IR 05000219/1990006
| ML20034B872 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 04/20/1990 |
| From: | Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20034B866 | List: |
| References | |
| 50-219-90-06, IEB-80-10, NUDOCS 9005010100 | |
| Download: ML20034B872 (32) | |
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V. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-219/90-06 Docket No.
50-219 License No.
OPR-16 Licensee:
GPU Nuclear Corporation 1 Upper pond Road Parsippany, New Jersey 07054 Facility Name: Oyster-Creek Nuclear Generating Station Inspection Conducted:
February 18 - March 17.1990
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Participating Inspectors:-
M. Banerjee, Resident Inspector E. Collins, Senior. Resident Inspector D. Lew, Resident Inspector W. Pasciak, Chief, FRSS Approved By:
b /c J / g WJb/W William _Ruland, Chief, Date
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Reactor Projects Section 4B Inspection Summary: Inspection Report No. 50-219/90-06 for February 18, 1990 i
through March 17, 1990
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Areas Inspected: The inspection consisted of.156 hours0.00181 days <br />0.0433 hours <br />2.579365e-4 weeks <br />5.9358e-5 months <br /> of direct inspection by resident and regional inspectors.
The areas inspected included a review of a degradation of a fire protection system (paragraph 1.2), multiple' control rod i
movement event (paragraph 1.3), reactor scram event (paragraph 1.4), plant startup with the rod worth minimizer bypassed (paragraph 1.5), reactor recircu-lation pump maintenance (paragraph 2.1),. contamination of the auxiliary boiler system (paragraph 2.2), skin contamination event (paragraph 2.3), monthly main-tenance observation (paragraph 3.1), monthly surveillance observation (para-graph 3.2), emergency preparedness quarterly drill (paragraph 4.0), main steam valve maintenance (paragraph 5.1) and licensee event reports (paragraph 6.0).
Results: Overall, the plant was operated in a safe manner. The promptness of the control room operators' actions in response to an Alternate Rod Injection (ARI) system initiation was excellent.
The licensee's failure to establish a continuous fire watch for an inoperable deluge system is a violation. A plant
startup conducted with the Rod Worth Minimizer bypassed is a violation. The licensee's failure to perform an ALARA review is a violation. Operating with the Auxiliary Boiler System contaminated in a manner contrary to station pro-cedures is a violation. The licensee's failure to perform a receipt inspection
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t is a noncited violation.
NRC review of the~ licensee's safety evaluation re-garding the contaminated auxiliary boiler and review of the licensee's imple-mentation of Bulletin 80-10 were left unresolved.- The critique of a radio-logical skin contamination event was thorough from a radiological' aspect; how-ever, the critique was fragmented in that nonradiological aspects were not
reviewed. The Plant Review Group (PRG) inappropriately determined that the movement of two control rods was not reportable in accordance with 10 CFR.
50.73.
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EXECUTIVE SUMMARY L
Inspection Report No. 50-219/90-06 This report covered inspection. activities from February 18, 1990 to March 17, 1990. During this period, one reactor scram occurred and one plant startup was conducted.
Reactor power was limited during the latter part of the inspection period because of condenser vacuum problems caused by suspected problems in the steam jet air ejector system.
Four violations were cited; one violation was
noncited; and, two items were left unresolved.
On February 20, 1990, a reactor trip was manually initiated when the Alternate Rod Injection (ARI) System actuated.
Inadvertent keying of a two-way radio in a control room area posted ~with signs prohibiting the use of any radio. caused both pressure trip units of the ARI logic to. actuate. The promptness of the control room operators to trip the reactor in response to the ARI system in-itiation was excellent, t
Events were observed during the inspection period which demonstrated weaknesses.
in the area of radiological controls. A complete ALARA review was not per-formed for the replacement of the "A" reactor recirculation pump bearing and the collective dose for that work was nearly 11 person-rem. The auxiii-i l
ary boiler system was contaminated. However, contrary to station procedure, I
the use of the auxiliary boiler system was not restricted, the cause of the
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contamination was not corrected,.the system was not decontaminated and an immediate safety evaluation was~not perforned. A skin contamination event occurred as a result of poor work practices and performing work outside the planned job scope, r
Events were observed during the inspection period which demonstrated weaknesses in the area of corrective actions. A trouble alarm for fire area 4A deluge system remained actuated for 16 days before appre 'iate corrective action as required by technical specification were taken. When the alarm was finally inve. Ligated, the fire protection deluge system 4A, zone 1, was determined to be inoperable.
Compensatory action to establish a continuous fire watch had not been taken for 16 days. A plant startup was commenced with the Rod Worth Minimizer bypassed contrary to technical specification requirements. An in-stance was noted involving the use of valve repair compound without the re-quired quality receipt inspection, thereby resulting in the use of material which was potentially in nonconformance with quality requirements.
Even after this issue was identified by NRC inspectors, licensee maintenance personnel were slow in documenting and resolving this deficiency.
Overall, the licensee operated the plant in a safe manner. Several weaknesses were identified in the area of radiological controls and corrective actions.
Although the licensee has in place several. plans for improvement, many of the results of these plans have not been realized. These events emphasize the l
weakness of the licensee's implementation and completion of the plans for im-provement in these ar as.
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TABLE OF CONTENTS i
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_1.0 Operations (71707, 93702)....................
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1.1 Chronology of Operational Events......,........
'l 1.2 Fire Protection Systein Degradation.............
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1.3 Multiple Control Rod Motion Event.
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1.4 Reactor Scram..........-..............
1.5 Plant Startup with Rod Worth Minimizer Bypassed
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1.6 Control Room Teurs.....................
1.7 Facility Tours........................
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2.0 Radiological Controls (30702, 90712, 93702)
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l 2.1 Reactor Recirculation Pump Maintenance.. -...
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2.2 Contamination of the Auxiliary: Boiler System....,
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2.3 Hot Particle on the Refueling Floor...........
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2.4 Assessment.................
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3.0' Maintenance / Surveillance (62703, 61726).............
3.1 Monthly Maintenance Observation............. -..
3.2 Monthly Surveillance Observation..............
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4.0 Emergency Preparedness (71707).................
5.0 Safety Assessment / Quality Verification (93702).........
5.1 Main Steam Valve Maintenance........
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6.0 Licensee Event Report Review (92700)..............
7.0 Inspection Hour' Summary.........
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8.0 Exit Meetings and Unresolved Items (30703)........... 26 ATTACHMENTS Attachment 1:
List of Personnel Contacted i
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DETAILS
1.0. Plant Operational Review
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Inspectors reviewed details associated with key operational-events that occurred during the report period. A summary of these inspection activi-ties follows.
- x 1.1 Chronology of Events At the beginning of'this inspection period, a reactor startup had just been completed and power ascension to 100% power was in pro-gress. The turbine had been placed on'line.
No technical specifi-cation action statements were in effect.
2/18/90 Reactor power reached 100%.
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2/20/90 The Alternate Rod Injection (ARI) System was inadvert-
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ently activated when a technician--inappropriately keyed a two-way radio. A manual scram was-inserted by the operators.
De-tails of this event are described in Paragraph 1.4.
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The unplanned outage, 12-U-9, commenced.
2/21/90 During plant cooldown, the "B" isolation condenser con-
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densate return valve (V-14-35) failed-to open when the operators l
attempted to operate the valve.
The cause was suspected to be
thermal binding. The "B" isolation condenser was declared in-operable.
Technical Specifications allow continued plant opera-
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tions for seven days with this system out of service.
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handwheel and tested satisfactorily later in the day. The "B" isolation condenser was declared operable; and, the technical specification action statement was' terminated.
A reactor startup was commenced.
2/22/90 The main turbine was placed on line.
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2/24/90 Reactor power reached 100%.
