IR 05000272/1981012
| ML18086A816 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/08/1981 |
| From: | Bettenhausen L, Greenman E, Hill W, Norrholm L, Paolino R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18086A815 | List: |
| References | |
| 50-272-81-12, 50-311-81-11, NUDOCS 8107280560 | |
| Download: ML18086A816 (27) | |
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. Report Nos *
Docket No License No U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT 50-272/81-12 50-311/81-11 50-272 50-311 DPR-70 DPR,;.75
REGION I
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0311-810314 0311-810313
.050311.,.810519 050311-810520 050311-810521 050311-810530 050272;810109.
050272-81011 Licensee:
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80 Park Plaza 050272-810312
"'----------------'\\oc:0272-810324 Newark, New Jersey 07101 050272-810322
"""'-----"'"----------------10~50212-810520 Facility Name:
Salem Nuclear Generating Station - Units 1 and 2 050272-810521
~----------+H;050272-81052 Inspection At:
Hancocks Bridge, New Jersey 050272-810527 Inspectors:
Inspector P'G'/G/
EIB date
/J/\\ R: J. P~l ino, Reactor I*~spector, EIB
¥~flj ate Approved [ Fl ~~
.tM/ ~- Gree ~Chief, Reactor Projects Section No. 2A, Tr -
Projects Branch No. 2, DRPI
?18./Bt date Inspection Summary:
Inspections on May 1 - May 31, 1981 (Combined Report Numbers 50-272/81-12 and 50-311/81-11)
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Unit 1 Areas Inspected: Routine inspections by the resident and region-based inspectors of plant operations including tours of the facility; confonnance with Technical Specifications and operating parameters; log and record review; review of licensee events; fire protection review; and followup on previous inspection items. The* inspection involved 75 inspector-hours by the resident and region-based NRC inspector Results:
No items of noncompliance were identifie Unit 2 Areas Inspected: Routine inspections by the resident and region-based inspectors of plant startup testing including tours of the facility; confonnance with license requirements and Technical Specifications; fire protection review; followup on licensee events; and, followup on previous inspection items. The inspection involved 208 inspector-hours by the resident and region-based NRC inspector o56ouai*o7i~~_,,_~~~__...oncompliance were identifie PDR ADOCK 05000272
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DETAILS
1. Persons Contacted J. Driscoll, Chief Engineer L. Fry, Station Operating Engineer J. Gallagher, Assistant Maintenance Engineer S. LaBruna, Maintenance Engineer H. Midura, Manager - Salem Generating Station L. Miller, Station Performance Engineer J. Jackson, Reactor Engi_neer (Acting)
R. Silverio, Assistant to the Manager J. Stillman, Station QA Engineer R. Swetnam, Radiation Protection Engineer The inspector also interviewed and talked with other licensee personnel during the course of the inspections including management, clerical, maintenance, operations, performance and quality assurance personne. Status of Previous Inspection Items (Closed) Follow Item (272/80-33-01)
Incorrect identification of valve 1 FP 147 in the Fire Fighting and Organization Manual, Appendices P and The inspector confinned that "on the spot" changes to,
these Appendices, made on January 8, 1981 and April 29, 1981, respectively, corrected the valve designation to read FP 147, instead of FP 4 The inspector had no further questions on this ite (Closed) Follow Item (311/80-22-01)
Implement surveillance procedures dictated by review in accordance with IE Bulletin 80-06 - ESF Reset Controls. The inspector reviewed completed documentation for surveillance tests SP(O) 4.3.2.1.l{c) and SP(O) 4.6.3.1.2(b)
which test the operation of containment isolation valves, including the identified valves in the Bulletin response (e.g. 2 SJ 53, 2 FP 147, and 21-24 MS 18). These tests demonstrate operation of the valves and confirm these valves maintain containment isolation after the signal has been reset. These tests were completed in February 1981, prior to Unit 2 heat up. The inspector had no further questions on this ite *
(Closed) Follow Item (311/80-17-04) Exercise of corporate emergency response plan. The inspector reviewed records of training exercises conducted at tbe corporate offices and observed corporate response at the site during the coordinated April 8, 1981 exercise. Record review in-dicated that, during March 1981, several training evolutions were conducted for the corporate recovery management staff, including classroom, conmunications, and table top exercises. The staff was also involved during practice drills held with the states prior to the April 8 exercise. Communications/recall drills were conducted during off-hours and weekend The inspector had no further questions on this ite..
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(Closed) Unresolved Item (272/80-23-05) Shipment of exempt quantities of radioactive material. Based on review of shipment records, the inspector confirmed that procedural controls for radioactive materials are now applied to all shipments, including exempt quantities. This procedure documents justification for treatment of materials as limited quantities and provides necessary shipping and handling instructions to the carrier. The inspector had no further questions on this ite (Closed} Unresolved Item (272/81-04-01) Steam generator decontamination procedure. The inspector confirmed that procedure RP 7.031, Steam Generator Decontamination, was approved in SORC meeting 81-16 and was issued on March 16~ 1981. This procedure includes the precautions necessary to ensure that adequate boron concentra-tion is maintained during decontamination of steam generator The inspector had no further questions on this ite (Closed}
Follow Item (311/80-18-03) Determination of leak rate in systems outside containment. This item is discussed in *paragraph-7-and *
was found acceptable.* *
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(Closed) Follow Item (272/80-14-05 and 311/80-10-03)
The inspector verified that handout materials and instructions for General Employee In-doctrination (GEI) using GEI Lesson Plan, Revision 3, February 26, 1981, includes discussion of plant layout, facilities, and equipment *
This item is close (Closed} Follow Item (311/80-17-01) Radiation worker classroom training currently includes a discussion of containment air locks and their operation. This item is close (Open)
Open Item (311/79-18-01) Verification that Startup Test Procedure, SUP 82.5, Shutdown from Outside the Control Room meets regulatory and licensee commitment The version of SUP 82.5, dated January 30, 1979, and approved by the Station Operations Review Committee, March 6, 1979, is in process of revision following an NRC review of the fire protection procedures and practices including the safe shutdown capability. Discussions with licensee engineers concerning the startup test revealed the following:
a. The test will be conducted using the normal shift complement available to unit b. Sufficient operators will be provided to resume operation from the control room if warrante *
c. Personnel assignments for the conduct of the test will be in accordance with the Emergency Instruction I-4-lO(A),
Control Room Evacuatio The location of the (Senior) Shift Supervisor conducting the test will be clearly stated in the procedur '.
