IR 05000219/1990003
| ML20033F899 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 03/14/1990 |
| From: | Hernan R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20033F897 | List: |
| References | |
| 50-219-90-03, 50-219-90-3, NUDOCS 9004040050 | |
| Download: ML20033F899 (47) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I-
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P iReport No.-
50-219/90-03
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Docket No.-
50-219
p License'No.
DPR-16l l
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p Licensee:'
GPU Nuclear Corporation i
1 Upper Pond Road
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Parsippany, New Jersey 07054
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Facility Name: Oyster Creek Nuclear Generating Station
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Inspection Conducted: January 7,1990, - February 17.-1990
, Participating Inspectors:
M. Banerjee, Resident Inspector
.E. Collins, Senior Resident-Inspector
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D. Lew, Resident Inspector Approved By:
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R. Hernan, Acting Section Chief, I) ate
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Reactor Projects Section 48
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t Inspection Summary:
'. Inspection Report No, 50-219/90-03 for January 7,1990 - February 17, 1990
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Areas Inspected: The inspection consisted of 240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> of direct inspection hours by resident inspectors.
The areas inspected included observation and review of plant operational events (paragraph 1.0), the fire protection deluge system (paragraph 2.0), main steam isolation valve leak repair (paragraph 3.0),
drywell. wall thinning measurements (paragraph 4.0), recirculation pump discharge valve failure (paragraph 5.0), recirculation pump "A" seal failure
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(paragraph 6.0), isolation condenser steam leak (paragraph 7.0), core spray keep fill. pumps (paragraph 8.0), engineered safeguard feature system walkdown
_(paragraph 9.0), monthly maintenance observation (paragraph 10.0), monthly surveillance observation (paragraph 11.0), review of.the Fitness For Duty '
iInitial. Training Program (paragraph.12.0), and onsite review of Licensee Event
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9004040050 900316 PDR ADOCK 05000219
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Results:.The plant was operated in a safe manner during this inspection period.
Licensee discovery of an inoperable deluge system '16 days after a-trouble alarm is.an unresolved item. The absence of documentation of material used in a valve repair is an unresolved. item.
Licensee evaluation.of recirculation pump seal problems was thorough, and the subsequent removal of f
the pump from service was well planned and executed.. Recirculation pump discharge valve problems:may have contributed to seal failure. The Standby Gas-Treatment System (SGTS) was evaluated as able to perform its intended safety
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function.. Initial training sessions for.the Fitness For Duty Program were well.
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presented.
'The licensee' changed theldate'for their estimate to rcach minimum code wall'
thickness-in the drywell from June 1992 to June 1991.
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- TABLE OF CONTENTS
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- 1.0 Plant Operational. Review (71707)................
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1.1 Chronology of Operational Events..............
'1. 2 Control Room Tours.....................
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1.3-Facility Tours..................-.....
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c2.0 Fire Protection Deluge System (71707, 93702)..~.... -,. -.,
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3,0 Main Steam Isolation Valve NS03A (71707)
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4. 0 Drywel l - Wal l Thi nn i ng ( 71707 )...................
5.0 "A"_ Recirculation Pump Discharge Valve (71707, 93702)......
6.0- Recirculation Pump:"A" Seal Failure (93702)
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7.0 Isolation Condenser Steam Leak (71707)......,......
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8.0 Core Spray Keep-Fill Pumps (71707),..............
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9.0 Engineered Safeguards Feature System Walkdown (71710)......
10.0 Monthly Maintenance Observation (62703)..............
11.0 Monthly = Surveillance'0bservation (61726)............
12.0' Temporary Instruction 2515/104:
Inspection of Fitness for Outy Initial Training Program (255104).......
- 13.0 Observation of Physical Security (71707)............
14.0 Enforcement Conference..
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15.0 Onsite Review of Licensee Event Reports
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.(92700, 92701, 92702, 90712)...............,..
16.0 Inspection Hours Summary....................
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17.0 Exit Meeting and Unresolved Items (30703)............
ATTAC'iMENTS Attachment I:
List of Personnel Contacted Attachment II: Licensee Enforcement Conference Presentation
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E DETAILS 1.0 Plant Operational Review w
1.1 Chronology of Operational Events At the beginning' of this inspection period,. the plant was operating at 100% power. The plant had just completed its 22nd day of
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continuous operation with the turbine on line. One technical specification action statement was-in effect.
The No. 2 service
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water dischar0e pressure gauge was declared inoperable on 1/4/90 as a result of maintenance on the No. 2 service water pump. Technical i
specifications allow continued plant operation for 30 days with this gauge out of service. The following lists the major plant events which occurred during this period.
1/10/90 Core Spray System 2 was declared inoperable to allow
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maintenance to be performed on the core spray booster pump differential pressure switch, RV-40B, and the breaker to core spray booster pump NZ03.
Technical specifications allow
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continued plant operations for sever days with this system out of service.
Maintenance on the Core Spray System 2 was completed; and, the system was declared operable. The technical specification action statement was terminated.
Details of this event are
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described in paragraph 8.0.
A plant shutdown'was commenced when the "A" recirculation pump discharge valve failed to close during a preventive maintenance evolution and the reci culation loop was-placed in an isolated condition.
Technical specifications ' equire the plant be pieced r
in cold shutdown if a recirculation loop is isolated.
The shutdown was terminated when the licensee was able to close the
"A" recirculation discharge valve.and place the loop in an idle configuration.
Minimum power attained during the event was 82%.
Details of this event are described in paragraph 5.0.
1/11/90 Reactor power was returned to 100%.
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l When the "A" recirculation pump was returned service after preventive. maintenance on its motor generator, the No. 2 seal L
pressure indicated 940 psig. Normal No. 2 seal pressure was 510 l:
psig. The increased pressure indicated that the No. I seal had
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failed.
Details of this event are described in paragraph 6.0.
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1/17/90 The Emergency Service Water (ESW) System 1 was declared D
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inoperable when ESW pump 52A was placed out of service to repair an oil leak on the motor.
Technical specifications allow plant operation to continue for seven days with this system out of service.
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After completion of the maintenance on ESW pump 52A, Station Procedure 607.4.004, " Containment Spray and Emergency Service Water System 1 Pump Operability and Inservice Test," was performed to establish the operability of ESW System.1.
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the performance of the surve111ance, the ESW System 1 keep fill-line check valve was observed to be chattering when the ESW pump-was. operating. Although the acceptance criteria of the suryc111ance test were satisfied, the licensee elected not to-
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declare the system operable until Plant Engineering reviewed the check valve chattering.
1/18/90 After a precautionary administrative control was placed
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on the ESW system keep fill check valve, the ESW System I was declared operable. The seven-day technical specification' action statement was terminated. The check valve was subsequently replaced on 1/23/90. Details of the check valve chattering are described in paragraph 10.0.
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1/19/90= The No. 2 service water pump was returned to service;-
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and,- the No. 2 service water discharge pressure gauge was declared operable.
The 30-day technical specification action
statement was terminated,-
1/23/90 Reactor power was reduced to approximately 70% to allow
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the removal of the "C" feed string from service to repair a leak on the "C" feed pump casing drain line.
1/28/90 The No. 2 service water pump discharge pressure gauge
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was declared inoperable after discovering that it was broken.
. Technical specifications allow continued plant operations for 30 days with this gauge out of service.
1/29/90 The No. 2 service water pump discharge pressure gauge
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was replaced and declared operable.