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2/26/90 During the performance of the Core Spray Instrument
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a Calibration and Test, Procedure 610.3.205, the "B" isolation
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condenser vent valves failed to close on a reactor low-low water level signal. The cause was determined to be failed contacts on an isolation condenser logic circuit relay (6K12) and the "B" isolation condenser was declared inoperable.
Technical Speci-fications allow continued plant operation for seven days with this system out of service, i
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2/27/90 The "A" recirculation pump No. I seal cavity pressure j
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increased from 520 psig to 870.psig,. indicating potential fail-i ure.
The seal pressure, subsequently, was oscillating' slowly..
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The. trend in pressure, however, was decreasing.:
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Replacement of the isolation condenser logic. relay was.per-L formed.
In order to perform post maintenance testing on the l
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Technical specifications require the plant be placed in. cold shutdown condition within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> unless one of the isolation-
L condensers is returned to operability.
The "A"~ isolation con-
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L denser was declared operable three hours later,-and the 30-hour.
p technical specification action. statement was terminated.
l 2/28/90 The "B" isolation condenser was declared operable, and.
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L the.seven-day technical specification action-statement was ter-l minated.
The "B" channel of the Hydrogen-0xygen Monitoring System was declared inoperable as a result of a failure of the calibration gas admission solenoid valve.
Technical Specifications allow continued plant operations for 30 days with the "B" channel out l
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3/2/90 The "B" channel of the Hydrogen-Oxygen Monitoring System
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was repaired and declared. operable, and the 30-day technical specification action statement was terminated.
3/9/90 Decreasing. vacuum in the "C" condenser shell was ob-
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served.
Plant power was reduced to about 70% to stabilize vacuum.
3/10/90 Manipulation of the steam jet air ejector transfer
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valves in an attempt to determine the cause of the condenser low vacuum condition resulted in further deterioration of. vacuum.
Reactor power was further. reduced to about 45% to stabilize Vacuum.
3/14/90 The licensee increased reactor power to 58%.
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limited by condenser vacuum.
The cause of the condenser vacuum problems was isolated to the steam jet air ejector system.
3/15/90 During the performance of the Isolation Condenser Auto-
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matic Actuation Sensor Calibration and Test, Procedure 609.3.003, the "A" isolation condenser vent valve failed to immediately reopen. The failure was isolated to questionable performance of the isolation condenser logic relay (6K10), and the licensee declared both isolation condensers inoperable. Technical Speci-fications require the plant be in cold shutdown condition within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> or the affected trip system placed in a trip conditio e
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hours after the initial indication of failure.
The 30-hour.-
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technical specification action statement was then terminated.
3/16/90 Low levels of radioactivity were found in standing
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water in a storm sewer catch basin. Details of this eve _nt are
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described in Paragraph 2.2.
3/17/90. Replacement of the isolation ~ condenser.' logic relay was
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performed.
To perform post maintenance: testing on the-relay, both isolation condensers had to be declared inoperable.
Tech-nical Specifications. require the plant be placed in cold ' shut -
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L down condition within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> unless the isolation con'aensers
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The "A" 1 solation condenser was'
declared operable four hours later. The 30-hour technica1J
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l specification action statement was terminated.
Because the'"B"~
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seven day technical specification action statement:was still in effect.
1.2 Fire Pratection System Degradation (Unresolved Item 90-03-01)
Inspection Report 50-219/90-03' discussed an event where.a trouble l
alarm for a fire zone in the cable spreading room was;not addressed for 16 days.
Troubleshooting on February 8,1990, found that all.
L detectors for deluge systen 4A, zone 1 were disabled,-rendering this
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system inoperable.
In response to-the initial fire protection, trouble alara, control room operators instituted an hourly fire watch'
to satisfy Technical Specification requirement'3.12.A.R.a.with less-l
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than the minimal num V of fire detection instruments operable.. On Januan 28,1990, it w discovered that the hourly fire watch of the
cable spreading room was not being performed.
This discrepancy prompted the generation of Operations critique report No. 2100-90-002.
After it was discovered the suppression system was inoperable on February 8, 1990, the critique review ~was expanded to include that event.
The cr1~.ique concluded the root cause of the. event was " personnel
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failure to perform." Several contributing causes were~ identified:
Group Shift Supervisors and operations management did not initi-
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ate adequate measures to restore the detection' system to an operable status. Techr.ical Specifications allow establishing an I
hourly fire o r but require restoring the detection systems to operable status within 14 days; and,
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l Group. Shift Supervisors did not realize.that inoperable detec-
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tion systems could render the automatic suppression system in-operable. Procedure 333, " Plant Fire Protection System," does-
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not clearly state that inoper:ble detection systems can render the automatic suppression system inoperable.
The critique'also identified several administrative control
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problems'in establishing and monitoring fire watches.
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Permanent corrective actions recommended by the critique included:
'j Making the cH t hue required reading for Operations personnel;
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Revtsing Procedure 333 to-delineate the relationship between
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detection systems and suppression systems;
Revising the Technical. Specifications to clarify the association
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between fire detection systems and their automatic suppression systems; and, Issuing guidance to control room supervision to require priority
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to returning -inoperable fire protection systems to service.
The inspector. reviewed Licensee Event Report 90-001. This report concluded inadequate procedure guidance, combined with personml error, allowed the fire suppression system to remain inoperable for 16 days. The. corrective action'of the LER referenced the above
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Operations Department critique.
This event demonstrates inadequate attention to fire protection
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systems. Since the control room operators did not recognize the potential for the disabling of the autornatic supression system, the resulting compensatory measures established on January 22 were not sufficient to cover this possibility. A.lso, no corrective actions were implemented until-February ~8.
This resulted in an inoperable
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fire suppression system for 16 days.
NRC enforcement policies require correction of violations within a reasonable time frame.
In this event, the trouble alarm existed for 16 days with no testing or diagnosis. Subsequent diagnosis-showed that the automatic suppression system was inoperable..The inspector concluded the -16 day period with a trouble alarm actuated, without understanding the cause for'the trouble alarm was not ' reasonable.
Thus, the violation was not corrected in a reasonable time frame and
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a Notice of Violation is being issued.
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Technical Specifications section 3.12.C.1 requires that spray and/or sprinkler systems listed in Table 3.12.2 shall be operable.
Fire area OB-FZ-4-(cable spreading room, deluge systems 4A and 4B) is j
listed in Table 3.12.2.
From January 23, 1990; until February 8,
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1990, fire suppression 4A was inoperable and a continuous fire watch was not established. This is a violation of NRC requirements (NV4 50-219/90-06-01).. (Closed UNR 50-219/90-03-01)
1.3 Multiple Control Rod Motion Event On December 16, 1989,-during reactor.startup a control-room operator.
(CRO) inadvertently selected and moved two control rods.
The opera-tor terminated the event by-deenergizing rod select power.
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ensee secured the startup until an evaluation of the event could.be performed and reported this event via the Emergency Notification-
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System (ENS) as a plant condition outside of the design basis.
NRC review of _ this event is documented in Inspection' Report 50-219/89-29.;
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On December 21,J1989, the Plant Review Group (PRG) reviewed this event for reportability under.10 CFR 50.73.
The PRG determined this event was not reportable.
Inspectors reviewed the PRG: rationale for concluding the moving of u
two control rods was not reportable.
The PRG concluded that the.
reactor protection system is the design basis for preventing fuel damage, as opposed to single control rod' control.-
t Section 4.6.2.2 of the updated Final Safety Analysis Report (FSAR)
specifies _the design features-provided_.to minimize.the. probability of inadvertent continuous control rod withdrawal.and to limit potential
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power transients in the event they should occur. The control' system is designed so that only one rod can be withdrawn at a time;'and, that preplanned withdrawal patterns and procedural controls are used to prevent abnormal configurations giving high rod worths.
Section 15.4 of the FSAR discusses analysis for continuous rod withdrawal transients rad the analysis for the control rod-drop accident.