SITE
e. The test will include local operation of 4 KV breaker, a motor operated valve, an air operated valve, local start of a diesel, and local control of a charging pum Included in the precautions will be explicit conditions for which the corrtrol ling station.wJlt be reestablished.in: the... control room for any evolution. The test procedure will be rev1ewed upon completion of the revision. This item remains ope. Shift Logs and Operating Records a. The inspector reviewed the following plant procedures to detennine the licensee established requirements in this area in preparation for a review of selected logs and record AP-5, Operating Practices, Revision 10, May 21, 1980; AP-6, Operational Incidents, Revision 6, February 22, 1979; AP-13, Control of Lifted Leads and Jumpers, Revision 4, February 11, 1980; Operations Directive Manual; and, AP-15, Safety Tagging Program, Revision 1, November 21, 198 b. Shift logs and operating records were reviewed to verify that:
Control room log sheet entries are filled out and initialled; Auxiliary log sheets are filled out and initialled; Log entries involving abnormal conditions provide sufficient detail to communicate equipment status, lockout status, correction and restoration; Log book reviews are being conducted by the staff; Operating orders do not conflict with Technical Specification requirements; Incident reports detail no violation of Technical Specification LCO or reporting requirement; and, Logs and records were maintained in accordance with Technical Specifications and the procedures in 3.a above *
c. The review included the following plant shift logs and operating records as indicated and discussed with licensee personnel:
Log No. 1 - Control Room Daily Log, May 1-31, 1981 Log No. 6 - Primary Plant Log~ May 1-31, 1981 Log No. 7 - Secondary Plant Log, May 1-3i, 1981 Log No. 8 - Unavailable Equipment Status Log, May 1-31, 1981 Night Orders, April 30, 1981 - May 28, 1981 Lifted Lead and Jumper Log - All active Nonconformance Reports for April 1981 Incident Reports 81 - 83-85, 91-98, 100-101, 104, 106, 108-110,, and 118 The inspector had no questions relative to logs reviewed during this inspection perio. Plant Tour a.. During the course of the inspections, the inspector made observations and conducted multiple tours of plant areas, including the following;
{_1)
Control Room (daily)
(2) Relay Rooms (3.) Auxiliary Building (4) Vital Switchgear Rooms (5) Turbine Building (6)
Yard Areas (7)
Radwaste Building (8) Penetration Areas (Q)
Control Point (10) Site Perimeter (11) Fuel Handling Building (12) Containment (13) Guard House
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b. The following determinations were made:
Monitoring instrumentation:
Th~ inspector verified that selected instruments were functional and demonstrated parameters within Technical Specification limit Valve positions. The inspector verified that selected valves were in the position or condition required by Technical Specifications for the applicable plant mode. This verification included control
. board indication and field observation of valve position (Charging/ *
Safety Injection, Auxiliary Feedwater, and Containment Sp~ay Systems).
Radiation Controls. The inspector verified by observation that control point procedures and posting requirements were being followe Plant housekeeping conditions. The inspectors observed that several areas of the plant were in need of housekeeping. This item was discussed with, and acknowledged by, plant management during the exit intervie Fluid leak No fluid leaks were observed which had not been identi-fied by station personnel and for which corrective action had not been initiated, as necessary.
Piping vibratio No excessive piping vibrations were observed and no adverse conditions were note Selected pipe hangers and seismic restraints were observed and no adverse conditions were note Equipment tagging. The inspector selected plant components for which valid tagging requests were in effect and verified that the tags were in place and the equ.ipment in the condition specifie By frequent observation through the inspection, the inspector
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verified that control room manning requirements of 10 CFR 50. 54 (k)
and the Technical Specifications were being me In addition, the inspector observed shift turnovers to verify that continuity of system status was maintained. The inspector periodically questioned shift personnel relative to their awareness of plant conditions and knowledge of emergency procedure Release On a sampling basis, the inspector verified that appro-priate documentation, sampling, authorization, and monitoring instrumentation, were provided for effluent release Fire protection. The inspector verified that selected fire ex-tinguishers were accessible and inspected on schedule, that fire alarm stations were inspected on schedule, that fire alarm stations were unobstructed and that cardox systems were operable. Details of the NRC fire protection review are discussed in paragraph *
Technical Specifications. Through log review and direct observa-tions during tours, the inspector verified compliance with selected Technical Specification Limiting Conditions for Operation. The following parameters were sampled frequently:
RWST level, BAST level and temperature, containment temperature, boration flow path, shut~own margin, offsite powe In addition, the inspector conducted periodic visual checks of protective instrumentation and inspection of electrical switchboards to confirm availability of safeguards equipmen Security. During the course of these inspections, observations relative to protected and vital area security were made, including access controls, boundary integrity, search, escort, and badgin During this report period, a strike occurred involving members of the contracted guard force. Details of this occurrence are discussed in paragraph 10. With reqard to routine tours, no unacceptable conditions were noted-.,*.: The following acceptance criteria were used for the above items:
Technical Specifications Operation Directives Manual Inspector Judgement e. The inspector had no further questions relative to tours made during this inspectio s: Licensee Events In Office Review of Licensee Event Reports The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followu The following LERs were reviewed:
UNIT 1 81-0l/03L 81-02/03L
- 81-03/03L
- 81-04/03L
- 81-05/03L Axial Flux Difference out of Target Band Loss of Service Water Flow Indication to No. 14 Containment Fan Coil Unit Loss of No. 12 Component Cooling Loop Failure of Control Room Emergency Air Conditioning Sys tern Damper High Steam Flow Channel II Comparator Failure
- 81-06/03L
- 81-07/0lT 81-08/03L
- 81-09/0lT
- 81--10/03L
- 81-ll/03L 81-12/03L
- 81-13/03L
- 81-.14/03L
- 81-15/03L
- 81-.16/03L
- 8.l-.17 /03L 81-18/03L
- 81-19/03L
- 8.l-20/03L
- 81-21/03L 81-22/03L
- 81-23/03L 81-24/03L 81-25/04L 81-26/03L
- 81-27/03L
- 81-28/03L
Loss of Audi.bl e Fire Detection Signal Safety Injection Throttle Yalves Not in Required Position
Auxiliary Alano Typewriter Failure Unidentified Leak in Containment Indicated By Malfunction of Sump Pump Controls No. 11 Containment Fan Coil Unit Inopera61 e No. 11 Containment Fan Coil Unit Inoperaole No. 2 Fire Pump Coo 1 fog Water Leak No. 12 Centrifugal Cna.Y.ging Pump Inoperao.le No. 12 Centrifugal Cnarging Pump Inoperaole Rod Position Indicator 2D1 Inoperable Rod Position Indicator 201 Inoperao] e Failed Snubber on No. 12 RHR Pump lA Diesel Generator Inoperable Loss of Audible.Fire Detection Signals Failed Snubber on No. 11 RHR Pump Loss of Level Indication on Nos. 11 and 12 Boric Acid Tanks Boric Acid Storage System Volume Less than Technical Specification Limit of 5106 Gallons Containment Air Lock Inoperaele Auxiliary Feedwater Storage Tank Less than 200'~000 Gallons Unmonitored Release of Waste Gas Loss of Audible Fire Alarm Signal Airborne Contamination - Unit l Auxiliary Building (Pl ant Alert)
