintenance observation inspection, the
i
inspector questioned if cop)er contamination in the station batteries was
a reportable event per 10 C:R 50 Part 21.
Part 21 requires reports of
i
manufacturing defects.
The licensee had determined that a manufacturing
defect in the lead posts that have copper inserts resulted in copper
contamination in some cells of the station batteries.
contamination in the acid electrolyte can result in the cell voltage
decreasing and shortening battery life.
The battery cell voltage is
required by technical specification surveillance requirement 4.8.2.3.2 to
be greater than 2.00 volts.
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The concern over copper contamination was documented on April 10, 1990 in
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Corrective Action Request (CAR) 90-3070.
The CAR had been evaluated and
gone through initial Quality Assurance (QA) review.
The inspector asked
for the Part 21 evaluation on the station batteries on approximately June
20, 1990.
The Itcensee had not performed the Part 21 determination for
reportability at that time.
The licensee's maintenance group >erformed
an initial Part 21 determination on July 6, 1990 and stated t1at it was
notreportable,perthelicensee'sNuclearDivisIonProcedure(NDP)
700-4, "10 CFR 21 Re)orting of Nuclear Plant Defects or Noncompliances".
When questioned by tie inspector as to why they had not performed the
Part 21 determination earlier, the licensee stated that they were going
to perform the evaluation after the conclusion of the 1990 Refueling
Outage.
The inspector's concerns over the reportability of this issue were
discussed with the maintenance group with the following observations::
1)
The maintenance group stated that this was not reportable because
they could not find any technical requirement for copper
'
contamination in any procurement document or NRC regulation.
The
inspector reviewed the vendor manual and noted limits on copper
contamination in the electrolyte on page 41.
Further, since the
continued use with cop)er contamination could lead to a loss of
voltage on the cell, tiis contamination can affect the NRC technical specification 3.8.2.
2)
The maintenance group also stated that this was not reportable
because the structure was not used to handle radioactive material or
control personr.el exposure.
The inspector noted that the station
batteries provide the emergency power source for power to
instruments following loss of off-site power.
Some of the
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instruments to which power is provided are radiation detectors which
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are used during an accident to control personnel exposure,
3)
The maintenance group further stated that this was not reportable
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because this potential defect would not contribute to exceeding a
i
safety limit or affecting the ability to mitigate the consequences
of an accident assuming a single failure.
The batteries are also-
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used to help mitigate the effects of a station blackout.
4)
The inspector observed that the station batteries are used to help
mitigate the effects of a station blackout.
Because the inspector raised the concern over reportability, the
Maintenance Department asked the Licensing Department to perform an
independent Part 21 evaluation.
The Licensing Department did not agree
with the maintenance department analysis,ly reported by another licensee.
but stated that this was not a
Part 21 report since it had been previous
The inspector contacted the NRC staff and confirmed that their was a
previous Part 21 on the batteries describing this situation (in 1979).
The following items may indicate a weakness in the dispositioning of
potentially reportable events:
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1)
The Maintenance Department evaluation was not timely and was
performed apparently as a result of the inspector's questioning.
2)
The rationale of the Maintenance Department for determining
reportability did not appear correct.
i
3)
The initial QA review of the completed CAR failed to identify this
CAR may have been reportable with respect to Part 21 10 CFR.
The inspectors will continue to monitor licensee evaluatiot, of
potentially reportable issues under 10 CFR 50 Part 21 for technical
adequacy and timeliness.
Followup Item 90-02-03, (Closed), " Evaluate Licensee Actions on Event
90-21."
Steam and water were found to be cmitting from vent valve F-14-3
on the RCS sample line on January 25, 1990.
An operator and guard were
contaminated.
The leak was stopped by isolating the sample line.
An
improper valve lineup was believed to have been the cause.
The licensee
performed an evaluation of this event, documented in Event Report 90-021.
The licensee's evaluation of the event' concluded:
(1)twotestvent
valves (S-5017 ands-5018)onthesamplelinewereshutbutleakedby
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(they did not pass a subsequent pressure / leak test and were replaced);
and (2) a pipe cap on the end of the line downstream was incorrectly
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installed.
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The licensee identified a number of corrective actions as a result of
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this evaluation.
Procedures OH-3-1 and OM-3-3 were revised on March 6,
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1990, to prohibit operators from installing vent and drain caps except
during an emergency.
Operation and Maintenance revised their policies on
March 6, 1990, to provide instructions to check for leakage when
releasing clearances and when a system is repressurized.
In addition all
Teflon tape wu removed f rom site by February 23, 1990.
The actions as reviewed in Ev(nt Report 90-021 were considered adequate.
This item is closed based on licensee corrective actions.
No violations or deviations were identified.
.'.1.
Unresolved Item
An unresolved item is a matter about which more information is required
to ascertain whether it is an acceptable item a deviation, or a
violation.
AnunresolveditemisdocumentedInSections3and6.
12.
Exit Interview (30703)
!
The inspactors met with the licensee representatives denoted in paragraph
1 on August 9, 1989, and with licensee management throughout the
inspection period.
In these meetings the inspectors summarized the scope
and findings of the inspection activities.
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