Both events assume that only~one control rod has been selected and is i
being moved.
l The inspector concluded that the design of the Oyster Creek reactor L
manual control system is to select and move one control rod..This I
design feature is an assumption used in the analysis of all rod with-
.drawal transients and the control rod drop accident. The selection i
and movement of two adjacent control rods on December 16, 1989, placed the' plant in a condition outside of its design basis.
Subsequent licensee review has concluded that this event will be re-ported in an LER.
Inspectors had no other questions regarding the reportability of this event.
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1 1.4 Reactor Scram i
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On February-10, 1990, an inadvertent actuation of the-Alternate Rod-Injection (ARI) System caused control rods to start moving into the
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core..The. control room operators, observing the moving control rods,
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immediately inserted a manual scram signal. The plant was subse-quently placed in a hot shutdown condition.
A Post Trip Review Group (PTRG) was convened'to review the cause of-
-the-ARI system actuation and-the response of plant systems. The PTRG -
dotermined that=the ARI system actuated as a result ofran instrument
and controls (I&C) technician who inadvertently keyed a two-way.radi_o l
near the ARI-reactor pressure trip units._ The keying'of the radio
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caused both reactor pressure trip units to actuate. The "two out ofL
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two logic" of the ARI system logic was satisfied, and the system-t actuated. The licensee confirmed this conclusion by' keying a'two-way radio near the trip units with-the ARI system:in-the bypass mode.
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Both. trip units actuated.
The PTRG reviewed the plant's response-to the trip and concluded that the plant responded normally.
The licensee conducted a critique to determine the cause of the_even.t.
and corrective actions.
It was noted that the door to the area of-the pressure trip units was posted prohibiting the:use of any radios.
It was also observed that the I&C technician had a high power radio versus a low power radio.
The licensee had initiated-a Human Per-
formance Evaluation System (HPES)_ review on this event.
The inspec-tor agrees that the evaluation of this event was appropriate.
Overall, the licensee's response to this event was adequate. The
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promptness of the control room operator's-response to the ARI system initiation was excellent. The plant responded normally.
l 1.5 Plant Startup with Rod Worth Minimizer (RWM) Bypassed On February 15, 1990, during a reactor startup, control room opera-
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tors identified that the rod worth minimizer (RWM) was bypassed. The immediate operator response was to place the RWM bypass switch to normal and verify the correct sequence of control rods.
At this
. point in the.startup seven control rods had been' withdrawn. With the RWM bypass switch in normal operators withdrew another control rod.
At that time the Plant Operations Director suspended the.'startup.
until a review could be performed.
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Inspectors reviewed Station Procedure 201.1, " Approach to Critical-ity," Procedure 302.2, " Control Rod Drive Manual Control System," and Procedure 409, " Operation of the Rod Worth Minimizer.". Inspectors-also reviewed Licensee Event Report 90-003.
Initial reports concerning operation with the rod worth minimizer bypassed indicated that six control rods were withdrawn at the time the operators discovered the error.
Inspector review of the RWM
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archive identified that seven control-rods had been withdrawn before
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the switch was returned to normal.
Inspectors discussed this dis-crepancy with Operations management and interviewed the operators who
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were present-in the control room at the time of the event. The in-spector concluded that the initial-report of six rods was in error. _
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and that the RWM bypass switch was'placed in Normal after withdrawal of the seventh control rod.
Control room operators indicated they identified the. problem with the RWM_while. withdrawing the seventh control rod. The inspector had no other questions regarding.the i
number of control 1 rods that had been withdrawn while the switch was-in bypass.
Licensee review of. the event indicatd the ro)t cause was operator error in that the group shift superNr and the control room opera.
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tors did not use:RWM indications.-
The licensee identified as'a contributing cause~ procedural deficien-
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Station Procedure 201.1 specified an electrical ~1ineup to be performed. This requirement.was obsolete because of a RWM modifica-
tion performed during the last outage. The' licensee also identified
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there was no specific guidance for establishing, documenting or de-termining operability of.the RWM.
Specifically, there was no proce-dural guidance specifying the correct position of the RWM keylock bypass. switch.-
Technical Specification 3.2.B.2 requires the RWM be operable during each reactor startup until reactor power reaches 10% of rated power.
NRC inspectors reviewed plant technical specification surveillance requirements. No surveillance requirement was specified for this limiting condition for operation.- NRC requirements, as stated in 10 CFR 50.36 require surveillance tests be specified that are necessary to ensure that limiting conditions of operation will be met..
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The inspector evaluated this event for safety significance.
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event was considered to be of minimal safety significance-since an
"after the fact" review identified that the control rods were with-drawn in sequence. Alsc, a second control room' operator was sta-tioned at the control room panel during rod withdrawal. While his specific duties were not to verify correct rod sequence, his presence provided additional assurance that the correct control. rod was
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selected.
The inspector concluded that the root cause of this event was inade-quate procedures. While the operators could have reasonably been-expected to identify that the RWM was in a bypass position and that
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the RWM was not providing proper indication while withdrawing control
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rods, the more fundametntal problem was that procedures were not in place to provide adequate guidance for the operators. No surveil-lance test procedure or any procedure was in existence that identi-fied the specific steps necessary to demonstrate RWM operability,
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provide documentation, and provide management review of that oper-ability.
In addition, no step was specified to-place the bypass switch in a normal position.
-Startup on February 15, 1990, with the RWM bypassed 1s a violation of'
Technical Specification requirements.
Technical Specification.
3.2.B.2.(a) requires the RWM be operable'during'each startup until reactor power reaches 10%.
Should the RWM become inoperable after the first 12. rods have been withdrawn the startup may continue, pro-vided that a second licensed operator verifies that the licensed
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operator at the reactor console was-following the rod program.
Even though this violation ~ was licensee identified and is classified -
s as Severity Level IV,: a Notice' of Violation will be issued.
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quate procedures controlling a safety related switch is a violation-a which reasonably could have been prevented by licensee's corrective-actions in regard to the violation issued as a result _of Inspection Report-50-219/89-23. ' Also, during-this cycle, eleven reactor start-ups were performed with nonspecific, procedural-guidance to verify RWM; operability.
(NV4 50-219/90-06-02).
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l 1.6 Control Room Tours I
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Routine tours of the control room were conducted by the inspectors
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during which time the following documents were reviewed:
Control Room and Group Shift Supervisor's Logs; I
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i Technical Specification Log; Li
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Control Room and Shift Supervisor's Turnover Check Lists;.
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Reactor Building and Turbine Building Tour Sheets; j
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Equipment Control Logs;.
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Standing Orders; and,
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Operational Memos and Directives.
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No unacceptable conditions were identified, l
1.7 Facility Tours Routine tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, personnel safety, and procedural adherence and regulaury requirements. The following areas were among those inspected:
Turbine Building
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Cable Spreading Room
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Diesel Generator Building
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Reactor Building
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L New Radwaste Building
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i Old Radwaste Building
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The following' additional items were-observed or verified:
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Fire Protection: ~
j Randomly selected fire extinguishers were accessible.and-
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inspected on. schedule.
Fire doors were unobstructed and in their proper position.
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Ignition sources and combustible materials were controlled
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in accordance with the licensee's approved procedures.
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Equipment Control:
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i Jumper and equipment mark-ups did not conflict with tech-
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L nical specification requirements.
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Conditions requiring the use of jumpers received the prompt
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attention of the licensee.
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Vital Instrumentation:
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Selected instruments appeared functional and demonstrated
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parameters within Technical Specification Limiting Condi-tions for Operation.
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Housekeeping:
Plant. housekeeping and cleanliness were in accordance with
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approved licensee programs.
Minor housekeeping deficiencies which were identified were promptly corrected by the licensee.
No other unacceptable conditions were-identified.