Thimble Leak in the Incore Flux Mapping System
- 81-29/03L
- 81-30/03L
- 81-31/0lT 81-32/03L 81-33/03L 81-34/03L
- 81-35/03L 8l-36/03L UNIT 2 81-01/03L 81-02/03L
- 81~03/03L 81-04/0lT
- 8l-05/03L
lA Diesel Generator Inoperable due to Erratic Governor Control Non-functional Fire Barriers Containment Cooling System - No. 12 Fan Coil Unit Failure to log and Acknowledge Operational Events with Entries Into 'Actfon.. Statements No. 2 Fire Pump Inoperable Leak i.n Spent Fuel Pit EC.CS Subsystem Inoperah le Inoperable Fire Hose 2A Diesel Generator Inoperable 2A Diesel Generator Inoperable Unauthorized Release of Waste Water Service Water Leak in Containment All Reactor Coolant Pumps and RHR Pumps Out of Service b. Onsite Licensee Event Followup (11 For those LERs selected for onsite followup (denoted by asterisks in detail paragraph 5}., the inspector verified the reporting requirements of Technical Specifications and Regulatory Guide 1.16 had been met, that appropriate corrective action had been taken, that the event was reviewed by the licensee as required by AP-4, 6, and 7, and that continued operation of the facility was conducted in accordance with Technical Specification limits. The following finding relates to the LERs reviewed on site:
Unit 1
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81-03/03L No. 12 Component Cooling Heat Exchanger was made inoperable due to failure of a dissimilar metal weld in the service water side drain line. Repairs were made within the time allowed by Technical Specifications. The inspector further confirmed that design change requests, 1-SC-0516 (Unit 1)
and 2-SC-0517 (Unit 2}, have oeen initiated to replace the material and remove the requirement for dissimilar metal welding in this applicatio *
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81-04/03L Freezing of the dampers was attributed to steam generator blowdown steam exhausted in the vicinity of the intake duct. A design change has been completed on Unit 1 to return blowdown steam to the condense The same change is in progress on Unit 2 and will be complete by the next cold season. These actions should prevent recurrence of this event~
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81-05/03L 81-06/03L and 81-19/03L
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81-07/0lT
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81-09/0lT During High Steam Flow Safety Injection channel functional testing, the Turbine Impulse Pressure signal which provides the nonnal steam flow signal malfunctioned due to a failed comparator unit. The comparator was replaced. The defec-tive unit was repaired under DR PD-1273 on March 4, 1981 and returned to spare These reports *detail loss of the audible alann associated with fire detection systems. The problem was initially attributed to impedance mismatch caused by additional loads on the syste An evaluation is in progress to confinn the cause. This is an unresolved item (272/81-12-01)
pending completion of the evaluation, submittal of a supple-ment to LER 81-19, and completion of dictated corrective action. The inspector confirmed that the audible alanns are tested at least monthly as part of the surveillance testing on pull boxe Details of this event are outlined in NRC Inspection Report 50-272/81-0 In a supplemental LER, dated March 20, 1981, the licensee concluded that the particular configuration of throttle valve positions found did not constitute unsafe operation of the facility under postulated accident con-ditions. This finding is based on safety evaluation SGS/M-SE-078, dated February 4, 1981, prepared with the concurrence of the vendo The licensee has taken additional procedural steps to prevent recurrence of this even This report documents an apparent unidentified leak in containment, later determined to be failure of the level controls for No. 12 Containment Sump Pump resulting in short-cycling and a conclusion that significant amounts of water were entering the sum The level detector, LD-7750, was removed from the control circuit, and, as documented in supplementary LER 81-09/01-1, dated May 7, 1981, the detector was replaced during a shutdown on March 9, 1981, restoring system alignment to nonna *
81-10/03L and 81-11/03L 81-13/03L and 81-14/03L 81-15/03L and 81-16/03L 81-17/03L and 81-20/03L
During operation, a leak in the penetration area on the spool piece to valve 11SW57 was identified. The leak was. outside containment and did not render No. 11 Fan Coil Unit tnoperable., however the service water isolation necessary for repair did *. The unit was isolated on January 26, 1981. for repair. Following a subsequent reactor trip,. Technical Specifications require that operability be. restored to permit reactor operation in Mode 1. Work had not star,ted on the leaking wel The Fan Coil Unit was returned to service and a reactor start-up conducte FoJJ ow-i'ng *,s.ta.rtup, the Fan Cai 1 Unit was again isolated* on January 27, 1981 to accomplish the weld repair. Repairs were completed on January 30, 1981 within the. time constraints of Technical Specification 3.6. Both of these events rendered No. 12 Centrifugal Charging Pump inoperable on February 1, 198 The first was a lubricating oil cooler leak which required pump inoper-abil ity to replace the cooler. Subsequent to this repair, an oil seal leak caused the thrust and main bearings: to fail due to loss of lubricatio No connection between these events was identified. Replacement of the bearings was accomplished within the time limits of Technical Specification 3.5. Both of these events relate to failure of individual rod position indication for control rod 20 This event was discussed in NRC Inspection Report 50-272/81~04. Initial corrective action taken on the connector resulted in temporary restoration of indication. The second failure precipitated complete replacement of the connector and cable assembly. Appropriate flux mapping to confirm rod position in accordance with Technical Specification 3.1.3.2.* a was confirmed by the inspecto These reports detail failed TNC snubbers found during inspection and testing irr accordance with IE Bulletin 81-01. The LER describes corrective actioru*.as replace-ment in kin The Bulletin response, dated March 12, 1981, cormnits to a re-design using strut restraints or reinspection of a representative sample by June 1, 1981. This will be confirmed during a subsequent inspection of corrective actions resulting from the Bulleti,.----------
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81-21/03L Level indication for both No. 11 and No. 12 Boric Acid Storage Tanks became inoperable for the same reason, boric acid plugging of the sensing Jines. The inspector reviewed completed Work Orders OD-942768 and OD-94288 Restoration of level indication was accomplished by blowing out the lines with ai No regular program to keep sensing lines clear by periodic blowdown has been established. The licensee committed to initiation of such a program. This item is unresolved (272/81-12-02)
pending review of effective action ~9 prevent recurrenc * --
81-23/03L Loss of air lock seal inte*grity appears to be a repetitive problem due-to seals coming out of the channe An eval-uation to establish corrective action to prevent recurrence has been initiated by the licensee. This item is unresolved pending review of evaluation conclusions (272/81-12-03).