The 30-day technical-
specification action statement was terminated.
The leak in the "C" feed pump casing drain was repaired; and, the "C". feed string.was returned to service.
Power ascension to 100% was commenced.
1/30/90 Reactor power ascension was terminated at 88% power.
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Reactor power was limited by the "A" recirculation pump seal temperature. The No. I seal had failed on 1/11/90. The high'
seal temperature indicated the No. 2 seal was starting to fail.
Other indications that the No. 2 seal was failing included increasing drywell identified and unidentified leak rates and
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decreasing No. 2 seal cavity pressure.
1/31/90 The "A" recirculation loop was removed from service as
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a result of high recirculation pump seal temperatures.
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loop power operation is permitted by technical specifications.
Reactor power ascension was recommenced.
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2/1/90 Reactor power ascension was. terminated at 97% power.
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Reactor power was limited by the capacity of the other four E
recirculation pumps.
2/5/90 While attempting to start No. 1 Emergency Diesel
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Generator for surveillance testing, No. 1 EDG failed to. start and the " Engine Disable " alarm annunciated. Technical specifications allow continued plant operation for seven days
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with the No. 1 EDG out of service.
After performing several starts of the No. 1 EDG, no problems were detected. Surveillance Procedure 636.4.003, " Diesel Generator Load Test," was satisfactorily completed for the No. 1 EDG, The No. 1 EDG was declared operable.
The technical specification action statement was terminated.
2/6/90 A reactor shutdown was commenced as a result of
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increasing drywell unidentified leak rate. The increasing leak rate was caused by the failing "A" recirculation pump seal. The unplanned. outage, 12U-8, commenced.
2/8/90 The licensee discovered the fire protection deluge
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system No. 4A was inoperable. Technical specifications require a continuous fire watch posted if this system is out of service.
The first indication of the failure of this system occurred on 1/23/90 when the trouble alarm for fire area 4A was received.
When the trouble alarm was received, an hourly fire watch was posted. Details of this event are described in paragraph 2.0.
2/15/90 A reactor startup from the 12U-8 outage commenced.
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During the startup, the operators realized that the first six control rods were withdrawn with the rod. worth minimizer (RWM)
bypassed.
Technical specifications require the RWM operable at
least during the withdrawal of first 12 control rods. At the end'of this inspection period, this event was still under NRC review.
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l 2/17/90 At the end of this inspection period, reactor power was j
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at 70%; and, power ascension to 100% power was continuing.
1.2 Control Room Tours L
Routine tours of the control room were conducted by the inspectors during which time the following documents were reviewed:
l Control Room and Group Shift Supervisor's Logs;
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Control Room and Shift Supervisor's Turnover Check Lists;
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Reactor Building and Turbine Building Tour Sheets;
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Standing Orders; and,
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Operational Memos and Directives.
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No unacceptable conditions were identified.
'1.3 Facility Tours
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Routine tours of-the facility were. conducted by the inspectors to
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make an. assessment-of the equipment conditions, personnel safety, and procedural adherence and regulatory requirements.
The following areas were inspected:
l Turbine Building
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Vital'.Switchgear Rooms
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Cable Spreading Room
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Diesel _ Generator Building
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Reactor Building
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The following additional items were observed or verified:
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Fire Protection:
Randomly selected fire extinguishers were accessible and i
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inspected on schedule, j
i Some problems with several fire doors were noted.- This j
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consisted of the door not closing properly. The licensee was informed. Hourly fire watch was instituted.
Ignition sources and' combustible materials were controlled
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in accordance with the licensee's approved procedures.
Appropriate fire watches or fire patrols were stationed
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when equipment was out of service.
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Equipment Control:
Selected jumpers and equipment mark-ups were reviewed to
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ensure they did not conflict with technical specification requirements.
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Vital Instrumentation:
I Selected instruments appeared functional and' demonstrated
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parameters within Technical Specification Limiting Conditions for Operation.
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Housekeeping:
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Plant housekeeping and cleanliness were in accordance with;
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approved licensee programs.
Minor housekeeping deficiencies which were identified were corrected by the licensee. No other unacceptable conditions were identified.
-2.0 Fire-Protection Deluge System
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On 1/23/90 the licensee-received a trouble alarm for fire area 4A deluge system. An hourly fire watch was established; and, a maintenance work request (short form) was prepared to repair the problem.
Deluge system 4A is in the cable spreading room and is separated into two
zones 1 and 2.
The detectors are installed such that cross zone coverage is provided. The deluge system requires signals from both zone 1 and zone 2 detectors to automatically actuate. The alarm function is available from any detector.
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While working on the maintenance short form on 2/8/90 the licensee realized'the detectors for zone I were inoperable.
This made the automatic. actuation capability of deluge system 4A also inoperable.
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licensee wrote a deviation report and established a continuous fire watch as required by plant technical specifications. Necessary repairs were made to=the module box and the system was-brought back to service within a short period of time.
'The licensee is currently reviewing the event. This item will remain unresolved pending NRC review of the licensee's evaluation.
(UNR 50-219/90-03-01).
3.0 Main Steam Isolation Valve NS03A During the 120-8 outage, the licensee' identified a dash pot oil leak and a body to bonnet steam leak from one of the inboard main steam line isolation valves, NS03A.
l-Although the same valve was found to have an oil leak during the May 1989 unplanned outage, the points of leakage were not the same. The oil in the dashpot is designed to control the valve stroke time. An excessively
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rapid closing of the MSIV could create an unacceptable pressure transient.
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The licensee determined that the valve stroke time was not affected and l
repaired the oil leak.
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The steam leak was also repaired during the 12V-8 unplanned outage by Leak Repair Company.- The inspector reviewed the work package. A clamp was installed around the bonnet flange, the inside of which was injected with Fermanite 2X material to seal the body to bonnet area leak. The installation of the clamp was not considered a temporary variation as the installation of the clamp did not affect system function or operation.
The-licensee determined that because of the weight of the clamp, the additional loading was acceptable and seismic qualification was not affected. A final injection of Fermanite was made during startup at 1000 psig. reactor pressure.
The leak was minimized to a very small value. The licensee evaluated it as acceptable. A permanent repair is scheduled to be made during 13R outage.
The work package did not include any QA paperwork documenting the acceptability of the vendor' supplied Fermanite material.
The licensee
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later identified that a QA receipt inspection was not performed before the Fermanite material was accepted for installation.
This item is unresolved. (UNR 50-219/90-03-02).
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4.0 Drywell Wall Thinning
During outage 12V-8, the licensee performed ultrasonic measurements of the drywell wall thickness. The results showed that the most limiting portion of the drywell had shifted f rom the sand bay area to the 51-foot elevation and the most conservative estimate of the time when minimum code wall thickness would be reached had changed from June 1992 to June 1991.
A telephone conference was initiated by the licensee to inform the NRC about their preliminary findings.
During the conference, the licensee stated that a copy of the revised safety evaluation will be provided to the NRC Project Manager and the resident inspectors.
5.0
"A" Recirculation Pump Discharge Valve On 1/10/89, a plant shutdown was commenced when the "A" recirculation discharge valve failed to close and the recirculation loop was placed in an isolated condition. When the licensee was able to place the loop in an idle configuration, the plant shutdown was secured and the plant returned to full power.
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Technical specifications allow continued plant operation with one loop in an idle configuration.
In an idle loop configuration, the recirculation pump is stopped with the discharge valve shut and the discharge bypass valve and the suction valve open.