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2.0' Radiological Controls
r 2.1 Reactor Recirculation Pump Maintenance
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The radiological control aspects associated with the replacement of the seal and bearings of the "A'! recirculation pump were reviewed on
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The ALARA' review for replacement 'of the' pump-seals was completed -on -
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February' 16, 1990.
The job scope included installation of scaffold-ing and shielding, disconnection and removal of the seal, transport of the seal te the 95 foot elevation, installation of a rebuilt seal,
testing of the new seal, and removal of the shielding and scaffold-
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ing. The work package included the possibility of replacing-the pump
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bearing.
The radiation work permit (RWP) for this job-was RWP No.
900154.
Based on seal work during the 10R, 11R and-12R outages,.the
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ALARA review estimated the exposure for this job to be:5_ person-rem, j
Review of licensee records for the above activities indicated the
exposure incurred for these activities was about 4 person-rem and o
consistent with the ALARA review estimate.
It was concluded by the
' inspector that good planning had been done for.these parts of the t
job. 'The ALARA review, however, did not include pump bearing re-
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placement.
Positive actions were taken to reduce exposure and radiological con-ditions for the rebuilding of the replacement seal.. Extensive
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efforts were taken to decontaminate the seal.
This resulted in sig-t nificant exposure reduction.
Licensee representatives stated that a few days before the job com-l menced it was decided that the pump bearing would be repla~ ed and the c
job scope needed to be increased to. involve inspection and measure-
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ment of the pump bearing cavity.
Licensee personnel knew, based on l
recent work on the "0" recirculation pump bearing, that this type of work would incur at least-as much exposure as the work on the pump seal. On the day that the job began a modification was made to the RWP to include bearing inspection and removal, but no modification was made to the ALARA review to include the additional work.
Review of licensee records for the radiation exposure associated with the bearing, including inspection, removal, measurement and installation activities showed about 11 person-rem associated with these activi-ties. These activities were performed without completion of an ALARA review, which is an apparent violation of plant Technical Specifica-tions.
-In a post-job debrief meeting the licensee discussed the problems experienced by the craft crew during the seal replacement job. Areas I
identified by the licensee as requiring improvement include tools, i
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procedures, training and planning and control of the job. During the bearing and retainer installation, increased personnel exposure re-suited from having parts that did not correctly fit, tools that were not adequate for the application and confined and restricted work space. The crew also indicated that the work package was frequently not in the field due to the required revisions, review and approval.
The mockup training did not simulate the work in the pump cavity.
The licensee recognized that not all of the " lessons learned" from the April 1989 bearing replacement on the "D" recirculation pump had been incorporated.
This violation is classified at severity level IV, and it is being cited because it was not identified by the licensee during their post-job reviews, Technical Specification 6.11 requires, in part, that procedures for personnel radiation protection shall exist and be adhered to for all operations involving personnel radiation protection.
Procedure No.
9300-ADM-4000.11. " Rules for Conduct of Radiologicel Work," and Pro-cedure No. 9300-ADM-4010.2, "ALARA Review Procedure," specify that it is the responsibility of the department initiating the work to co-ordinate an ALARA review. Procedure No. 9300-ADM-4010.2 further states that Radiological Engineering will perform an ALARA review for any task anticipated to accumulate $ person rem or more of total ex-posure. Contrary to this requirement, additional work was added to RWP No. 900154, involving anticipated total exposure in excess of 5 person-rem without the department ensuring the completion of an ALARA review, and as a result no ALARA review for the additional work was performed.
This is an apparent violation of Technical Specifications (NV4 50-219/90-06-03).
2.2 Contamination of the Auxiliary Boiler System i
On March 10, 1990, during operation of the No. 2 auxiliary boiler, the system deaerating feed tank overflowed and spilled onto the boiler house floor. The auxiliary boiler supplies heating steam to the radioactive waste (radwaste) concentrators (evaporators).
Leaks in the "A" evaporator had resulted in the transportation of radio-active material from the evaporator to the auxiliary boiler system.
The spill in the boiler house was treated as radioactive and actions were initiated to monitor and clean up the spill.
Samples of the water in the No. 2 auxiliary boiler and the deaerating feed tank showed activity levels of approximately 4.0 E-2 micro-curies /ml. A previous sample on March 1, 1990, indicated activity
levels in the No.2 auxiliary boiler of approximately 2.0 E-3 micro-
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curies /ml.
The significant increase in activity was attributed to l
1eaks from the "A" radwaste evaporator.
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Since the floor drcins in the vicinity of No. 2 auxiliary boiler are piped directly to the site storm drain system, the licensee performed
radiological surveys in a storm drain catch basin outside the boiler i
house. The purpose of these surveys was to identify any release of
radioactive _ material into the storm drain system and consequently off-site. Because of standing water in the floor drains (which were
clogged) and negative results of surveys of the catch basin, the licensee concluded that no radioactive material had been transported
outside the radiological controls area via the storm drain system.
l Sampling of the site heating steam system heating coils showed that
no radioactive material had been transported into this portion of the
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system. This included the heating coils on the turbine building roof
and the office building roof.
Three tanks of water which vent directly.to the atmosphere were also f
monitored. These are the condensate return tank from the new rad-waste building, the deaerating feed tank vent, and the cordensate
return tank vent from the heating steam portion of the system. Moni-
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toring of these tank vents did not detect any radioactive material,
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The licensee also monitored the boiler combustion exhaust.
In the
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event of a tube rupture or a tube leak the radioactive material in the boiler water would be released to the boiler exhaust stack,' thus initiating a ground level-release.
No activity was detected. The i
licensee performed an evaluation assuming that all the activity in the boiler was released via this pathway over a two-hour period.
Estimated expcsures at the site boundary were less than 1 mrem.
l Following the March 10 spill, the licensee initiated a safety review
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following the guidelines of 10 CFR 50.59.
This review was still in
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progress at the end of the inspection period.
NRC review of the lic-ensee's safety analysis is an unre',olved item (UNR 50-219/90-06-04).
Efforts were initiated to reduce the activity concentrations in the
- 2 boiler and the deaeroting feed unk by feed and bleed, and blow-downs. The "A" radwaste evaporator was secured and isolated.
The l
"B" evaporator was placed in service.
The resulting activities re-l turning to the auxiliary boiler condensate system from the new rad-waste building were drastically reduced. Activities were reduced in the deaerating feed tank t-) approximately 1.0 E-4 microcuries/ml.
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Activities in the #2 auxiliary boiler remained at approximately 1.0 E-2 microcuries/ml.
On March 15, 1990, the No. 2 auxiliary boiler was secured and the No.
I auxiliary boiler was placed into service. Because of residual con-tamination in the auxiliary boiler condensate and feed piping, acti-vity levels increased in the No. I boiler to approximately 1.0 E-3 microcuries/ml and stabilize _. _ _ _ -
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Analysis On February 17, 1990, a similar spill occurred. Activity levels in the auxiliary boiler at that time were approximately 1.0 E-4 micro-curies /ml.
The site Operations Department performed a critique No.
2100-90-004.
This critique concluded the root cause of the spill was-
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boiler water sample valves being left open.
Poor labelling was iden-i tified as a contributing cause.
This critique was inadequate in
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several respects.
First, it did not identify the uncertain status of the auxiliary boiler floor drains.
These drains go directly to the
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site storm drain system and an uncontrolled release of radioactive i
material via this pathway is not allowed. No surveys were initiated i
to verify that radioactive material.had not been released into an uncontrolled system (e.g., the storm drain. system). The critique assumed that the floor drains were intentionally plugged.
This was
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later shown not to be true.
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The critique was also inadequate in that the requirements of Station Procedure 106.2.1, " Spill Procedure", were not implemented to initi-ate a safety review in accordance with 10 CFR 50.59. This procedure specifies that if an event has contaminated a' nonradioactive system, further use of the system shall be restricted until the cause of the i
l contamination is identified and corrected and the system has been decontaminated.