81-27/03L This item is reviewed in detail in NRC Inspection Report 50-272/81-0 /03L The leaking thimble has been isolated at the seal tabl Acceptaole flux maps are obtained with the remaining 58 thimbles. Plans are being made to replace the thimble during the next refueling outage. The failure mechanism will be reviewed oy tne inspector at that time (272/81-12-04}.
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81-29/03L Erratic Diesel governor control was attributed to low oil level in the governor. The inspector confirmed that Inspection Orders 100733 and 100734 have been initiated and are 6eing completed on a monthly schedule to verify oil 1 eve /03L Tnis occurrence was attributed to lack of knowledge on the part of personnel running hose through the plant relative to integrity of fire barrier penetrations. The licensee stated that Administrative Procedure AP-9, Control of station Maintenance, will be revised to in-corporate fire barrier considerations. The inspector revi.ewed the draft of Revision 5 to this procedure and noted*that specific reference to fire protection require-ments is included on the work order fonn ~- The licensee stated that Revision 5 will be issued by :July 2, 198 This item is unresolved pending review of the issued Procedure (272/81-12-05}.
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81-31/0lT This report of a pinhole leak on a drain line weld for No. 12 Containment:'Ean Coil Unit was initially made via telephone in accordance with IE Bulletin 80-2 The licensee has assigned prompt report designations to these reports for consistenc No hard copy of the prompt repo~t was transmitted to the NRC Regional Office. The licensee has agreed to send a copy for completeness of the file. The inspector had no questions relative to the event or corrective actions take /03L. This event resulted from incomplete. retest of a design change made to valve power 1ockout circuits for valve 11SJ4 As a result, a wiring error which prevented Unit 2 valve opening was not detected. Technical Specifications require the valve to be shut with power remove To preclude recurrence, the licensee has provided additional guidance to-shift supervision relative to reviews of incomplete design change packages. A supplemental report will be submitted. when the li.censee's evaluation of this event has been completed.. This item remains unresolved i
pending review of the supplemental report (272/81-12-06).
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81.-03/03L This event is reviewed in NRC Inspection Report 50-311/
81-06. The inspector had* no further questions on this ite /03L With the: plant in Mode 5, replacement of relief* valve 2RH3 was required as part of a plant modification. The valve is in the common RHR suction piping and necessitated shutdown of both RHR pump At the time, reactor decay heatwas negligible since no critical operation had been conducted for the previous seven month Preparations were made to accomplish the work as rapidly.as possibl However, the total*task took 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 22 minutes, exceeding the one hour.allowed by Technical Specification 3.4.1.1.b.2b.for RHR to be de-energized~ All other aspects of the Action Statement were met and the plant was already in the condition specified by Technical Specification 3. The inspector had no further questions relative to this item. However, the total task, from isolation to reestab-1 ishment of RHR flow, took 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 22 minutes. This exceeded by one hour allowed by Technical Specification 3.4.1.l.b.2b for RHR to be de-energized. All other aspects of the Action Statement were me At the end of one hour, Technical Specification 3.0.3 governed and was complied with, in that the plant was, and remained in, Mode The inspector noted that new Technical Specifications, issued with the full power license on May 20, 1980, no longer have a one-hour time limit. The inspector had no furth~r questions on this ite *
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c. Of the reports reviewed, the following LERs detail events which required correctiv~ actions unde~~the license or Technical Specification:
50--272/81-07 /OlT 50-272/81-31/0JL The inspector)had-no further questions relative to LERs reviewe.
Review of Periodic and Special Reports Upon receipt,. periodic and-special reports submitted by the licensee pur-suant to.Technical Specifications 6.9.1 and 6.9.2 were reviewed by the inspecto This review included the following considerations:
The. report included the information required to be reported by NRC requirements; Test results *. :and/or supporting information were consistent with-design predictions and performance specifications; Planned corrective action was adequate for resolution of identified problems; and, Determination whether any information in the report should be classi-fied as an abnormal occurrenc Within the s:cope of the above, the following periodic reports were reviewed by the inspector:
Unit 1 Monthly Operating Report - April 1981 Unit 2 Monthly Operating Report - April 1981 No unacceptable c-onditions were identifie.
FulliPower License Conditions (Unit 2)
On January 14, 1981, April 28, 1981, and May 19, 1981, the NRC staff, including the Senior Resident Inspector, br.iefed the Commission on the status of Salem Unit 2 and the proposed licensing action to authorize operation in excess of 5%
.rated thermal powe The inspector reviewed_a:~urnb:er.*of these*.. jtems to deter-_
mine ~status,*of.;.impl~entati-on.:. The_ fol lowing >comments apply J~o the** areas -
revi-ewed (Numbers* refer to paragraph references in the full power license):
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2.C.(2)
Engineered Safety Feature Reset Control By discussions with personnel and review of surveillance testing data, the inspector confirmed that design modifications to control circu-i:t-ry for valves 2FP147, 2SJ53 and 21-24MS18 had been made and successfully retested to ensure that the valves remain in the isolation condition on reset of initiating signal. The following surveillance procedures periodi-,
cally test this feature on isolation valves and on ECCS equipment;
-SP(0)4.3.2.1.l(c), SP(0)4.3.2.l,l.(a), and SP(0)4.6.3.1.2(b).