If the suction valve is shut, the
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recirculation loop is considered isolated and the plant must be in cold
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shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The "A" recirculation loop was isolated during an evolution to remove the
"A" recirculation _ pump motor generator from service for maintenance.
The sequence to remove the motor generator from service required shutting the
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-10-discharge valve and stopping the recirculation pump. When the operators j
attempted to shut the "A" discharge valve, the valve's open indication
.i went out; however, the valve's close indication did not come.on.
Believing that this was a potential valve position limit switch problem.
'l the "A"' recirculation pump was stopped.
The operators immediately noted l
that there was excessive backflow through the "A" recirculation loop and I
concluded that the discharge valve was not fully shut. The "A"
recirculation pump suction valve was shut to prevent excessive backflow through the loop.
Inspection of the valve showed the stem nut was damaged and pieces of brass from the stem nut were imbedded in the stem threads.
Additionally, there was stem thread damage. The stem nut was replaced,
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and the stem threads were repaired. The motor operated valve testing
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(MOVATS) signature performed af ter the repair was satisfactory.
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failure of the valve to fully close on 1/10/90 was attributed the the j
damaged stem. nut and stem threads; however, a definitive root cause for the as-found condition could not be determined.
The licensee's actions in regard the the failure of the "A" recirculation
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pump discharge valve to fully close were reviewed.
The inspector
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concluded the actions taken by the licensee were adequate.
No
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unacceptable conditions were identified.
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6,0 Recirculation Pump "A" Seal Failure l
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"A" recirculation pump No I seal failed and the No. 2 seal started to fail. The first indication that the
.No; 1. seal failed occurred on 1/10/90 when the No. 2 seal cavity pressure.
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increased to 940 psig. The licensee stated it was possible that seal damage occurred during the recirculation discharge valve event during
which reverse flow through the pump occurred.
After the failure of the No I seal, the No. 2 seal started to show indications that it was failing. These indications included increasing seal temperatures and decreasing No. 2 seal cavity pressure which showed excessive flow by the seals. Additionally, drywell unidentified leak rate was increasing.
i On 1/30/90, the reactor power was reduced to 87% to reduce the high seal temperature. As the recirculation pump "A" seal temperature continued to increase, the MG set speed controller was locked up to preclude pump speed changes and further seal damage. The unidentified leak rate continued to increase.
The licensee began preparing for seal replacement. A temporary change was made to the plant operating procedure to change seal temperature for plant shutdown from 160 degrees F to 170 degrees F.
On 1/31/90, the recirculation pump seal temperature increased to 163 degrees F.
The licensee commenced an orderly evolution to remove l
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-11-h recirculation pump "A" from service. This evolution was well planned and executed.
After removal of "A" recirculation pump from service, the unidentified leak rate _was initially decreased. The leakage, however, started to
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increasing again. On 2/6/90, the drywell unidentified leak rate was 4.78
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gpm and exceeded the licensee established criterion of 4.75 gpm for plant shutdown. A controlled reactor shutdown was commenced; and, the outage
12U-8 began.
Significant leakage was identified from the "A" reci_rculation pump seal.
The pump seal was replaced with a rebuilt seal. The total personnel exposure for this work of 15 rem, exceeded the original estimate of 5 rem.
At the end of this-inspection period, NRC review of the seal replacement radiological planning for this job was in progress.
7.0 Isolation Condenser Steam Leak
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Isolation condenser steam line valves V-14-31, 32 and 33 developed packing leaks with V-14-31 leaking the most. A revision was made to Station Procedure 225.0, "Backseating and Unbackseating Station Valves," to allow
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r backseating these valves. During the controlled shutdown on 2/6/90, valve V-14-31 was backseated and the packing was tightened to reduce leak.
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After;the outage the valve was left in the normal condition with the leak stopped.
The revision to Procedure 225.0 and its associated safety determination
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were reviewed by NRC inspectors. As the steam leak through these valves constitutes a leakage path that bypasses the drywell, inspectors questioned the impact on accident doses. With a 20 gpm assumed leakage, through the valve packing, the licensee calculated an additional Design Basis Accident site boundary dose of 330 mrem child thyroid and 1,82 rem whole body accident dose from this leakage.
Inspectors did not have any l
further questions.
8.0 Core Spray Keeo Fill Pumps On 1/10/90, maintenance was performed on the core spray booster pump differential pressure switch, RV-408, and the breaker to core spray
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booster pump NZ038. Based upon the expected short duration of the maintenance activities, the operators elected to declare the entire system inoperable versus one core spray booster pump. This decision was based on
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their assessment that it was better to declare both pumps inoperable rather than to put one pump out of service for a longer period of time in order to perform an operability test on the remaining pump.
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The Core Spray System has a keep fill pump which keeps the core spray pump l
discharge line full of water to prevent water hammer upon system L
actuation. An interlock exists, however, which would cause the minimum flow valve to fail open if a core spray breaker is racked out.
If this
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-12-valve fails open, the keep fill pump flow would be diverted through the minimum flow line and the pump would go to runout.
Subsequent pump failure can potentially occur. To prevent the system keep fill pump going to runout, the operators elected to secure the core spray keep fill pump.
Station Procedure 308, Rev. 39. " Emergency Core Cooling System Operation,"
specifies provisions to install jumpers to prevent the minimum flow valves from failing open when a core spray breaker is racked out for maintenance.
The implementation of the jumpers to keep the minimum flow valve closed and the keep fill pump running would prever.t a water hamn.er if system were called upon to initiate.
The inspector reviewed the events of this maintenance evolution and concluded that the operator's decisions were acceptable. The operator's decision to declare the system inoperable to minimize the out of service time of the core spray booster pump was well founded.
Although the decision to secure the keep fill pump was acceptable, the inspector believed it would have been prudent to jumper the minimum flow valve closed to allow the keep fill pump to continue to operate. This action would have eliminated a potential water hammer if Core Spray System 2 had initiated.
No unacceptable conditions were identified.
9.0 Engineered Safeguards Feature System Walkdown The inspector performed a system walkdown of the Standby Gas Treatment System (SGTS) on 1/21/90 and 1/22/90. The SGTS is a plant atmosphere cleanup system which functions as a barrier between the radiation source and the environs during an emergency condition.
The walkdown included review of the system lineup procedures and drawings with the actual system configuration, review of completed valve and electrical lineup sheets, and observation of housekeeptng, component labelling, instrument calibration, local and remote instrument indications and system component material condition.
Several observations were made during the system walkdown. These observations were brought to the attention of Operations Management. The following is a list of these observations.
The system lineup procedure was compared with system drawings. The
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SGTS flow diagram, drawing No. 3D-822-21-1000, Rev. 5, showed the inlet dampers to the SGTS fans designated as DM-28-0049 and DM-28-0050. However, the system lineup procedure, Station Procedure 330, Rev. 17, specified that the inlet damper valves were not yet assigned component numbers. The licensee plans to update the procedure.
The inspector observed that the position of the inlet dampers to the
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SGTS fans were locked opened.
The system lineup procedure specified the valve positions be in the " locked throttled" position.
Additionally, the last valve lineup performed in February 1989 was
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signed off with these valves specified in the " lock throttled" position.
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Plant Engineering stated that the position of the inlet dampers, although presently in the open position, can potentially be throttled if it is required to establish a SGTS flow rate of between 2340 and 2860 sefm. However, Plant Operations stated that these valves have never been required to be throttled to meet the flow requirements.