Even though the spill itself did not actually con-taminate the auxiliary boiler system, continued site operation of j
this system as contaminated requires a safety evaluation to identify appropriate radiological controls and to ensure no unreviewed safety
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question is involved.
This requirement was added to Station Procedure 106.2.1 as a result of requirements specified in NRC Bulletin 80-10. " Contamination of I
Nonradioactive System and Resulting Potential-for Unmonitored, Un-controlled Release of Radioactivity to the Environment". This bul-letin specified that a monitoring program be established to promptly identify any contaminating events which could lead to unmonitored and uncontrolled releases of radioactive material.
It also required a safety evaluation be done to ensure there is no unreviewed safety question.
It also required that if operation is determined to be acceptable that any potential release points should be monitored and all releases must be controlled and maintained as low as reasonably achievable.
Inspectors reviewed Station Procedure 828.8, " Secondary Systems An-alysis:
Boiling Water." This procedure specifies weekly measurement of boiler water for radioactivity with an acceptance criteria of less
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than minimum detectable.
The corrective action specified if activity is detected is to notify the Group Chemistry Supervisor.
Site prac-tice has been to reduce the activity to below minimum detectable or as low as deemed feasible by conducting boiler blowdowns when acti-vity is detected.
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i The weekly radioactivity samples of boiler water showed activity had
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been increasing from approximately 1.0 E-6 on January 1,1990, to
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about 1.0 E-4 (a factor of 100) on February 17, 1990. During this time frame no corrective action was initiated to perform a safety i
evaluation or to control or monitor potential release points of radioactive material because of this contamination.
The activity continued to increase to approximately 2.0 E-3 on March 1, 1990, with no corrective action taken. Then, with the'"A" radioactive waste evaporator malfunction, activity levels jumped to approximately 4.0
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E-2 on March 8, 1990. The following spill on March 10, 1990, re-i suited in the release of radioactive material to the site storm drain
system. This release was unmonitored and uncontrolled.
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Licensee evaluation of the amount of radioactive material that was actually released to the environment concluded these quantities were
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very small, were well within the limits specified by plant Technical Specifications, and posed no threat to the health and safety of the
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public. The amount of activity estimated was less than that which would norm 611y be released in a processed overboard discharge.
The inspector concluded that the requirements of Bulletin 80-10 and also those of Station Procedure 106.2.1 were not met to evaluate pro-perly the consequences of system operation with radioactive material
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and to control and monitor potential release points.
in addition, t
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the inspector concluded Station Procedure 828.8 was inadequate in i
that it did not identify as corrective actior, the need to perform a safety evaluation of activities detected in the site auxiliary boiler
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system.
NRC review of overall site implementation of Bulletin 80-10 is an I
unresolved item (UNR 50-219/90-06-05).
Operation of the site auxiliary boiler system with radioactive mate-
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rial present without performing a safety evaluation per the guide-l
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lines of 10 CFR 50.59 as required ty Station Procedure 106.2.1 is a violation of site procedures (NV4 00-219/90-06-06).
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2.3 Hot Particle on the Refueling Floot L
On January 18, 1990, activities were in progress in the reactor l
building 119 ft, elevation to remove a work platform from the spent fuel pool.
The work platform had been used to support control rod blades, fuel channel pieces and local power range monitor strings while processing for shipment. This work was part of the licensee's
spent fuel pool volume reduction project.
The work was performed by i
a contractor.
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i During the activity, a worker received multiple hot particle con-tamination to the skin. A 35,000 cpm particle was found on his face and three hot particles reading 160 mrad /hr, 32 mrad /hr and 24 mrad /hr on his legs. The radionuclide from the hot particles was determined to be. Cobalt-60. The licensee performed dose assessments and conservatively estimated a total whole body skin dose of 4677
mrad (limit is 7.5 rem /qtr) and a MPC-hour assignment of 3.7 (limit is 520/qtr).
The events which occurred leading up to the skin contamination started when the work platform and receptacle would not clear the fuel pool. They were lifted to allow the separation of the two com-ponents such that they could be removed separately from the spent fuel pool. The supervisor was informed that the problem could be resolved by using shorter rigging cables. A change to the rigging procedure would require approximately three hours. The supervisor decided it would take too long and consulted with the Radiological Controls Technician (RCT) and the Quality Control (QC) inspector re-garding taking the work platform and receptacle out as one unit.
Personnel involved concluded no procedural problems would exist by removing the unit out as one piece.
When the work station anc re-ceptacle were removed as a unit, the RCT noted 18-20 R/hr reaaings from the bottom of the receptacle.
Since the work platform and receptacle could not readily be lowered back in to the spent fuel pool, the RCT decided to remove the bottom
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plate of the receptacle instead of immediately returning the work
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platform back to the pool. This determination was based on his assessment that (1) placing the work platform back in the spent fuel pool was difficult and would result in an overall higher-collective dose (2) contacting the Group Radiological Controls Supervisor (GRCS) for direction would require too long and the situation at the time required immediate action, (3) the supervisor's emphasis that the bottom of the receptacle can easily be removed and, (4) the in-
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l stability of the work platform on the edge of the spent' fuel pool.
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In retrospect, the RCT exercised poor judgment in his evaluation of I
the radiological consequences of this decision. Although some ac-tions conducted by the RCT were good, errors in judgment ultimately resulted in skin contamination of the worker.
The licensee conducted a review of this event to determine the root cause and corrective actions.
The critique was detailed and thorough in analyzing the RCT's actions and assessing whether his decisions were appropriate. The critique identified that the root cause was the failure to follow the job as planned and changes were not ade-quately communicated to the GRCS.
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The inspector reviewed this event and noted that the critique _ con-ducted by the licensee identified that the rigging procedure was not
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changed by the supervisor because he felt the procedure change would
take too long. The inspector made the following conclusions.
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The procedure used for the rerroval of the work station was in-
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adequate.
The procedure stated for the demobilization of the l
work station, " Remove, disassemble and decontaminate in reverse order of assembly. See Section 7.4.3 and subsections for in-
structions." Section 7.4.3, however, only specifies the assembly of the work station.
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The inspector concluded that the intent of the procedure was to
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perform the removal of the work station in the reverse order of installation into the spent fuel pool.
This interpretation would provide adequate direction to the workers on the removal of the work station and assure certain precautions such as set-
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ting the mechanical crane blocks and following a safe load path were taken.
It was interpreted by the workers, supervisor,'and QC inspector,
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that only the disassembly needed to be performed in the reverse order.
The removal of the work station could therefore be re-moved in any manner with no violation to the procedure.
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The supervisor recognized the intent of the procedure was to
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remove the work station in the reverse order of installation but was reluctant to do so because he felt the rigging procedure
l change would take too long.
The supervisor was concerned enough with the alternate method of removing the work station that he L
asked the QC inspector whether there was a precedural problem if
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the work station and receptacle were removed together.
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The inspector concluded that the inadequacy of the procedure and the reluctance to change the rigging procedure were significant contri-butors to this event.
Although the comment that the procedure change was not performed because it would take too long was captured in the radiological critique, no further review or corrective action deter-mination was performed. The responsible licensee supervisor was not aware of this comment in the critique. Neither he nor radiological
controls personnel pursued the non-radiological aspects of the event.
t The inspector concludec that the review conducted by the radiological controls division was thorough in the review of the event'from a radiological aspect.
The review, however, identified a potential prob-l 1em in procedure adequacy and a supervisor's attitude toward proce-dural changes.
The review was narrow in that it dealt only with the radiological issues.
No mechanism was initiated to have nonradio-logical issues identified and addressed.
The licensee stated that
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they will review this aspect of their radiological critiques and in-cident reports. This issue will be unresolved pending NRC review of licensee's review and corrective. actions, if any.
(UNR50-219/
90-06-07)
2.4 Assessment Each of these events highlight weaknesses in the day-to-day activi-ties in the area of radiological controls.