Testing in accordance with these procedures is conducted every eighteen months and was completed for Unit 2 in February 1981, prior to heatup and power operatio ~C, *. (3}: ~speci-al Low Power Tes.t Progra Through discuss ions with 1 i censed personnel and review of test program documentation, the inspector confirmed that all licensed operators had participated in the requisite number of natural circulation tests. The training was completed prior to unit operation in excess of 5% rated thermal powe.C.(6) SMII-6 Open Items.List. The inspector reviewed the remaining open i:tems,,documented in a licensee listing dated May 6,-1981. All items have been deferred until 11commercial operation" indicating*
- no impact on the startup test program. Approximately 74 items remain to be resolved. Following discussions with personnel and review of evaluations prepared by the licensee, the inspector identified-no items which would have an inimical effect on the test program or on reliable operation of associated equipmen.C.(lO)(b)(l) Wrapping of 125 VDC control power at elevation 64
- The inspector confirmed, by inspection of field routi:ng for the con.;.
trol powe~ cable, that the A and B trains of control power had been wrapped to provide fire protection in the switchgear roo The C train, due to its proximity to associated switchgear was not wrapped. This is consistent with the licensee's criteri The l:nspect.or had no further questions on this ite.C~(lO}{b.)(2J. Alternate shutdown procedure deficiencies. The inspector reviewed on-the~spot changes made to procedures OI 1-3.6, Hot Standby to Cold Shutdown, EI I-4.9, Blackout, and EI I-4.10, Con-trol Room Evacuation, to confirm that NRC concerns relating to th procedures had been ad~ressed. In addition, the inspector examined equipment and facilities necessary to carry out the alternate shut-down procedures. The following aspects of the procedures were found acceptable:
- the procedures are adequately coordinated to invoke the local operating procedures _for equipment impacted by fir control room evacuation is dictated only be a condition causing it to be uninhabitable, not simply by loss of contro placement of personnel is addressed and required keys and proce-dures to be removed from the control room have been identifie the unaffected control room is suggested as the preferred alter-nate control locatio all e~uipment listed in local operating instructions has been prestaged, with most of this equipment being placed in locked cabinets with keys available in the hot shutdown pane *
- system status logs have been established at the hot shut-down panel to provide a record of equipment which has been disturbed for local operation and to provide a mechanism for restoring nonnal operatio guidance is provided for rapid boration in the event
- that reactor shutdown has not been directly verified prior to leaving the control roo procedures and equipment for detennining hot and cold leg temperatures by cutting into penetration area cabling have been provided at the dedicated alternate shutdown interface cabinet in the penetration are headsets for portable radios have been obtained and provided to the operating staff to ensure more reliable radio communications in high noise area.C.(lO}(c)
-- 2.C. tlO}(e)
-- 2. c. (21 ) (b)
Emergency lighting. There were 132 (61-Unit 1, 71-Unit 2)
battery-powered emergency lighting units installed in the station to provide lighting independent of plant distribution systems. These battery-powered lights were rated for eight hours use (see Detail paragraph 8).
Re-routing of alternate shutdown power fee By inspection of cable routing, the inspector confirmed that the dedicated power feed for alternate shutdown instrumentation has been re-routed through elevation 64' directly to the penetration area, thus elimating the potential interaction on elevation 84' with normal instrument powe Training in the recognition and mitigation of low pressure injection perfonnance degradation. The inspector confirmed that this information was provided to licensed operators in a memorandum from the training department dated April 28, 1981 which was distributed to each operato In addition, this area is a subject to be covered in the operator re-qua l ification progra.e.(24}(el Leak rate testing for primary coolant sources outside con-tainmen The inspector confirmed, by discussions with personnel and review of test data, that the system leak determinations had been complete The following leak rates were obtained; eves - 94 drops/min, Safety Injection System - 46 drops/min, RHR - 4 drops/min, Waste Gas System -
5369 SCCM, Waste Liquid - no leakage, Sampling - 52 ml/min, Containment Spray - no leakage. The licensee is preparing a fonnal report of these result In each case of iden-tified systems leakage, a Work Order to repair the leak was initiate The inspector had no further questions relative to license conditions to be completed prior to operation above 5% rated thermal powe *
8. Fire Protection Reivew
including the resident inspectors, conducted an on-site evaluation of the licensee's fire.protection cable interaction study and the corrective actions precipitated by that study. The licensee's evaluation and modifications to provide adequate independence for redundant safe shut-down equipment and cable are incomplet * The findings and recommendations of the team are included in the Safety Evaluation Report, NUREG 0517 Supplement 6, issued in support of full-power licensing of Salem Unit 2. During the course of the review, two resident inspectors and one Region-based inspector verified that evaluation tools (drawings, etc.) reflected plant as-built conditions, confinned that design modifications (barriers and cable wrapping) were being made as dictated by evaluation conclusions, and reviewed the licensee's alternate shutdown procedures for adequac As documented in the Safety Evaluation Report, incomplete items remain to be verified by the NRC Office of Inspections and Enforcement as follows:
The licensee's overall program verification is scheduled for completion by June 5, 1981. This was later modified to July 15, 1981 (311/81-11-01) *
Several modifications to the alternate shutdown procedure to be com-pleted prior to operation of Salem Unit 2 above 5% rated thermal power with applicability to both unit Completion of the cable wrapping/modification program by July 31, 198 t311/81-ll-02).