Plant Operations plans to change the procedure to indicate the valve
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i positions as " locked open".
The electrical checkoff list for SGTS required that breaker No.13 in
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Continuous Instrument Panel No. 3 be in the "0N" position. This breaker was labelled " Panel 11F, NS03A&B, NSO4A&B, V-6-395 logic" and supplies power to the solenoids for V-28-17. V-28-18, V-28-47, V-27-1 and V-27-2.
These valves were containment isolation valves which allow exhaust from the Drywell and Torus to the SGTS.
The inspector noted that in the last electrical lineup, which was performed in February 1989, the operators annotated on the checkoff sheet that breaker No. 13 was a spare breaker. No signofis were evident that the breaker No. 13 was in the "0N" position. No deviation report was initiated to resolve the discrepancy.
Although a deviation report should have been written in February 1989, the inspector concluded (based upon previous inspection reports and enforcement conferences) that there has since been a substantial increase in site personnel's awareness to document discrepancies for resolution.
Licensee review concluded breaker No. 13 was the correct power supply to these SGTS solenoids.
System walkdown verified the breaker was in the correct position. At the end of this inspection period, the licensee was continuing their review of the discrepancy on the last electrical lineup sheet.
The inspector noted several components were either not tagged or had
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been labelled with masking tape which was difficult to read.
The licensee has since placed temporary brass label tags on the
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components. The inspector noted, however, that a labelling program had been initiated by the licensee last year to standardize and ensure permanent labels on all major components and valves. The
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program has been effective in identifying deviations between as-built configuration, and system procedures and drawings as well as labelling deficiencies. At the time of the SGTS walkdown, the SGTS had not yet been reviewed under this program.
The inspector noted several housekeeping deficiencies in the area of
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SGTS. These deficiencies included a ladder standing vertically next to V-28-28 and an unrestrained fire extinguisher.
These deficiencies were corrected by Operations.
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l Overall, the inspector concluded the SGTS would perform its intended function. Deficiencies noted by the inspector are being addressed by Operations Management.
No unacceptable conditions were observed.
10.0 Monthly Maintenance Observation During an Emergency Service Water (ESW) System I pump operability and inservice test on 1/17/90 the System I keep fill line check valve was found to be banging. The keep fill line provides water from the service water system to keep the ESW pnp discharge line full, which reduces the possibility of a water hammer upon pump start. The licensee decided to replace the valve; however, a spare valve was not readily available.
Administrative controls were instituted requiring the operators to close the keep fill line manual valve upon a system actuation.
The licensee obtained the required spare part and replaced the valve on 1/23/90. The inspector reviewed the work package, system tagout, QC hold points and observed performance of the repair.
A visual inspection of the inside of the replaced valve indicated a loose disk nut and damaged cotter pin.
This was what the licensee expected as a previous design review indicated that the disk nut and cotter pin arrangement of a swing check valve was susceptible to wear due to valve chattering.
During the maintenance, while the keep fill line was isolated, the licensee ran one ESW pump in each system to keep the system full. While starting the ESW pumps, the operators noted that Procedure 301,
" Containment Spray /ESW Operating Procedure," did not contain instructions to valve in the differential pressure (dp) gauges for the heat exchanger.
From the pump discharge pressure and heat exchanger outlet pressure the operators conservatively verified that the heat exchanger baffle plate dp limit was not exceeded.
The licensee wrote a deviation report to review and correct this.
No unacceptable conditions were identified.
11.0 Monthly Surveillance Observation The inspector observed parts of the following I & C surveillances on 1/25/90 and 2/11/90 respectively:
610.3.205 - Core Spay System II Instrument Channel Calibration and Test 519.3.011 - Scram Discharge High Water Level Test and Calibration The inspector verified proper authorization was made prior to the starting of the surveillances, communication with the control room was maintained, job specific RWP's were obtained as required, personnel were wearing dosimetry as required by the RWP, and test instrumentation was within its calibration due date. Within the scope of the inspection, no unacceptable conditions were identified.
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12.0 Temporary Instruction 2515/104:
Inspection of Fitness For Duty Initial
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The purpose of Temporary Instruction (11) 2515/104 was to determine
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whether required training was being conducted to implement the Fitness For Duty (FFD) program and to provide the NRC with information on the scope of initial training being implemented by the industry.
The TI required the resident inspector to attend one FFD policy awareness training session for general employees, one FFD training session for supervisor personnel and
one FFD training session for those personnel required to perform escort duties.
The inspector attended initial FFD training given to the General Office Review Board (GDRB) members on 1/17/90. The licensee implemented their FFD program to meet 10 CFR 26 requirements on 11/1/P?. General employee and escort training was combined in a 4-hour sessiot This training was combined because the licensee's policy was that anyone with unescorted access to the site can have escort duties.
The supervisor training included the four-hour general employee / escort training and an additional
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one-hour supervisory training session.
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The training sessions were well presented and questions concerning the program were encouraged.
Both film and video were used in addition to lectures.
The inspector noted that Human Resources was responsible for the initial training and verification that all personnel with unescorted access had received the training.
The Training Department will subsequently be responsible for this training and will incorporate the training as part of site access requirements and requalification.
No unacceptable conditions were identified.
13.0 Observation of Physical Security During daily tours, the inspectors verified that access controls were in accordance with the approved Physical Security Plan, security posts were properly manned, protected area gates were locked or guarded and that isolation zones were free of obstructions.
The inspectors examined vital area access points to verify that they were properly locked or guarded and that. access control was in accordance with the security plan.
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14.0 Enforcement Conference On February 16, 1990, an enforcement conference was conducted at the NPC-Region I office regarding apparent violations identified in Inspection Reports 50-219/89-06 and 89-09.
The issues discussed were:
the effectiveness and enhancements to the Preliminary Safety Concern Process; the interrelationship between the Core Spray System and the Automatic Depressurization System; single failure vulnerabilities in the Standby Gas Treatment System; and, design weaknesses in the Containment Spray System.
The licensee's presentation l
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Conclusions of the conference will be transmitted under separate cover.
l 15.0 Onsite Review of Licensee Event _ Reports (LERs)
During this inspection period, Licensee Event Reports were reviewed to determine the adequacy of event assessment, the root cause determination,
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corrective actions, generic applicability, consideration and completeness i
and accuracy. The following LERs were reviewed.
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LER 89-10: This LER discussed two 10 CFR 50 Appendix R concerns associated
with the isolation condenser system.
These concerns and licensee's
corrective action were reviewed in Inspection Report 50-219/89-07.
The first concern involved a fuse common to both Appendix R and non-Appendix R circuits which could render control power unavailable to the
isolation condenser condensate return valve V-14-35. As indicated in i
Inspection Report 50-219/89-07, the licensee installed a modification to the circuit to correct the problem.
This concern was considered resolved in Inspection Report 50-219/89-07.
The second concern was that a fire in certain areas of the plant could simultaneously disable the isolation condenser high flow sensors or associated logic circuitry, and the power and control cables to the AC powered isolation condenser valves. As a result, a spurious closure of all the isolation condenser valves and inability to open the valves could occur with resulting unavailability of the designated decay heat removal system.
i The licensee developed a plant modification to correct the above deficiency and was waiting for an outage of two weeks or more to complete the installation.
In the interim an hourly fire watch had been established for the areas involved.
In addition, the licensee indicated that an evaluation has been completed to assure that undesirable spurious isolation condenser isolation due to a high steam flow logic initiation resulting from fire can be mitigated.