The first event shows the low significance attached to performing a formal ALARA review in the instance cited.
The momentum of complet-ing the work resulted in 11 man-rem of exposure without formal re-view.
Post-job reviews did not identify this deficiency.
The second event shows weaknesses in the site program for evaluating operation with normally uncontaminated systems being contaminated.
No safety evaluation was performed even though a formal critique was performed.
This critique did not adequately evaluate the first spill.
Consequently, sentinued operation with inadequate radiolo-gical controls resulted in release of radioactive materials outside of the Radiological Controls Area.
The third event shows fragmentation in event review processes.
The Radiological Incident Report identified a reluctance to change a mar-ginally adequate rigging procedure because of the length of time re-quired to process the change.
Continuation of the job eventually resulted in handling of equipment in unplanned configurations.- This contributing cause to the event was not identified to the appropriate responsible site personnel.
All the events show weaknesses in the identification, documentation, correction, and prevention of deficient radiological conditions.
While program improvemtots are being implemented, these events show continued poor performance in the area of Radiological Controls and serve to emphasize the importance of effective long-term corrective
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3.0 Maintenance / Surveillance 3.1 Monthly Surveillance Observation On March 12, 1990, inspectors observed performance of surveillance test 602.3.004, "Electromatic Relief Valve Pressure Sensor Test and Calibration." For this observation inspectors verified the current revision of the procedure was used, proper authorization was obtained to perform the test, procedure steps were signed off as performed,
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and the "as found" conditions of the EMRVs met acceptance criteria.
One valve (IA83D) required adjustment to meet acceptance criteria.
After adjustment, the valve was satisfactory.
The surveillance test specified the connection of an ohmmeter to ter-minal block location L2 for each of the valve pressure controllers (Steps 6.2.5, 6.3.5, 6.4.5, 6.5.5 and 6.6.5).
This style of terminal block did not provide any location for the technician to attach the test probe. On one valve the technician used the bare wire which was visible near the termination. On the other four valves, the techni-cian visually located a point electrically equivalent and attached his probe. Because of the wording of the surveillance test step and the terminal block configuration this step could not be performed exactly as written. A discrepancy was noted by the I&C technicians.
The licensee is determining the appropriate procedure change to im-piement.
While performing the test, the-I&C technicians noted the terminal boxes were labelled EQ denoting special equipment environmental qualification requirements. The technician questioned if there was a need for an EQ summary component evaluation worksheet (SCEW). This question was documented in the comments portion of the test.
Evaluation showed the terminal boxes Nere not environmentally qualified, only the components inside; and therefore, no SCEW sheet was required. The licensee is evaluating the need to specify visual inspection requirements in this surveillance procedure.
The inspector observed a wiring diagram posted inside the cover of each pressure controller. At various points during the performance of the surveillance the technicians referred to the wiring diagram.
No documentation was visible to indicate the diagram was a controlled drawing or approved as an operator cide. Ononedrawing(IA83B)
handwritten corrections were made to the drawing, along with hand-written notes.
These drawings were subsequently removed from the plant.
No other deficiencies were identified.
3.2 Monthly Maintenanct Observation On February 27, 1990, inspectors observed maintenance associated with the replacement of a failed relay in the isolation condenser logic circuit.
Inspectors reviewed the work package (immediate maintenance short form 57924) and the standard maintenance procedure for relay replacement, Procedure A100-SME-3922.01.
Inspectors also reviewed the safety evaluation associated with the temporary modification to install jumpers in the isolation condenser logic. The inspector
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verified the proper approval was obtained prior to beginning the work and the proper approval was obtair<ed for the installation of the tem-porary modification.
The inspector observed the notification of the
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control room operators immediately prior to the installation of the temporary modification. The inspector also observed close coordina-
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tion and supervision by the job supervisor.
This is required for an
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immediate maintenance short form.
I During the installation of the temporary modification the job super-visor evaluated the location of the jumpers to be too close in proxi-i mity to the relay which required replacement.
The supervisor was l
concerned _that during the actual relay replacement there was a possi-
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bility the jumpers could be inadvertently dislodged. The supervisor
stopped work on the job, directed the removal of the jumpers and more research to identify an acceptable location for the jumpers. The inspector concluded this action on the part of the job supervisor was
appropriate.
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For the job package, safety evaluation, temporary modification and maintenance observation no unacceptable conditions were identified.
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l 4.0 Emergency Preparedness
A quarterly Emergency Preparedness drill was conducted on March 1,1990.
Portions of the drill were observed by the inspectors in the Technical Support Center (TSC) and the control room.
The drill scenario involved a small break from the Core Spray System I sparger.
Complicating events were a hydrogen explosion on the turbine deck, loss of offsite power and failure of one diesel generator.
The debrief of the drill was observed on March 2, 1990.
Licensee identi-
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fied deficiencies were (1) the offsite dose calculations were miscalcu-lated which resulted in a poor protective action recommendation by the TSC
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staff; and, (2) hardware problems with the telephone lines from the con-
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l trol room to the TSC and Operations Support Center created difficulty in communications. Other minor deficiencies were noted. The licensee pro-perly addressed the deficiencies identified.
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No unacceptable conditions were identified.
5.0 Safety Assessment / Quality Verification
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5.1 Main Steam Isolation Valve NS03A Leak Repair (Unresolved Item
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F0-219/90-03-02)~
During the plant outage 12U-8 in February 1990, a body to bonnet steam leak was identified on the inboard main steam isolation valve NS03A.
This leak was repaired on February 16, 1990. The licensee contracted a vendor, Leak Repair Inc., who installed a clamp around the bonnet flange and injected Furmanite 2X material inside the clamp to seal the leak.
The repair was designated as " nuclear safety re-lated," but the work package did not contain any QA inspection tags
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I clearing the Fermanite seal material for safety related application.
i Upon the inspector's questions on February 22, 1990, the licensee
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determined that a QA receipt inspection was not performed before the Fermanite material was accepted and installed.
l Due to limited shelf life, an on-site cupply of the seal material is
not maintained.
The:11censee's contract with the vendor required the
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vendor to notify site QA Engineering before bringing material on site
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so a receipt inspection could be performed to ensure the specified material was used for the repair.
However, the vendor did not notify
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site QA Engineering and the licensee personnel involved with the re-
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pair and work package closeout did not note that the required receipt
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inspection was missed.
This incident was similar to one during 1986 when approximately half of the material supplied by Leak Repair. Inc.
l was not receipt inspected. At that time the licensee wrote a quality deficiency report (QDR) and reemphasized the contract requirement with the vendor.
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In order to certify acceptability of the installed seal material the
licensee retrieved the batch number and material identification' from the used containers and matched them with vendor supplied informa-tion. The material identification matched with the one reviewed and approved by Engineering and Chemistry..The licensee also obtained
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some material of the same batch number from the vendor and sent it to-
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the laboratory for analysis. The laboratory report indicated that the material was acceptable. The licensee also indicated that they
would maintain a refrigerated supply of Leak Repair material on site,
thus eliminating the need for the vendor to bring in material prior to each job.
Refrigerating the material increases shelf life in-definitely.
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On March 12, 1990, the inspector asked the licensee if a deviation
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report should have been initiated on this incident. The licensee prepared a QDR to address the vendor's failure to comply with the
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contract requirement on March 13, 1990. A deviation report and a
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material nonconformance report (MNCR) were also prepared by the lic-ensee on 3/14/90 addressing the missed receipt inspection and mate-rial acceptability. The inspector concluded that the leak repair
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material installed on NS03A~was acceptable. 'The safety significance of the event was minimal for this application, as the repair did not
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affect capability of the main steam isolation valve to isolate.
In-creased valve leakage would be detected via increasing drywell un-identified leak rate. The event indicated a potential weakness in the licensee's procurement program with Leak Repair Inc. The 11cen-
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see personnel involved with the job and work package closeout were slow in documenting the deficiency in a deviation report, QDR or MNCR so that necessary review of the event and the corrective action could be performed. This called into question their understanding of the corrective action program and its documentation requirements.
Not performing a receipt inspection for nuclear safety related material
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.is a violation of the licensee's QA Plan and 10 CFR 50, Appendix B, t
Criterion VII. However, due to minimal safety significance, isolated nature of the incidence, and acceptable licensee correction action, no Notice of Violation is being issued, following the guidance pro-vided in NRC Enforcement Policy 10 CFR 2, Appendix C, paragraph V.A.
(NON 50-219/90-06-08) (Closed 50-219/90-03-02).
6.0 Licensee Event Report Review (LERs)
During this inspection period, Licensee Event Reports (LER) were reviewed to determine the adequacy of event assessment, the root cause determina-
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tion, corrective actions, generic applicability, consideration and com-
pleteness and accuracy.
Corrective actions not yet complete are followed by the licensee via their Licensing Action Item (LAI) tracking system.
The following LERs were reviewed.
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LER 89-001, Possible loss of Main Steam Line Isolation Capability Due to Excessive Main Steam' Isolation Valve Control Air Leakage, and.LER_89-008.
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[oss of Air Event will prevent Secondary Containment Integrity Due to Inadequate Surveillance Testing of Air Support System:
These LERs refer
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to a condition discovered by the licensee where there was excessive leak-age from the control air piping to the main steam isolation valves and secondary containment isolation valves.
This condition resulted in de-graded performance of these valves in the event of a loss of the station instrument air system.
The licensee discovered this condition while performing testing in re-sponse to NRC Generic Letter 88-14 and the Emergency Operating Procedure i
Inspection 50-219/88-200.
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The first issue was reviewed in a meeting held at NRC headquarters._ The
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meeting was documented in a meeting memorandum dated 2/2/89.
The licensee performed an MSIV seat leak rate test over a range of simulated drywell pressure and valve actuator pressure.
Following an NRC request, the lic-ensee documented their MSIV leak rate analysis under design basis accident (DBA) conditions with loss of control air supply to the actuators. The analysis indicated that with zero valve actuator pressure, the integrated leakage /offsite dose will be below the SEP integrated leakage /offsite
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dose.
This report was submitted to the NRC on 3/10"9 and was found acceptable by NRR review. As committed in the LER, a supplemental LER is also being written by the licensee to address additional corrective ac-tions for MSIV leakage.
This constituted of replacing the air piping and
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associated accumulator check valves with soft seat check valves to reduce.
accumulator air leakage in the event of a loss of instrument air. Testing performed after the replacement indicate acceptable MSIV leakage.
Inspection reports 50-219/88-38, 89-07 and 89-10 describe licensee's con-tinued testing of the air operated valves and the accumulators, and the
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corrective actions in terms of replacing or repairing the leaky components and additional procedural guidance for a loss of instrument air event,
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Regarding the second event, long term corrective actions for establishing a surveillance program to test the air support system is being addressed via the licensee's licensing action item backing system for Generic Letter 88-14.
LER 89-002, possible Fuel Pool Gate Movement Above Irradiated Fuel:
This voluntary LER refers to an event where a heavy load (fuel pool gate) may have been moved over irradiated fuel. The LER was voluntary because the control room operator who observed the movement was not certain that the fuel pool gate actually moved over irradiated fuel. Although he initially a lieved the gate may have passed over spent fuel, he was not certain due to his angle of view and the water spray on the gate as it was being moved. The corrective actions specified in the LER have either been com-pleted or appropriately tracked by the licensee.
No unacceptable condi-tions were identified.
LER 89-003. Reactor Isolation During Surveillance Test Caused by Failed fuse: This LER refers to an event in which a reactor isolation was in-advertently initiated.
The cause of the initiation was a failed fuse in i
one of the reactor protection system (RPS) channels.. When the operators
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performed a surveillance on the other channel, the reactor isolation in-itiated. The cause of the event was determined to be a human engineering design deficiency in that there were no alarms associated for a half or full isolation signal from the isolation relays. A modification is scheduled for 13R outage to provide an alarm for half isolation signal in.
No unacceptable conditions were identified.
LER 89-004, Main Steam Isolation Signal During Reactor Protection _ System
>ower Supply Transfer Caused by Inadequate Procedure:
This LER refers to
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a main steam isolation valve automatic c'osure signal which occurred when a reactor protection system power supply was shifted.
The significance of this event was low because the plant was in cold shutdown with the main j
steam isolation valves already closed.
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The licensee determined the cause of the event was inadequate procedure and human error on the part of the responsible technical review and the safety reviewer.
It was observed that all but one corrective action has been completed. The corrective action which has'not yet been completed was advising originators and reviewers of the importance of clear communi-cations in the procedure change process.
No unacceptable conditions were identified.
LER 89-005. Standby Gas Initiation due to Blown Fuse Caused by a Dislodged Jumper during Surveillance Testing: While performing control rod scram insertion time test a jumper installed during the surveillance slipped off its connection point, shorted to a portion of the reactor protection sys-tem and blew a fuse. This caused a partial primary containment isolation =
and an initiation of the Standby Gas Treatment System (SGTS).
The plant
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was shutdown and a reactor hydrostatic surveillance test was in progress.
Initiation of SGTS and closure of drywell (DW) sump, equipment drain tank isolation valves and the purge valves did not result in any plant transient.
The licensee replaced the blown fuse, reset the isolation, secured SGTS operation and reopened DW isolation valves. As a long term corrective action, the licensee had a task in progrcss to eliminate the need to in-stall jumpers and lifted leads during surveillancos. The necessary modi-fication will be made during the upcoming 13R refueling outage to address the control rod scram time testing.
LER 89-006, Technical Specification Inconsistency Results in Less than hequired Number of Automatic Depressurization Channels:
This LER de-scribes six occurrences when Technical Specification 3.1.1, $6ction G.3 requirement of two operable automatic depressurization system (ADS) trip systems were not maintained. One of the ADS trip system logic inputs comes from the core spray booster pump differential pressure (d )
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switches. Thus, if an entire core spray system is made inoperable by vir-tue of disabling both of the core spray booster pumps or the two dp switches in the system main pumps, the input to one of the two ADS logic tra. ins is also inhibited, thus not meeting Technical Specification 3.1.1, Section G.3 requirement, and the plant is required to be in the cold shut-down condition within 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The core spray system technical specifi-cation does not address this interface and allows up to 7 days of plant operation with one core spray system inoperable.
This concern and licensee's corrective action was reviewed in NRC Inspec-tion Reports 50-219/88-38 and 89-06/09. An enforcement conference was held with the licensee on February 16, 1990, as documented in Inspection Report 50-219/90-03.
LER 89-007, Design Deficiency Causes Standby Gas Treatment System Initiation during ARM Maintenance:
Initiation of the Standby Gas Treat-ment System ($GTS) was due to a ribbon connector plug coming out of its socket, which interrupted power to one of the two area radiation monitors (ARM) on the reactor building vent exhaust manifold. Due to the system single trip logic and failed safe design, a reactor building isolation and SGTS initiation occurred.
The plug-in type connector relies on a tight fit between the plug and the socket. A similar problem occurred several times in the past on other ARM modules.
The licensee is currently per-rLrming a design review of the ARM system to determine the necessary con-nector modification. The design review is expected to be complete by June-30, 1990.
LER 89-009, Potential Loss of Adequate Containment Cooling During a LOCA due to a Design Deficiency in the Containment Spray System:
fhis LER dis-cusses a design deficien;y in that during a design basis Toss of coolant accident, a low-low reactor water level prevents the containment spray system from operating in the torus cooling mode of operations, In the drywell spray mode, the pumps are tripped when drywell pressure drops to 2
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Long term cooling of the torus is precluded because the procedures restrict containment spray operation when containment pressure is less than 3 psig.
Continued decay heat addition to the torus would result in increasing torus water temperature and eventually loss of net positive suction head to the core spray pumps.
The licensee's corrective action included reducing the containment spray pump trip setpoint from 2 psig drywell pressure to 0.6 psig. Also, jumpers were to be installed to bypass the logic such that valves could be v
repositioned in the torus cooling mode.
Inspection Reports 50-219/89-06, 09 and 80 address the issue. 11censee's corrective action and its imple-mentation.
LER 89-019, Technical Specification shutdown. Emergency Diesel Generator I Inoperable: This report discussed the failure of diesel generator 1 to start followsng a surveillance test during which erratic load swings were observed while its unloading sequence. As licensee's troubleshooting and repair were not completed within the seven-day Technical Specification limited condition of operation, the plant was shutdown.
This event, including the licensee's repair of the diesel generator, was reviewed by the resident inspector and discussed in Inspection Report 50-219/89-21.
LER 89-023, Four Out of Six Low Vacuum Scram Setpoints Found Out of Specification Due to Sensing Element Drift:
This LER refers to an event in which four out of six low vacuum setpoints were found at values less conservative than the Technical Specification limit.
This event was reviewed in depth during an NRC Augmented Inspection. The results of the inspection were documented in Inspection Report 50-219/89-81.
The LER stated that the as found condition was not reportable and that the report was being submitted voluntarily.
This assessment, however, was contrary to the conclusions of the Augmented Inspection Team. A manage-ment meeting is scheduled to discuss the Augmented Inspection findings.
LER 89-024, six out of Eight Isolation Condenser Pipe Break Sensors Found out of Specification due to Excessive Drift:
During a surveillance test on December 28, 1989, six out of eight differential pressure (dp) sensors in the isolation condenser (IC) steam and condensate lines were found to be out of specification. The as-found trip setpoints were found to be higher than the required dp corresponding to 300% normal steam flow. The dp switches isolate the isocondenser steam and condensate lines upon a
line break.
The licensee modified these dp switches during 1980 with snap-acting switches and since then the switchss have not demonstrated the desired setpoint repeatability.
10 pipe beeak would also be detected and alarmed l
by the aren radiation monitoring and the temp rature monitoring systems.
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The control room operators are procedurally directed to manually isolate the affected IC when the source of alarm is verified. The reactor build-ing ventilation system switches over to the SGTS upon a high radiation level in the vent system.
The licensee considered the safety significance of the event as minimal.
The setpoint drif t would not affect the automatic isolation capability for a large break in the IC lines. The IC lines are not designed to auto-matica11y isolate if break flow is less than 300% of normal flow. These switches are scheduled to be replaced during the 13R refueling outage.
The inspector found the licensee's corrective action acceptable.
LER 90-001. Failure to Set Continuous Fire Watch Due to Inadequate Procedural Guidance and Personnel Error: This LER refers to an event in l
which a continuous fire watch was not established for an inoperable fire protection deluge system. This event was reviewed in this inspection re-port in paragraph 1.2.
LER 90-002. Standby Gas Treatment System Automatically Star,tj while Removing Instrument Panel power Supply from Service for Maintenance: The continuous instrument panel (CIP) No. 3 1s normally powered from the vital MCC 182 via a rotary inverter. An automatic transfer switch, IT-3, allows the transfer of power from the rotary inverter to vital MCC 1A2. On February 7,1990, the rotary inverter was removed from service for main-tenance. This caused the automatic transfer switch to shift. During this transfer, power was momentarily lost to CIP-3.
Loss of power to the logic relays and trip units caused initiation of the SGTS and partial isolation of the primary and isolation of secondary containments.
The LER did not identify the specific systems affected by the partial i
isolation of the primary containment. Upon inspectors review, the licen-see described the partial primary containment isolation as involving isolation of the drywell sump and equipment drain tank discharge valves, drywell purge and ventilation exhaust valves, drywell and torus nitrogen purge valves, tip valves and the drywell oxygen sample valve. The reactor was shutdown with drywell deinerted at the time of the incident; there-fore, the safety significance of the event was minimal.
The operating procedure for vital power system requires the operators to verify automatic transfer of switch IT-3; however, it doc iot address the consequences of a momentary loss of power to CIP-3.
The licensee is cur-rently reviewing the procedure for necessary revision and plans to incor-porate a list of systems and components that will be automatically actu-ated upon removal of the rotary inverter from service. Manual actuation of SGTS prior to removing the rotary inverter from service will also be required.
Similar changes to other system operating procedures to indi-cate the automatically actuated components is also being considered.
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LER 90-003. Control Rods Withdrawn Durino Startup with the Rod Worth Minimizer Bypassed Due to Personnel Error:_ This LER refers to an event during reactor startup where the first seven control rods were withdrawn with the Rod Worth Minimizer bypassed.
This event was reviewed in this inspection report in paragraph 1.5.
7.0 Inspection Hours Summary Inspection consisted of 156 direct inspection hours; 38 of these direct inspection hours were performed during backshift periods, and 9 of these hours were deep backshift inspection.
8.0 Exit Meeting and Unresolved Items The resident inspectors attended the exit meeting for Inspection 50-219/
90-04. The lead inspector discussed inspection activities and findings with senior licensee management.
No proprietary information was dis-cussed.
A summary of the results of the inspection activities performed during this report period was made in a meeting with senior licensee management at the end of this inspection.
No proprietary information was included.
Unresolved items are matters for which more informatien is required in order to ascertain whether they are acceptable, violations or deviations.
Unresolved items are discussed in paragraphs 2.2 and 2.3 of this report.
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o ATTACHMENT I Personnel Contacted Licensee Personnel A. Agarwal, Technical Functions J. Andrescavage Plant Operations
- R. Barrett, Plant Operations Director T. Blount, Emergency Preparedness D. Brittner, Control Room Operator
- R. Brown, Radwaste Operations Manager J. Brownridge, Maintenance
- G. Busch, Licensing Manager G. Cappadanno, Technical Functions J. De Blasio, Plant Engineering Manager B. De Merchant, Licensing Engineer S. Dunsmuir, Plant Operatiens
- E. Fittpatrick, Vice President & Director
- V. Foglia, Technical Functions Manager R. Gayley, Plar.t Engineering
- J. Hildebrand, R & EC Director
- R. Heffner, Rad Con & SH Assessor T. Hedigan, Instrument and Controls G. Hutton, Group Shift Supervisor
- E. Johnson, Maintenance Supervisor I&C
- L. Lammers, Plant Material Director L. Martino, Radiological Controls K. Mulligan, Plant herations R. Murdock, I&C Eng.
S. Narayan, Elec. Engineering D. Ranft, Engineering Manager J. Renda, Radiological Controls
- J. Rogers, Licensing Engineer
- A. Rone, Plant Engineering Director
- P. Scallon, Plant Operations Manager S. Serpe, Control Room Operator
- M. Slobodein, Rad Con Director
W. Stewart, Safety Review
- R. Sullivan, Emergency Preparedness Manager
- R. Thompson, Core Engineering R. Thoms, QA Engineering Manager G. True, Supervisor Funct/Mtee
- D. Tuttle, Chairman R&D Improvement Plan J. Ventosa, Plant Engineering J. Vermeylen, Control Rrom Operator E. Weibrecht, Plant Orerations, Control Room
- K. Zadroga, Radiological Controls l
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. Attachment I
NRC' Personnel
- M. Banerjee,-Resident Inspector
- E. Collins, Senior Resident Inspector
- R. Hernan, Acting Section Chief, Reactor Projects Branch 4B
- D, Lew, Resident Inspector
- E. Wenzinger, Chief,- Reactor Project.s Branch-4 Denotes attendance at exit meeting.
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