The review team concluded that fire protection measures currently in place are adequate for continued operation of Salem Unit 1 and for the issuance of a full power license for Salem Unit 2 with the understanding that corrective actions delineated in the Safety Evaluation Report will be implemented on a schedule subject to further staff approva In the course of the staff's onsite review, one area in the 480/~30 VAC Switchgear Room on elevation 84' in the Auxiliary Building was identified in which a single postulated 20-foot diameter fire could potentially fail all instrument channels, including the independent safe shutdown instru-mentation provided for alternate shutdow The review team concluded that this presented an immediate safety concern. Accordingly, the in-spector* obtained, and documented in correspondence from NRC Region 1 dated May 5, 1981 (IAL 81-22), a licensee committment to take immediate corrective actions. These actions included:
Re-routing of the alternate shutdown power feed in order to provide protection for this cable from a fire affecting the normal instrument trains. This will be completed by June 5, 1981 for Units 1 and Innnediate stationing of a dedicated, continuous fire watch in the
1 elevation switchgear room until the modification described above is complete *
During the period when new leads are being landed, and no power feed to the alternate shutdown instruments is available, an additional fire watch*will be stationed continuously in the Relay Roo The final engineering verification of the fire protection analysis and corrective actions, which will confirm no similar mis-routings, will be completed by June 5, 198 The inspectors confirmed the immediate actions. Subsequent discussions with the licensee indicated that additional work resulting from the team review may impact the schedule to complete the final engineering verification. A new date for completion of July 15, 1981 was documented in correspondence to NRC Region 1 dated May 20, 198 As stated above, this action will be confinned by the inspectors during a subsequent inspectio c. It was noted during plant tours that the licensee had placed approxi-mately ten battery powered lights (per unit) in the plant. This number is insufficient to illuminate the areas and access routes required by the alternate shutdown procedure. Fu*rther examination revealed that the battery packs installed with two-oulbs were rated for only 3.75 hour8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> In view of this finding, the team reconnnended that additional lighting (self-contained battery packs rated for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) be provided in all areas occupied during perfonnance of the alternate shutdown procedure and routes of personnel access to and from those operating area *
This item was examined in the context of licensee correspondence to NRC(NRRl, dated March 19, 1981 which related to paragraph III.J of Appendix R to 10 CFR 5 The licensee asserts the following:
III.J Emergency Lighting Emergency lighting units with at least an eight hour battery power supply shall be provided in all areas needed for operation of safe shutdown equipment and in access and egress routes theret Design Description:
PSE&G has previously conmitted to install an eight hour self-contained emergency lighting system. This has been approved by the NRC staf Implementation Schedule:
Installation has been completed. Salem Units 1 and 2 are in compliance with this requiremen *
Further review of correspondence and discussions with personnel revealed the information and interpretations described belo In.the original response, dated August 24, 1977, to Appendix A of Branch Technical Position APCSB 9.5-1, the licensee's position relative to item D.5 emergency lighting is stated in the following:
3.4.5 Lighting and Communication Lighting and two-way voice communication are vital to safe shutdown and emergency response in the event of fire. Suitable fixed and portable emergency lighting and conununication devices should be provided to satisfy the following requirement.4.5.a NRC Position Fixed emergency lighting should consist of sealed beam units with individual 8:-.hcur minimum battery power supplie PSE&G Response to 3.4.5.a - The intent of this guideline is partially met. Appropriate corrective action is being taken where necessary to ensure compliance with guidelin A fixed emergency lighting system is provided. This system receives power from the 125V and 250V D.C. system Emergency lighting is provided in areas which are required for safe shutdown (e.g., the Control Room and the Hot Shutdown Station) and in most areas where required for safe evacuation from all areas of the station. The batteries are capable of supplying D.C. power to the emergency equipment for two hours of operation after a loss of A.C. powe If the normal power source is lost, the battery chargers are energized from the Emergency Diesel Generators, providing emergency lighting for an unlimited duration. Since the fixed emergency lighting system does not illuminate all areas of the station, this system will be supplemented with battery powered portable hand lights in the event that nonnal station lighting is lost during a fire conditio In correspondence dated June 5, 1978, the NRC staff reiterated its position in the following:
(SP) 5. Section 3.4.5 Lighting ana Co11111unications a. As stated in Appendix A, Section D.S(a), it is our position that fixed 8-hour capacity self-contained emergency lighting of the fluorescent or sealed beam type be provided in areas that must be manned for safe shutdown and for access and egress routes to and from all fire area It is noted that the licensee's intent was to maintain hot standby and not cooldown. Further, the above position describing access refers to fire areas vice alternate shutdown location *
I
'
In response to the above staff position, the licensee, in a letter dated July 26, 1978, provided the following information:
PSE&G RESPONSE Question 5. PSE&G has re-examined the Station's emergency lighting system and considers that the present fluorescent lighting, as well as the planned additional fixed sealed beam lighting (see Action Item 13 of the *** Station Fire Protection Program Review)
will provide adequate emergency lighting for those areas that must be manned for safe shutdown and for access and egress routes to and from all fire areas. The power supply for the fixed emergency lighting system (current and planned addition)
is available for essentially an unlimited duratio In addition, the Station is presently provided with ten sealed beam battery powered (8-hour self-contained) hand lights to be used during emergencies. This infonnation was discussed in Sections 3. (a} and (b) of the Salem Station Fire Protection Program Revie Action Item 13 refers to the addition of approximately 10 additional emergency lights to provide for safe evacuation from all areas of the station. Design Change Request 1-ED-299 was initiated in early 1978 to install this additional lighting. Purchase Requisitions 15667 and 76799 were written in February and July 1978 to order 11 lighting units for Unit 1 and 19 for Unit 2, respectivel An error was made in the model number such that two-bulb units were ordered. Manufacturer's data in-dicates that two-bulb units will support an illumination time of 3.75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> and single bulb units will support an illumination time of hours. At that time, the order was placed as "non-safety related" and the licensee's quality assurance program was not applied to fire protectio On January 19, 1979, the staff responded to the above licensee's posi.tion lly reiterating the original NRC position as follows, " Your response to Question Sa is unacceptable. It is our position that fixed 8-hour capacity self-contained emergency lighting of the fluorescent or sealed beam type be provided according to Section D.5 of Appendix A to BTP ASB 9.5-1."
In a letter dated March 2, 1979, the licensee stated the following committ-ment, "We will provide fixed 8-hour capacity self-contained emergency lighting in accordance with Section D.5 of Appendix A to BTP ASB 9.5-1 ***
Implementation date - October 1979 - both units."