This evaluation did not identify any concern.
LER 89-11: This LER discusses the events leading to a manual scram of the reactor on 4/22/89. During a planned shutdown evolution while the reactor was at around 2% power the mechanical vacuum pump was placed in service.
However, the operator failed to properly align the seal water makeup supply to the seal water tank.
Continued operation of the vacuum pump depleted the seal water tank inventory such that the mechanical vacuum pump was operating without seal water makeup.
This caused a decreased condenser vacuum and the reactor was manually scrammed.
A review of this event, including the analysis of the cause of the occurrence and corrective actions, is presented in Inspection Report 50-219/89-10.
The licensee determined that the operator error resulted from not having the procedure in hand while performing tne evolution.
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Plant Procedure 106, " Conduct of Operation and 107, " Procedure Control,"
were revised to add the specific requirement to have procedures in hand while performing plant evolutions.
The exceptions to this requirement were controlled by the Standing Order #41. The inspector verified that
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added to this exemption list.
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LER 89-12: On 5/20/89, while attempting to remove the mode switch key, after the switch was moved from " shutdown" to " refuel" position, the
- witch moved out of position and generated a scram signal.
Previous to
the switch manipulation, the plant was already in a cold shutdown condition with reactor vessel vented, hence no rod movement occurred. The licensee determined that the reactor protection system responded normally.
The cause of mispositioning the switch while attempting to remove the key was determined to be binding of the key lock and mechanical wear of the mode switch. The licensee lubricated the key to ease the binding and is planning to replace the mode switch during the next refueling outage.
LER 89-13: During a plant startup on 5/8/89, the isolation condenser condensate return valve V-14-35 was being cycled every 100 degrees during heatup as required by the plant procedures. After opening the valve at 260 degrees, es the valve was given a close signal, it moved back to its closed position; however, the operator motor was not stopped by the torque switch.
The motor finally tripped on overload protection, and the licensee declared the isolation condenser system "B" inoperable.
The licensee's response to the inoperable isolation condenser was reviewed in Inspection Report 50-219/89-12.
The licensee determined the cause to be a broken roll pin in the torque switch and replaced the torque switch.
Operability of the valve was verified. MOVATS current signature taken after torque switch replacement did not provide indication of valve stem damage.
The possibility of valve seat damage was reviewed with the vendor who concluded that the resultant stall thrust on the valve seat would not damage the seat. The licensee considered the torque switch roll pin railure to be an isolated event.
LER 89-14: This LER addressed a missed reactor coolant sampling for dose
equivalent I-131 following a reactor power change greater inan 15% on 5/15/89. The licensee evaluated the root cause to be a personnel error exacerbated by an incorrect action statement for the sampling requirement in the technical specification log sheet (TSLS).
The licensee corrected the action statement in the TSLS.
In addition, the licensee has identified several plant procedures which should also be revised.
These revisions are currently scheduled for completion by 6/30/90.
LER 89-15:
This LER described the main generator overexcitation event on 5/18/89, which resulted in a generator trip, reactor scram, but did not automatically transfer power to the startup (S/U) transformers.
The incident, plant and licensee response and licensee's corrective action were reviewed in Inspection Reports 50-219/89-12 and 16.
The licensee has i
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completed a study to evaluate the need for modifying the plant such that S/U transformers could automatically energize the 4160 volt buses
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following an overexcitation trip of the main generator. This modification is incorporated in the main generator protective relay upgrade and is
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planned during the 13R refueling outage.
LER 89-16: This LER describes the 6/25/89 trip of the main generator due to a phase differential condition caused by a fault in main output transformer M1A. The trip of the main generator resulted in a turbine trip and an anticipatory reactor scram.
The licensee's corrective was to
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install a temporary variation for operation with one main transformer.
The plant and licensee's response to the trip were evaluated in Inspection Report 50-219/89-14 and found acceptable. The apparent cause of the fault in M1A was an internal winding failure.
The licensee has completed their investigation of the failure of M1A on 6/25/89 and a failure of the other transformer (MIB) which occurred on 7/11/89.
Results of this investigation, including the root cause and corrective action, are described in the next paragraph.
LER 89-17: This LER discusses the 7/11/89 trip of the main generator due
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to a fault in the operating main output transformer (M1B) which resulted in a turbine trip and an anticipatory reactor scram.
The Oyster Creek
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plant is provided with two main output transformers.
However, due to a failure of the other unit (M1A) on 6/25/89, only one transformer was on line.
The licensee's response to the transformer failure and the corrective actions were reviewed in Inspection Report 50-219/89-16. A preliminary root cause analysis was performed by the licensee which indicated that reduced cooling oil flow through the windings was the probable root cause.
The reduced oil flow resulted from a ruptured oil box which occurred years ago and was found and repaired during the 12R outage. The reduced oil flow caused slow thermal degradation of the winding insulation.
The repair performed during 12R outage which also included jacking of the l
windings caused damage to the brittle insulation. This eventually caused a phase to phase fault.
The licensee has completed the investigation into the root cause of the M1A and M1B failure and is currently updating the LER to incorporate the final root cause determination. The conclusion of the root cause analysis confirmed the pitliminary determination.
LER 89-18: This LER discussed an event where a loose wire was identified in the high pressure actuation circuit for the Electromatic Relief Valve (EMRV) logic during perforcance of a surveillance on 7/29/89. The licensee believed that the wire could have become loose during the previous surveillance performed on 6/28/89, as the "D" EMRV actuated normally upon a high pressure on 6/25/89,
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The licensee determined that only the high pressure relief function for the D EMRV was inhibited. The Automatic Depressurization System and i
manual functions were unaffected.
The other four EMRVs were functional, together with the safety valves.
The licensee indicated that the safety valves are sized such that during a failure to scram event the high pressure safety limit would not have been exceeded.
Licensee's short term corrective action was to verify proper connection for the loose wire and replace the wire. A visual inspection and i
tightness check on all the connections of the five.EMRV controllers was
also performed. As a long term corrective action the licensee evaluated the feasibility of revising the surveillance procedures for the EMRVs to
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verify the continuity through all portions of the circuit and found it not feasible. The licensee plans to incorporate a requirement in the subject surveillance procedure to check the terminals in the controllers for
tightness at the completion of surveillance.
This will identify if any
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wire becomes loose during connection of the test equipment.
LER 89-20: This LER discussed the event when the knife switch used to select DC control power to the safety related 480 AC unit substation 182 was found to be positioned to a non-safety related source. A detailed i
inspection of the event, including licensee's discovery and corrective actions was performed and documented in Inspection Report 50-219/89-23.
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An enforcement conference, documented in Inspection Report 50-219/89-29, was held with the licensee on 12/5/89.
LER 89-21: On 9/22/89 while operating at full power, the plant scrammed
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on an anticipatory turbine trip signal. The technicians perforning a surveillance on reactor water level transmitters returned a transmitter to service without removing the test equipment. When the instrument reference leg root valve was opened according to the procedure, the reference leg of the instrument and four others were vented through this
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opening. This generated a false high reactor level signal and a turbine
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trip.
Inspection Report 50-219/89-21 discussed the event and licensee's L
review. The control room operators' response and the licensee's
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E corrective action were found satisfactory. The licensee counseled the (
technicians involved and made the LER required reading for all Instrument L
and Control technicians. An NRC inspector noted that LER 89-21, revision 0, did not identify the safety system actuation and if the plant responded as designed. The licensee issued a Revision 1 to the LER on 1/12/90 to include these aspects of the event.
LER 89-22: This LER discusses a violation of the plant technical l
specification requirement, whereby there was no senior licensed operator
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in the control room for a period of six minutes on 10/5/89. This event
was reviewed in Inspection Report 50-219/89-21. The licensee's response to the event and corrective action was found satisfactory. A noncited I
violation NCV 89-21-05 was generated and closed out in that inspection l
report.
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16.0 Inspection Hours Summary t
Inspection consisted of 240 direct inspection hours out of a total of 460 r
inspector hours on site.
Thirty-nine of these direct inspection hours were performed during backshift periods.
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17.0 Exit Meeting and Unresolved Items A summary of the results of the inspection activities performed daring this report period was made in a meeting with senior licensee management
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L at the end of this inspection.
The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.
Unresolved items are matters for which more information is required in order to ascertain whether they are acceptable, violations or deviations.
Unresolved' items are discussed in paragraphs 2.0 and 3.0 of this report.
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ATTACHMENT I Personnel Contacted
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Licensee P_e_rsonnel F. Aller, Plant Materiel
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K. Barnes, Licensing Engineer l
- R. Barrett, Plant Operations Director
- G. Busch, Licensing Manager
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G. Cappadanno Technical Functions
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P. Cervenka,-Plant Operations Engineering J. Chartering, Plant Engineering t
P. Crosby, Plant Engineering J. De Blasio, Plant Engineering Manager B. De Merchant, Licensing Engineer
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.S. Dunsmuir, Plant Operations i
P. Fischler, Maintenance Superintendent
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- E. Fitzpatrick, Vice President & Director
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'V. Foglia, Technical Functions Manager J. Freeman, Plant Operations R. Gayley, Plant Engineering
R. Hendriksen, Plant Operations M. Husain, Plant Engineering
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D. Jones, Plant Engineering J. Logatto, Technical Functions 0. Perez, Plant Engineering
- D. Ranft, Engineering Manager S. Reininghaus, Control Room Operator
- J. Rogers, Licensing Engineer r
A. Rone, Plant Engineering Director G. Sadaukas, EP & I P. Scallon, Plant Operations Manager C. Schilling, Plant Engineering
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T. Sensue, Plant Operations
M. Slobodein, Rad Con Director M. Szmidt, Human Resources
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NRC Personnel
- M. Banerjee
- E. Collins-
- D.
Lew-Denotes attendance at exit meeting.
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ATIAONEhT II
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OYSTER CREEK NUCLEAR GENERATING STATION i
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ENFORCEMENT CONFERENCE l
FEBRUARY 16,1990
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AGENDA
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I INTRODUCTION - M. LAGGART
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POTENTIAL SAFETY CONCERN (PSC) PROCESS - M. LAGGART
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I Ill DISCUSSION OF INSPECTION RESULTS - A. AGARWAL I
AUTOMATIC DEPRESSURIZATION SYST EM (ADS)/ CORE SPRAY -
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SYSTEM (CS) INTEROPERABILITY
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STANDBY GAS TREATMENT SYSTEM (SGTS)
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l 10 CFR 50, APPENDIX B CONCERN
IV CONCLUSIONS AND ENFORCEMENT POLICY APPLICABILITY-l M. LAGGART
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ISSUE i
WAS THE PSC PROCESS EFFECTIVE IN PROPERLY RESOLVING SIGNIFICANT SAFETY CONCERNS?
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PSC PROCESS
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THE PSC PROCESS IS A REVIEW MECHANISM TO IDENTIFY AND RESOLVE CONCERNS.
IT IS ONE OF MANY REVIEW MECHANISMS THAT EXIST WITHIN
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EXAMPLES OF SUCH MECHANISMS INCLUDE:
PLANT TOURS SURVEILLANCE TESTING DRAWING VERIFICATION PROGRAM
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ELECTRIC LOAD STUDY SYSTEM FUNCTIONAL AUDITS PLANT MODIFICATION PROCESS SAFETY REVIEW PROCESS GENERAL OFFICE REVIEW BOARD INDEPENDENT ON SITE SAFETY REVIEW DEVIATION REPORTS QUALITY ASSURANCE AUDITS SAFETYISSUES ASSESSMENT PROGRAM RISK MANAGEMENT EFFORT NUCLEAR SAFETY COMPLIANCE COMMITTEE
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EXTERNAL MECHANISMS ALSO CONTRIBUTE TO THE IDENTIFICATION AND RESOLUTION OF PROBLEMS.
INPO SIGNIFICANT EVENT REPORTS
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VENDOR SERVICE INFORMATION LETTERS
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NRC INITIATED BULLETINS, INFORMATION NOTICES,
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INSPECTION REPORTS, AND GENERIC LETTERS.
- THE INTENT OF THE PSC PROCESS IS TO PROVIDE A COMPREHENSIVE AND THOROUGH REVIEW OF THOSE CONCERNS RAISED BY INDIVIDUALS.
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ORIGINAL PROCEDURE ORIGINAL PSC PROCEDURE ISSUED ON 12-31-81 WAS DEFICIENT
IN SEVERAL AREAS
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ALTHOUGH DEFICIENCIES EXISTED, THE IMPLEMENTATION WAS
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EFFECTIVE.
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PERSONNEL FREQUENTLY WENT BEYOND THE SCOPE OF THE j
PROCEDURE TO RESOLVE CONCERNS.
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PSC RE-REVIEW EFFORT IN 1989 SUPPORTS THIS i
CONCLUSION.
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t THE RESULTS OF THE RE REVIEW WERE DOCUMENTED AND
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SUBMITTED TO NRC BY LETTER DATED MARCH 21,1989.
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PSC RE REVIEW
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DETERMINE IF VALID SAFETY ISSUES MAY STILL EXIST FOR
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PREVIOUSLY CLOSED SAFETY CONCERNS.
RE-REVIEW CONDUCTED MARCH 18 AND 19,1989.
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TOTAL OF 104 CLOSED PSCs SINCE EARLY 1983
RE REVIEW CONCLUSION j
REASONABLE ASSURANCE THAT NO UNIDENTIFIED SAFETY
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ISSUES ASSOCIATED WITH PSCs.
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NRC INSPECTION NO 89-07 STATES
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" THE INSPECTOR CONCLUDED THAT THE LICENSEE
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RESPONSE TO NRC REQUEST TO REVIEW CLOSED PSCs WAS PROMPT, THOROUGH AND EFFECTIVE. THE LICENSEE REVIEW PROVIDED CONFIDENCE THAT THE PSC PROCESS HAD NOT LEFT SIGNIFICANT SAFETY QUESTIONS UNRESOLVED."
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REVISED PSC PROCEDURE l
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PSC PROCEDURE UNDERWENT A SIGNIFICANT REVISION IN 1989 WHICH PROVIDED THE FOLLOWING ENHANCEMENTS:
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PROVIDES DEFINITIVE CRITERIA FOR WHA 1 CONSTITUTES A
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SAFETY CONCERN.
EMPHASIZES THE RESOLUTION OF A SAFETY CONCERN RATHER
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THAN JUST THE REPORTABILITY ASPECT.
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CONCERN TO THE COGNIZANT TECHNICAL DEPARTMENT.
ESTABLISHES REQUIRED TIME FRAMES FOR THE l.
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DETERMINATION OF REPORTABILITY AND/OR THE EXISTENCE
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OF A SAFETY CONCERN.
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REQUIRES THAT UPPER MANAGEMENT APPROVE THE FINAL l
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REVISED PSC PROCEDURE HAS DRAMATICALLY IMPROVED THE
TIMELINESS IN RESOLVING PSCs.
UPPER MANAGEMENT IS CLOSELY MONITORING THE TIMELINESS
ASPECT.
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INSPECTION REPORT _RESULTS l
CORE SPRAY SYSTEM INSPECTION REPORT 89-06 IDENTIFIED SIX INSYANCES WHEN A
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CS SYSTEM WAS REMOVED FROM SERVICE.
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i INSPECTION REPORTIDENTIFIED ONE ITEM AS AN APPARENT
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VIOLATION OF TECHNICAL SPECIFICATION.
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INSPECTION REPORT EXPRESSED CONCERN THAT ORIGINAL PROBLEM i
l DESCRIBED IN PSC 86-006 WAS NOT PROPERLY DISPOSITIONED.
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INSPECTION REPORT RESULTS STANDBY GAS TREATMENT SYSTEM INSPECTION REPORT 89-06 CONCLUDED TH AT PSC 84-018,
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CONCERNING A SINGLE FAILURE WHICH COULD PREVENT AUTO INITIATION OF SGTS, WAS A SIGNIFICANT SAFETY CONCERN'NOT PROPERLY RESOLVED BY GPUN.
I 10 CFR 50 APPENDIX B INSPECTION REPORT 89-06 CONCLUDED THAT PSCs84-018 AND
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86-006 WERE SIGNIFICANT SAFETY CONCERNS NOT PROPERLY RESOLVED BY GPUN AND lDENTIFIED THAT AS AN APPARENT VIOLATION OF 10CFR50 APPENDIX B, CRITERlON XVI.
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ADS / CORE SPRAY.INTEROPERABILITY
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DESCRIPTION
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PSC 86-006 IDENTIFIED ANOMALY BETWEEN T.S. TABLE 3.1.1
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AND SECTION 3.4.A.3
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WITH ONE CORE SPRAY SYSTEM OUT OF SERVICE, ONE ADS
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ACTUATION CHANNEL IS COMPLETELY DISABLED.
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THE PSC EVALUATION CONSIDERED ONLY ADS ACTUATION l
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SENSOR LCO COVERED BY NOTE "i" OF THE TABLE 3.1.1
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THE ANALYSIS ASSUMED AVAILABILITY OF OTHER ADS
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CHANNEL, WHICH HAS REDUNDANT SENSORS FROM OTHER CORE
SPRAY SYSTEM.
NO REFERENCE TO TABLE 3.1.1 NOTE "h" UNDER TECH SPEC - , SECTION 3.4.A 3
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GPUN INITIAL EVALUATION THE PSC PROCESS DID NOT IDENTIFY / RESOLVE CS/ ADS
INTEROPERABILITY, i
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THE PSC DISPOSITION ADDRESSED THE ALTERNATIVES TO THE
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PRESENT CONFIGURATION RATHER THAN TS COMPLIANCE, AND I
CONCLUDED THAT THE PRESENT DESIGN WAS MORE APPROPRIATE.
EMPHASIS WAS THAT IF CORE SPRAY WAS UNAVAILABLE,
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BLOWDOWN OF INVENTORY WITHOUT MAKEUP CAPABILITY j
WOULD REPRESENT A SIGNIFICANT SAFETY CONCERN.
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CORRECTIVE ACTION BA 328279 SCHEDULED FOR 13R TO REVISE CORE SPRAY / ADS
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INTERFACE.
IN THE INTERIM, GPUN IS FOLLOWING THE MORE RESTRICTIVE
-
LCO OF T.S. TABLE 3.1.1 UNDER THESE CONDITIONS. i.e.,
BRING THE PLANT TO COLD SHUTDOWN IF ONE CORE SPRAY SYSTEM IS OUT OF SERVICE.
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CONCLUSIONS i
>
SAFETY SIGNIFICANCE j
i
,
ADS AND CORE SPRAY SYSTEMS WORKTOGETHER FOR SMALL BREAK i
-
LOCA AT LEAST ONE TRIP SYSTEM OF ADS WAS AVAILABLE AT ALL TIMES
-
,
,
lNPUT LOGIC SWITCHES TO ADS ARE ALSO ALARMED IN THE
-
CONTROL ROOM ENSURING THAT OPERATORS WILL BE ALERTED TO CHANGING PLANT PARAMETERS
,
PROCEDURES PROVIDE GUIDANCE TO THE OPERATORS TO INHIBIT
>
-
ADS AND MANUALLY DEPRESSURIZE THE REACTOR IF REQUIRED
.
SAFETY SIGNIFICANCE IS MINIMAL
-
THE TS ANOMALY OR LACK OF CORRELATION BETWEEN CS AND ADS l
>
OPERABILITY LIMITS CAN BE VIEWED AS " TECHNICAL SPECIFICATION CASCADING."
,
THIS ISSUE IS PRESENTLY BEING LOOKED AT BY NRR PERSONNEL
-
AND WILL PROBABLY RESULT IN AN INTERPRETATION FROM NRC.
.
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>
PSC CONCERN WAS WITH A SINGLE FAILURE WHICH COULD PREVENT j
AUTOMATIC INITIATION OF SGTS
)
>
CONCLUSION OF PSC WAS THAT IT DID NOT REPRESENT A SAFETY CONCERN AND IT WAS NOT REPORTABLE.
INSPECTION REPORT 89-09, WHICH WAS TRANSMITTED UNDER THE
>
SAME COVER LETTER AS INSPECTION REPORT 89-06 CONCLUDED.
"THE SGTS AUTOMATIC START LOGIC WAS NOT ORIGINALLY
,
DESIGNED TO MEET SINGLE FAILURE CRITERIA. THE
'
INSPECTORS DETERMINED THAT LOSS OF POWER TO THE
>
l REACTOR BUILDING VENTILATION AND FILTER BANK HEATING L
COILS WOULD NOT STOP THE SGTS FROM PERFORMING WITHIN ITS DESIGN BASIS. THE LICENSEE DEMONSTRATED THAT THE SGTS COULD BE MANUALLY STARTED, DURING A DESIGN
'
BASIS ACCIDENT, WITHOUT EXCEEDING 10 CFR PART 100 EXCLUSION BOUNDARY DOSE LIMITS."
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INITIAL EVALUATION OF THE SGTS PSC WAS PROPER
>
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THIS DOES NOT REPRESENT A VIOLATION, A SAFETY CONCERN, j
OR AN INAPPROPRIATE RESOLUTION OF A PSC l
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10 CFR 50_ APPENDIX B
.-
PSC 84-018 (SGTS) RESOLUTION BY GPUN WAS SUBSEQUENTLY
>
DETERMINED BY NP.C TO BE APPROPRIATE.
THE RE REVIEW OF PSCs IN 1989 PROVIDED ASSURANCE THAT
THERE WERE NO UNIDENTIFIED SAFETY ISSUES ASSOCIATED WITH OYSTER CREEK PSCs (THE RESULTS WERE DOCUMENTED TO NRC BY LETTER DATED 3-2189)
NRC INSPECTION NO 89-07 STATES:
" THE INSPECTOR CONCLUDED THAT THE LICENSEE
...
RESPONSE TO NRC REQUEST TO REVIEW CLOSED PSCs WAS PROMPT, THOROUGH AND EFFECTIVE. THE LICENSEE REVIEW PROVIDED CONFIDENCE THAT THE PSC PROCESS HAD NOT LEFT SIGNIFICANT SAFETY QUESTIONS UNRESOLVED."
ADS /CS INTEROPERABILITY WAS JUDGED TO BE OF MINIMAL
>
SAFETY SIGNIFICANCE.
INAPPROPRIATE TO JUDGE A PROCESS AS INEFFECTIVE BASED ON
>
ONE EXAMPLE OF MINIMAL SAFETY SIGNIFICANCE.
THE PSC PROCESS HAS BEEN EFFECTIVE IN IDENTIFYING AND
RESOLVING SIGNIFICANT SAFETY CONCERNS.
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CONCLUSIONS AND ENFORCEMENT POLICY APPLICABILITY THE SAFETY SIGNIFICANCE OF THE ADS /CS INTEROPERABILITY j
VIOLATION IS MINIMAL.
.
PSC RE REVIEW PROVIDED CONFIDENCE THAT THE PSC PROCESS HAD
NOT LEFT SIGNIFICANT SAFETY QUESTIONS UNRESOLVED.
I
>
ENHANCEMENTS HAVE BEEN MADE TO THE PSC PROCESS.
t ENFORCEMENT POLICY IN 10 CFR 2, APPENDIX C WOULD CLASSIFY
>
THE ADS /CS INTEROPERABILITY AS SEVERITY LEVEL IV.
i
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EXAMPLE OF APPENDIX C STATES:
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"A LESS SIGNIFICANT VIOLATION OF A TECHNICAL
-
L SPECIFICATION LIMITING CONDITION FOR OPERATION WHERE THE APPROPRIATE ACTION STATEMENT WAS NOT SATISFIED WITHIN THE TIME ALLOCATED BY THE ACTION STATEMENT."
UPON RECOGNITION OF THE TS ANOMOLY, PROMPT AND
COMPREHENSIVE CORRECTIVE ACTION WAS TAKEN.
.
THE PSC PROCESS HAS BEEN AND IS EFFECTIVE IN IDENTIFYING AND
RESOLVING SAFETY CONCERNS.
,
_ _ _.. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ _.. _ _. _. _ _ _ _ _.. _. _ _ _, ~. _. _. _ _ _ _... _ _ _ _.. _ _ _.. _ _ _... _ _, _ _. _
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IAtti 3.1.1 PROI(CilV( IN51RuMINIAll0N RfquitfMENIS (CONIO)
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Reacter Modes Min. No. of Min. No. of in which function Operable or Instrument Must 6e operable Operating Channels Per
.
(trippedi Operable Action
. { p tion irlo Settine
@tdown Refuel starte Lug Trio systees irlo Systees teeutreda-G. -Automatic Deressertsetten 1.
High Drywell ( 3.5 psig M(v)
M(v)
M(v)
N 2(k)
2(k)
See note h Pressure 2.
Low-Low-Low 1 4*S" above R(v)
X(v)
M(v)
M
'2 See note h Reactor Water top of active i.evel fuel 3.
AC Weltage NA M(v)
X
2 Prevent auto depressuriaa-tien en less of AC power.
See note 6
h.
One instrument channel in each trip system may be inoperable provided the circuit which it operates in the trip system is placed in a simulated tripped condition, if repairs cannot be completed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> the reactor shall be placed in the cold shuduwn condition, if more than one instrument channel in any trip system becomes inoperable, the reactor shall be placed in the cold shutdown condition. Relief valve controllers shall not be bypassed for more than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> (total time for all controllers) in any 30 day period and only one relief valve controller may be bypassed at a time, l.
The interlock is not requirec during the start-up test program and demonstration of plant electrical output but SN.l! be provided following these actions.
3.4 EMERGENCY C001.ING Applicability: Applies to the operating status of the emergency cooling systems.
Objective:
To assure operability of the emergency cooling systems.
Soecifications:
A.
Core Soray System 3.
If one core spray systen loop or its core spray header aP instrumentation becomes inoperable during the run mode, the reactor may remain in operation for a period not to exceed 7 days provided the remaining loop has no inoperable components and is demonstrated daily to be operable.
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CORE SPRAY ' ADS' INTERFACE L(EXISTING)
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DIVISION
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PSC 87-03 (INITIATED ON MARCH 25,1987)-
.*
- -
DESCRIPTION
.
l INTRODUCTION OF A LO-LO WATER LEVEL SIGNAL WILL q
-
.
RE-ALIGN CSS VALVES TO DRYWELL.
.>
SAFETY SIGNIFICANCE
,
!
IF MANUAL CSS /ESW PUMPS ARE RUNNING IN TORUS COOLING
-
MODE, VALVE RE-ALIGNMENT WOULD INADVERTENTLY SPRAY
,
THE DRYWELL AND A POTENTIAL IMPLOSION OF THE DRYWELL
.
DUE TO RAPID DEPRESSURIZATION VIA SPRAYS COULD I
OCCUR.
- CORRECTIVE ACTIONS
.
PROCEDURE 310 WAS REVISED TO INCLUDE A PRECAUTION
-
AND LIMITATION FOR DYNAMIC TESTING.
t PROPOSE DELETION OF VALVE REALIGNMENT LOGIC ON LO-LO
--
-
WATER LEVEL.
ELIMINATE AUTOSTART LOGIC OF CSS.
-
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PSC RESPONSE WAS APPROPRIATE IN RESPONDING TO THE
,
CONCERNS IDENTIFIED.
,
>
->-
INSPECTION REPORT 89-06 STATES:
'
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"ANOTHER CONCERN THAT MAY BE INFERRED FROM THE PSC AND THAT WAS SPECIFICALLY DISCUSSED IN IR
^
50-219/87-04 IS THE INABILITY TO USE TORUS POOL COOLING (DYNAMIC TEST MODE) DURING CERTAIN ACCIDENT AND TRANSIENT CONDITIONS."
L PSC 87-03 ORIGINATOR DID NOT IDENTIFY THIS CONCERN, NOR
-
s DURING THE EVALUATION WAS THIS CONCERN IDENTIFIED AS AN L
ADDITIONAL ITEM.
,
PROPOSED CORRECTIVE ACTION IN THE PSC HOWEVER WOULD
-
HAVE RESOLVED UNIDENTIFIED CONCERN (DELETION OF VALVE REALIGNMENT LOGIC ON LO-LO WATER LEVEL).
.
?
PSC PROCESS IS NOT DESIGNED TO SEARCH OUT ALL PROBLEMS
>
THAT A SYSTEM MAY HAVE.
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.
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.
.
.
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PSC 89-003 DID ADDRESS SPECIFIC CONCERN OF INABILITY TO e
USE TORUS POOL COOLING.
'
.
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.THE INTENT OF THE PSC PROCESS IS TO PROVIDE A
.
COMPREHENSIVE AND THOROUGH REVIEW OF THOSE CONCERNS D
RAISED BY INDIVIDUALS.
l:
-
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' *
DURING RESOLUTION, PERSONNEL INVOLVED IN THE PROCESS MAY -
AND HAVE IN THE PAST ADDRESSED OTHER CONCERNS THAT THEY BECOME AWARE OF.
!
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.
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,
NO PROCESS CAN ENSURE THAT ALL TECHNICAL ISSUES WILL BE l
i IDENTIFIED.
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