The January 19, 1979 letter and a January 31 - February 1, 1979 meeting with the staff also initiated the systems interaction analysis necessary to assure independence of systems required for shutdown as well as cool-dow *
As evidenced by the licensee's responses and based on discussions with personnel, the licensee still believed that fixed emergency lighting powered by inverters drawing from the station batteries constituted a system meeting the intent of BTP 9.5-1. Based on the availability of three inverters, the licensee considered a total loss of station lighting incredible. The staff's objection was presumed to be aimed at the use of hand lanterns. Further correspondence with the staff does not address emergency lighting until the March 19, 1981 letter was received. The Fire Protection Safety Evaluation Report, (FPSER) dated November 20, 1979 concludes that the installation of fixed eight-hour capacity self-contained emergency lighting of the fluorescent or sealed beam type has been completed for both units.* The licensee still believed that the station battery/inverter system met this requirement. The FPSER further documents the co11111ittment to complete the fire hazards interaction analysis which was continuing at the time of this review. It is noted that the licensee did not consider the total loss of lighting credible during the evaluations conducted abov The fire protection review team, in evaluating the station lighting system as related to the overall interaction analysis, concluded that, by the licensee's own criterion, a single postu~:ated 20-foot diameter fire in the relay room could affect all three emergency lighting inverters. Under station blackout conditions, such a fire would make fixed, independent battery pack lighting in plant areas necessar Accordingly, installation of eight-hour battery packs in alternate shut-down areas and access routes was recommended by the review tea The postulated loss of all station emergency lighting was not considered in any analysis made by the licensee* prior to the NRC revie The May, 1981 SER documents the licensee's * * *schedule for completion of battery pack installation. As stated above, this will be confirmed by NRC inspectio Amendment 21 to Unit 1 Facility License DPR-70 adds the following license condition:
2.C.5 Public Service Electric and Gas Company shall maintain in effect and fully implement all provisions of the approved fire pro-tion plan. The approved fire protection plan consists of the document entitled, "Salem Nuclear Generation Station Unit N Fire Protection Program Evaluation Comparison BTP APCSB 9.5-1 Appendix A" which includes: Initial Issue, submitted with letter dated September 14, 1977 additi*onal infonna~ion submitted with letters of July 19, July 26, September 8, and September 26, 1978 and February 15, March 2 and November 5, 197 The March 2, 1979 letter referenced in the license documents a committment to install eight-hour fixed lighting by October 1979, which, as described in previous correspondence, included ten battery pack On May 5, 1981 it was detennined by the inspectors that installed battery packs would not provide an ei~ht-hour illumination time. The inspector further noted that 10 CFR 50.48 {Federal Register 45 FR 71569, dated October 29, 1980)
suspends compliance dates which were based on previous fire protection*
evaluations satisfying Appendix A to BTP/APCSB 9.5- *
At the conclusion of this inspection period, and prior to raising Unit 2 power level above 5%, the licensee had completed installation of approximately 120 battery packs for emergency lighting in both unit The battery packs are Exide Model B-200 and will provide eight hours of illumination when installed with 2 25-watt lamps or four halogen (12 watt) bulbs, based on vendor catalog information. The licensee has not established a surveillance test or frequency for these units to assure continued operability. This is an open item (311/81-11-03).
- The inspector had no further questions on the fire protection revie. Operational Events a. Unit 1 At 2:09 a.m. on May 20, a spurious Safeguards Equipment Cabinet lB operation started the lB diesel and the blackout loading sequenc The service water cross connect to the turbine building was automatically isolated. Since cooling to the main turbine lube oil cooler was isolated, the control room operator tripped the main turbine automatically resulting in a reactor trip. Refer to Detail 13.. b of this repor At 8:41 a.m. on May 21, unit 1 tripped from 30 percent power. Testing of the output breaker from the Gas Turbine Generator (Unit 3) to the 13 KV switchyard caused unit 1 shutdown when portions of the 13 KV bus were deenergized causing loss of two of four Reactor Coolant Pumps (loss of power). The protective circuitry tripped the reactor when two of four reactor coolant pumps were deenergized. The licensee stated that the engineering staff would examine the current test procedure and equipment design to detennine if any changes were necessary. Caution tags were attached to the breaker to preclude local operation of the breaker in the test position. These tags will remain attached pending resolution by the engineering staf On May 21, Westinghouse notified the licensee of a potential Volume Control Tank (VCT) problem. Failure of one of the VCT level instruments may cause the VCT to empty and damage the centrifugal charging pump which would continue to operate. The vendor's recommended correction directs operators to confirm proper VCT level, letdown, makeup, and diversion flow if anomalous indications or alanns are received. Licensee Event Report 50-272/81-54/0lT refer At 4:42 p.m. on May 25, the main turbine was removed from s~rvtce to investigate high vibrations on No. 7 and 8 bearing on No. 13 LP turbin Subsequent inspection revealed several missing blades and connecting shrouds from the L-3 stage on each end of No. 13 LP turbine. Repairs were still in progress at the conclusion of the report perio ~
b~ Unit 2 Heat up to mode 3 (Hot standby) was completed at 3:59 a.m. on May 1 On May 19, the Commission authorized the Director of NRR to issue a license for the full power operation of SALEM unit On May 20, the license was issue At 8:40 a.m. on May 20, control rod 204 dropped during startup when the reactor power was in the intennediate range. The reactor was shut dow Investigation revealed a faulty connector at the vessel head connection. The faulty connector resulted in an open circuit to the stationary gripper coil causing the rod to drop. After connector re-placement, startup was performed and the reactor was critical at 4:24 a.m. on May 2 Coincident with the trip of unit 1 on May 21 at 8:41 a.m., unit 2 tripped on high steam flow coincident with low-low Tave. This was caused by the instrumentation change required for natural circulation tests. The steam flow bistables were tripped (zero output) for high steam flo A:.signal generator simulated Tave above 547 degrees. The Tave signal generator was powered from a local 125 vac outlet (non vital). Loss of the 13 KV bus cause:! loss of power to the 125 vac outlet and the signal generator. Tave indicated below 543 and a reactor trip occurre Although the SI signal was generated, modification to the solid state protection system in accordance with the natural circulation test pro-cedure prevented actual safety injection. This modification was performed per Appendix A of Startup Procedure 90.0. Subsequent startup and natural circulation training were completed satisfactoril At 5:00 a.m. on May 30, No. 21 Auxiliary Feed Pump was rendered inoperable when a pump bearing failed and shaft damage.; occurred requiring replace-ment. A subsequent reactor trip.at 5:34 a.m. due to low level in No. 24 steam generator precluded further startup testing of the main turbine because of a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Action Statement (Technical Specifications) imposed by the failure of the auxiliary feed pum The pump was still inoperable and maintenance was in progress at the conclusion of the report perio The inspector had no further questions relating to the operational events listed above or licensee's corrective action. Guard Force Strike At 6:10 a.m., on May 27, 1981, the majority of the day shift contract guard force walked off the job and established a picket line on the access road to the Salem and Hope Creek sites. Night shift guards were retained on site and all guard force supervision augmented the number of security guards. All posts and guard force functions were adequately covered. Operations personnel were retained on site until properly relieve At 9:30 a.m., access to the site was physically restricted by the picket Bargaining unit employees at the station, including operations, maintenance, health physics, and I&C personnel, did not recognize the action as valid and agreed to wor Due to the physical restraints on access, the licensee employed a helicopter air lift to transfer personnel. Adequate numbers of station personnel were maintained on site during this actio At approximately 7:30 p.m., on May 27, an injunction was obtai'ned to limit the number of pickets and to move the line closer to the Salem site such that Hope Creek would not be impacted. Harassment and restraint of persons wishing_ to cross the line was also prohibited. Following this action, station personnel were able to travel in and out of the station as necessar Contractor personnel elected to cross the lines within several day At the conclusion of this inspection period," pickets are still_ in place in limited number No problems with access have been noted. Adequate staffing of the security force has been maintained. Further details on this job action are discussed in NRC Investigation Report 50-272/81-16 and 50-311/81-1. Startup Test Report - Unit 2 The inspector reviewed the Startup Test Report transmitted by letter dated May 1, 1981. This reports results of the Unit 2 startup tests from the period April 18 through August 29, 1980 and covers pre-critical tests, initial criticality, zero-power physics tests and a special series of tests on natural circulation of reactor coolant. The inspector verified that the test results reported met test acceptance criteria or were adequately evaluated by.the licensee and the reactor vendor. The report accurately reflects test results for the low power portion of the Unit 2 Startup Test Progra The inspector had no questions relative to the Startup Test Repor. Surveillance The inspector observed required surveillance testing and verified that testing was perfonned in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were properly accomplished, test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel. The inspector observed the following surveillances:
- 2 PD -2.6.039 No. 22 Steam Generator Steam Flow Protection Channel II (Revision 0, dated November 1, 1978}
- 2 PD -2.6.031 No. 21 Steam Generator Steam Pressure Protection Channel II (Revision 0, dated October 25, 1978)
- The inspector interviewed the personnel performing these tests as to the details of the procedures, anticipated or required results, system interaction during the bistable trips, and operation.of the remaining protection system while these circuits were in test. The inspector concluded that qualified personnel were performing the tests and the test results were satisfactor On May 16, 1981, the licensee performed Surveillance Procedure SP(O)
4.4.7.2.2, Emergency Core Cooling to measure the leak rate of specific check valves which serve as a pressure boundary for the Reactor Coolant System. The check valves subject to the test were specified in the draft copy of the proposed "Full Power 11 Technical Specification which would become a requirement as of the date of issuance of the full power licens The inspector reviewed the results of the leak test as follows:
Valve N Leak Rate (gpml Valve N Leak Rate (gpm)
21SJ43 and.
21SJ156 SJ43 SJ156 SJ43 and 23SJ156 SJ43 SJ156 SJ55 SJ139 SJ53 * 22SJ139 SJ55 0.24 23SJ139 SJ55 SJ139 0.73 21SJ56 RH27 SJ56 RH27 SJ56 SJ17 0.1 combined 24SJ56 SJ150 SJ144 RH1 SJ144 0.48 2RH2 0.24 23SJ144 0.73 24SJ144 0.48 As the leak rate or combined leak rate for any group of valves was less than one gallon per minute, tne inspector concluded that the results of the tests wer.e satisfactory. The inspector had no further questions regarding the results of the test. A complete review of the surveillance procedure and the acceptance criteria specified in the procedure will be conducted in a subsequent inspection and is unresolved (311/81-11-04)
pending completion of this revie. Maintenance a. Station maintenance activities of system and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry standards and in conformance with Technical Specifications. The following items were considered during the observation of maintenance related activities:
limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; maintenance was accomplished using an approved procedure;
- functional testing and/or calibration were perfonned prior to returning the component or system to service; quality control records were maintained; qualffied personnel performed tfle maintenance; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemente The inspector observed the disassembly and inspection of No. 21 Auxiliary Feed Pump following its failure on May 30. It was apparent after dis-assembly that the thrust f>earing had failed (reason unknown) causing axia.l movement, internal oinding, and loss of oil.*'from the lubricator on the thrust f>earing. Since the impellers are press-fitted on the shaft, excessive time would Ile required to remove them and the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement would oe exceeded. The licensee elected to install a new shaft with. new impellers. The assemoly was in progress at the conclusion of the report period. The inspector discussed the pump assembly with the maintenance personnel and supervisors to confirm that they were
technically competent to repair the pum Operability of the pump is required 5y Technical Specifications within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the plant must E>:e cooled dow Tfle inspectors monitor this aspect of plant operation through tfie routine* inspection program. The*inspector had no further questions regarding the maintenance on the Auxiliary Feed Pum '
c. Following a spurious operation of the Safeguards Equipment Cabinet (SEC)
l B, the licensee performed maintenance on the cabinet to detennine the caus Initial investigation did not reveal the cause for the spurious operation; however, the licensee replaced the control drawer with a spare and perfonned maintenance procedure M3B to verify operation of the SE During the trouble shooting investigation, it was observed that another load powered from the same 125 vac vital power supply had experienced an overload causing tripping of the supply breaker to the faulted componen The licensee questioned whether the SEC was sensitive to voltage fluctua-tions and performed tests to confirm this premise. Several tests were perfonned to fluctuate the power supply voltage by shorting the power supply tnrough various fuses (1/8 amp, 1 amp and 30 amps).
The power supply voltage was monitored with test instrumentation. The inspector observed that the 1/8 amp and '1 amp test had neglible effect. The licensee reported that the 30 amp fuse caused the voltage to drop to zero before the fuse interrupted the short circuit. After the fuse failed, the power supply output returned to 125 vac. The 1 B SEC operated during this test in a manner similiar to the spurious operation on May 2 The licensee concluded that the SEC was voltage sensitive and an evaluation would be made regarding the sensitivity of the SEC and any necessary changes to preclude future spurious actuations would be identified. This item is unresolved (272/81-12-07) pending review of the licensee's evaluation and corrective actio I L
14. Unresolved Items Areas for which more infonnation is required to determine acceptability are considered unresolved. Unresolved ite~s are contained in Paragraphs 6 and 8 of this repor. Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings.