IR 05000352/1987013
| ML20236K157 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 07/28/1987 |
| From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236K148 | List: |
| References | |
| 50-352-87-13, NUDOCS 8708060435 | |
| Download: ML20236K157 (36) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 87-13 Docket No. 50-352
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l License No. NPF-39 J
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Licensee: Philadelphia Electric Company
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2301 Market Streat
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Philadelphia, PA 19101 Facility: Limerick Generating Station, Unit 1 Inspection Period: May 17 - June 30, 1987 inspectors:
E. M. Kelly, Senior Resident Inspector S. D. Kucharski, Resident Inspector Approved by:
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omes Linv e, Chi fojects Section 2A Date/
Summary:
utine daytime (320 hours0.0037 days <br />0.0889 hours <br />5.291005e-4 weeks <br />1.2176e-4 months <br />) and backshift (23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> including weekends) inspections of Unit 1 by the resident inspectors consisting of:
followup on outstanding items and license conditions; walkdown of the fuel poo'l cooling and cleanup system; plant tours including security and fire protection measures; maintenance and surveillance observations; evaluation of modifications; and, review of LERs and periodic reports.
Refueling activities were observed including reactor vessel disassembly and tne full core offload between.May 28 and June 6.
An allegation concerning the use of procedures to conduct.' refueling activities was also reviewed and is discussed in Detail 13.
Independent inspections evaluated scram discharge volume capacity; refueling cavity seal integrity; and the condition of containment spray header nozzles.
Several meetings were attended onsite during the period, including routine PORC; NRB Meeting No. 203 on June 4; and various outage meetings.
One violation was identified (discussed in Detail 4.9) regarding administrative control of troubleshooting refueling platform position indication. An increased in " ice of reportable events occurred during the inspection period, and followup of each event is addressed in Detail 4.
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. DETAILS l8
~1.0 Principals Contacted Philadelphia Electric' Company J. Doering, Superintendent of Operations R. Dubiel, Senior Health Physicist G. Edwards,' Tech 11 cal Engineer
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L J. Franz, Station Manager M. Gallagher,. Reactor Engineer
' K. Hunt, Refuel Floor Coordinator J. Mi'lito, Supervising Engineer, Field Engineering J. Law, Outage P1anning D.' Neff, Compliance Engineer J, Spencer, Superintendent of Services
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-.R. Scott, Superintendent, Construction Division W. Texter, Supervising Engineer, Maintenance Division l
Also during this inspection period, the inspectors discussed plant status -
and operations with other supervisors and engineers in the PECO, Bechtel and General Electric organizations.
2.0 Followup on Open Items 2.1 (Closed) Followup Item 85-03-09 The subject item involved a commitment by the licensee to incorporate environmental qualification requirements into preventive mainte-nance (PM) programs. The inspector discussed the item with the responsible engineer or the plant staff, reviewed the appropriate
' environmental ' qualification. (EQ) committrents, and verified the computer ratrices developed by the licensee to accomplish the item.
A new administrative procedure A-25.2 entitled EQ Program (in the draft stage) was also reviewed by the inspector.
The procedure is intended to provide compliance with the EQ program for electrical and mechanical equipment, and to assure that the equipment is maintained in a condition to perform its safety function for its qualified life when subject tc the conditions predicted. The original commitment for item 85-03-09 was addressed in a letter dated June 17 from the licensee to the NPC Regicn I office.
The licensee's engineering department had prepared and currently controls EQ reports identifying mechanical and electrical maintenance requirements.
EQ requirements were inputted into the licensee's computerized history of maintenance planning system (CHAMPS) computer in order to automatically schedule the necessary work and track activities.
The licensee committed in their June 17, 1985 letter to input EQ requirements into the PM program prior to the first refueling outage, i
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The, extensiveness of this commitment is reflected by the fact that tha-EQ baseline: Includes approximately 2000 I&C maintenance tcsks
request forms and approximately 2000 maintenance department activi"
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ties which will subsequently be generated as maintenance request-forms (MRFs). at the appropriate intervals. As an example, the-inspector reviewed a newly approved PM procedure PMQ-057-008 for cleaning and examination of the combustible gas analyzer panels. The intpector determined that the proper vendor manual information and
.j-recommendations for visual inspection of signs indicative of aging
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had.been incorporated into the procedure; that MRF numbers 868-7464
and -7465 existed to perform the visual inspection of these panels l
every refueling outage; and that the appropriate EQ requirements from
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package number 59 of the EQ report had been incorporated in this
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preventive maintenance activity.
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Engineering review of EQ reports was completed and a set of EQ-related maintenance tasks for safety-related equipment were provided for the plant staff in a memorandum from the electrical engineering department to the Limerick plant manager dated December 31, 1986.
The inspector reviewed the maintenance task forms prepared by engineering, discussed their use and-incorporation into the Unit 1 PM program with the responsible staff engineer, and concluded that the licensee had met their commitment to incorporate EQ requirements into I
the PM program.
The inspector had no further questions and identi-i fied no violations.
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2.2 (Closed) Unresolved Item 85-43-02 The item involved the emergency service water (ESW) Loop B system design that supplies the HPCI system.
The item questioned the adequacy of the design whereby only Loop B was capable of supplying the HPCI room coolers and Loop A only supplied the RCIC room coolers.
In response to the inspector's concern licensee QA representatives and corporate
engineers produced a letter dated March 30, 1973 from the Unit 1
architect engineer addressing the ESW system design. The letter-addressed pump room flooding incidents and other single failure criteria such as pipe whip, missiles, and fire.
The original Limerick ESW system design had not insured protection from common mode events.
Specifically addressed were missiles from rotating machinery, such as HPCI and RCIC turbines, that could damage ESW room cooler supply lines.
Current ESW design physically separates Division 1 and Division 2 ESW piping in the reactor building and eliminates the possibility of a common event causing the loss of both divisions of ESW.
The inspector discussed the conclusions of the above letter with licensee engineers and had no further questions.
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Additionally, the inspector reviewed QA' corrective' action' audit AL-87-48 which addressed the above open item by interviewing opera-tors.to assure that they were aware that ESW' Loop B affected HPCI only and' Loop A affected RCIC.
The QA audit also ascertained that-HPCI/RCIC room cooler ESW loop dependence was emphasized in licensed operator requalification trairo.
9nd that related technical 'specifi-cations were understood.
Finally, the system operating procedure S11.0.A for ESW abnormai alignment wa's verified to' address tne HPCI dependence on ESW Loop B.
The inspector concluded.that the concerns were appropriately addressed and.had no further questions.
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2.3 -(Closed) Deviation 86-17-02
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The' subject deviation involved shunt trip coils installed on p'
outboard isolation valves on the supply and return lines for reactor enclosure cooling wat?r (RECW) ard drywell chilled water (DCW)
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The shunt trip coils had prevented the chilled water L
isolation valves from remote manual closure from the main control room under design basis accident conditions s e the notor operator feeds would be shed from but not automatical'
sequenced back onto their respective safeguards electrical busses.
The licensee responded to the deviation in an October 10, 1986 letter to NRC Region I by describing the immediate corrective action of disabling the shunt trip coils by disconnection of their terminal blocks at the motor l
control centers under a temporary circuit alteration (TCA) number
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737..The TCA remained in effect until the end of Unit i first cycle i
operation on May 15, 1987.
1.icense condition 2.C.10 requires the installation of automatic isoiation capability for the outside containment isolation valves for the RECW and DCW systems. Modification number 84-106 was initiated during the inspection period to upgrade the design of the isolation valves to meet the requirements of GDC-56 and license condition 2.C.10.
Portions of the modification were reviewed in NRC Inspection Report numbers 50-352/87-09 ano 87-16.
The completion of modifications to meet license condition 2.C.10 involve removal of TCA-737 and removal of the shunt trip coils for the 8 Osolation valves affected by modification 84-106. The completion of the modification will be followed in future NRC inspections, and therefore the licensee's response to the subject deviation is considered closed. Tha inspector had no further questions and identified no violations.
2.4 (Closed) Unre_ solved Item 86-23-03 The item involved the failure of the Loop A drywell spray outside containment isolation valve HV-51-1F016A reported by the licensee in LER number 85-102.
The inspector's concern was for the isolation of one of the two loops of drywell spray indefinitely, although drywell spray is not a system requir.ed by t.echnical specifications.
Later NRC
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inspections addressing unresolved item 86-23-03 concluded that operation with one of two loops was an acceptable condition pending the repair of the loop A isolation valve.
The inspector observed the repair to residual heat renoval (RHR)
system valve HV-51-1F016A under MRF 86-6449. The inspector reviewed completed work packages documenting the repairs performed under work instruction WI-2106 and in accordance with 8 different maintenance procedures for removal, repacking, repair, and reinstallation.
The inspector also discussed the repair of the valves with the assistant piping foreman and the craft involved in machining the valve body.
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clearance problem in the valve body had been found which was the cause i
of the failure of the valve disc to seat and seal.
Repairs included grinding the lower left and right sides of the west wedge casting internal to the valve body for better seat contact.
Bluing of the I
seat surf. aces had shown 6-14 mils deviation in the initial contact pattern check.
The valve repair was successful and a subsequent local leak rate test was successfully performed.
The test leakage found was 251 standard cubic centimeters per minute, well within the administrative limits provided for this valve.
The valve was suc-cessfully stroke time tested on June 20 to open in 73 seconds and close in 69 seconds.
Based on the successful repair and local leak rate testing for the HV-51-1F01'6A valve, the inspector concluded that the concerns addressed in item 86-23-03 had been addressed and con-sidered this item closed. The inspector will follow subsequent MOVATS testing of HV-51-IF016A and a supplemental revision to LER No.85-102 in future inspections.
2.5 (Closed)_UnresolvedItem 86-27-02 The item involved the effect of wind on secondary containment inleakage and the operability of the standby gas treatment system (SGTS) to maintain the required reactor enclosure negative pressure at less than 1,250 standard cubic feet per minute, (scfm), the design basis building in leakage (and exfiltration rate).
The licensee proposed an amendment to the technical specifications (TS) to include the consideration of wind speed while performing surveillance tests for secondary containment leakage.
The proposed amendment established a criterion of less than or equal to 7 mph wind speed to establish a meaningfully measurable building leakage.
The inspector reviewed the safety evaluation for the proposed TS change and verified that the TS change was approved by the PORC in meeting 87-019, and was submitted to the NRC for approval on March 20, 1987.
The bases for the proposed TS change were supported by meteorriogical dispersion factors and post accident orfsite dose analyses which were shown to be within regulatory limits under 7 mph winds.
For ground level wind speeds greater than 7 mph, atmospheric dispersion would be greater (and better) than that assumed in accident analyses.
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Engineering calculations bounded the possible SGTS flows and showed that dose analyses were not exceeded for wind speeds in excess of 8 mph and for SGTS flows of up to 3000 scfm.
During secondary containment isolations experienced during operations of Unit 1 in the past year, SGTS flow has been observed to randomly exceed the TS limit of 1250 scfm because of high wind conditions (typically greater than 10 mph) combined with the configuration and placement of differential pressure flow instrumentation.
During higher wind conditions, the differential pressure across reactor enclosure walls will be greater than the quarter-inch negative pressure maintained by the SGTS due to building wind effects.
The proposed TS amendment establishes the criterion of less than or equal
to 7 mph wind speeds as necessary in assessing the operability of SGTS and secondary containment design basis leakage.
Pending approval of the proposed technical specification change by the NRC, the inspector's concerns associated with unresolved item 86-27-02 will be considered resolved.
2.6 {Closedl_ Unresolved Item 87-09-01 During the performance of security surveillance testing of the xray metal detection and explosive detectors in NRC inspection 50-352/
87-09, the inspector identified certain deficiencies associated with the surveillance test procedures regarding concealment of the test object.
Licensee security supervision agreed to certain procedural improvements for surveillance tests ST-7-084-311 and 932.
The inspector verified that the improvements had been incorporated into the test procedures and concluded that this adequately addressed his concerns.
Therefore, the item is closed.
3.0 Review of Plant Operations 3.1 Summary of Events Unit I was shut down on May 15 to begin the first refueling outage.
Drywell head removal and reactor vessel disassembly were completed by Mn/ 25.
Core alterations commenced on May 28 and all 764 fuel assemblies were removed and stored in the spent fuel pool by June 6.
The core remained offloaded for the remainder of the inspection period.
32 Operati onal Sa f ety_Ve ri fica tion 3.P 1 Control Room and Refuel Floor Activities The inspectors toured the control room daily to verify proper manning, access contral, adherence to approved procedures and comnliance with technical specifications.
The inspectors reviewed shif t superintendent, control room supervision, and licensed operator logs and records
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l covering the entire inspection' period.
The inspectors L
performed backshift and weekend tours of the facility
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thrsughout the inspection period. On May.28 and,29, June u
5, 11, 12, 15,:and 20, the backshift inspections were
betw2en-the hours of 2:00 a.m. and 6:00 a.m.
The inspectors reviewed logs and records for completeness, abnormal conditions, and significant operating changes and trends. Other operating records reviewed included:
Reactor Engineering and STA books, night orders, radiation work permits, the locked valve log, maintenance: request forms, temporary circuit alterations,- ar,d ignition source control checklists. The inspectors also observedc hif.t s
turnovers during the perdod.
Operations activities were observed for conformance with Administrative' Procedure A-7.
No unacceptable conditions were noted.
-The inspector reviewed activities associated with the preparation for and conduct of refueling.
The^ plant entered Operational Condition 5, Refueling, on May 20.
The inspectors observed preparations for inflating the reactor cavity seals, the removai-of the drywel! and reactor head, the tie-in of the standby gas treat:rer,t system to the refuel floor, lif ts of the reactor vessel separator-and dryer assemblies, full core offload of 764 fuel assemblies from May 28 through June 6,-and subsequent work to rearrange contro) blades, to replace 15 local power range monitors (LPRM) and to ' remove and rebuild 20 control rod drives. All activities were observed to be in confor-mance with approved procedures, and appropriate control of refueling activities was evident and in accordance with general plant procedure GP-6.1, Shutdown Operations for Refueling, Core Alterations nd Core Offloading.
No concerns were identified, and no violations were identi-fieJ.
3.2.2 Sec uri ty_
During entry to and egress fr a the Unit 1 protected area and vital areas, tl.e inspectors observed that access controls, security boundary integrity, search actf.vities,
escorting and badging were all in accordance with Security
Plan implementing procedures ana guard force instructions.
The inspectors also observed the availability and opera-bility of security systems such as search equipment, perimeter detection devices, and security computer alarms.
The inspectors verified that the minimum number of armed guards required by.the Security Plan to be onsite were i
present on selected shif ts by review of duty rosters,
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discussion with licensee Shift Security Advisors, and observation of guard force turnovers.
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i 3.2.2.1 Inattentive Watchcan
.The senior resident inspector was informed on. June 16 by.
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licensee security supervision of an fncident that occurred on, June 6 involvirg a security watchman who was allegedly _
l inattentive while on a compensatory post assignment.
The watchman had assumed and remained'on his post for approximately 1-1/2 hours when he was reported by.a firewatch supervisor touring the Reactor Enclosure to be apparently asleep. -The security watchman was obset ved by. security supervision who
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responded to the report within 10 minutes to be awake and
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attentive,.but was relieved of his' post and suspended pending the licensea's investigation.
The inspector reviewed the licensee's report'and evaluation of the incident, discussed the incident with licensee management, and observed routinely
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t.hroughout the inspection period that security force members on compensatory guard postings were attentiv'e and' cognizant of post orders.
The watchman suspended on June 6 was reinstated on June i
18 following an interview with the licensee's Nuclear Security Specialist.
The inspector had no further questions or concerns, and identified no violations.
3.2.2.2 Safeguards Material Lost On May 22, 1987 outdated Safeguards Information (SI) was inadvertently placed in the trash, which ended up in a skip pan (dumpster) located outside of the PECO warehouse.
Enroute to a dumpsite, the SI which was bound in a stack (and
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found to be outdated and intended to be shredded) apparently fell out of the skip pan behind the warehouse.
Three security employees discovered the material approximately one hour after the skip pan wr p'cked up, and returned the material to security
supervision.
Security representatives immediately conducted rweeps of the owner controlled area between the warehouse and the dumpsite, including the area where the SI material was found.
The dumpsite was posted by two secarity force members who were instructed to ensure that skip pans were only dropped and not dumped, until a daylight search of the dumpsite for additional SI material was conducted. A visual search was conducted by security personnel on May 23.
No additional SI material was found.
The inspector found that SI material intended to be shredded and stored within the Administrative Building bullet l
resi,stant enclosure (.BRE) had not always been attended or locked away since the BRE is manned 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day.
Due to the heavy volume of traffic through the BRE, and with the shredder being located in the BRE, the licensee determined that it was possible for SI material designated to be shredded to be acci-dently tossed in the trash can.
The licensee concluded that
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there was no' intent to steal or improperly use the SI, and that.it had been; inadvertently or carelessly thrown away.
E The inspector. reviewed the licensee's investigation i
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summarized in a letter dated June 3, 1987, from the
security contractor to the licensee's Director of Nuclear Securf ty.
The inspector observed improvements made by the licensee at the end of the ;nspection period in handling i
and processing of SI mate _ rial intended to be shredded..No
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violations were identified.
3.2.3 Radiological Contro]s The inspectors observed the availability and use of radiation monitoring equipment, including portai monitors I
and portable friskers.
Thc inspectors also observed health phsyics (HP) supervision and technicians involved i
in plant activities involving potentially significant l
radiological conditions.
Radiation work permits (RWPs)
wee selectively reviewed to deternine that appropriate job coritrols, protsctive clor.hing, dosimetry and HP upport were prescribed, in use, ar.d understood by workers involvw.
Radiological controls for high raoiation areas were determined to be ir. accordann with prrc.edure HP-215, Establishment and Posting of Radiological Control Arces.
Locked high radiation areas were verified to be properly identified and secass to such was appropriately controlled..The inspectors entered the drywell and suppression pool on several occasions during the
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inspection period, and observed the five hot spots identified by HP surveys. All of tW identified conditions had been flushed, wern prop?rly identified and roped-off, and read less than 1 n/ hour at 18-inches away.
No violations or concerns were identified.
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3.3 Station Tours The irspectors toured accessible areas of the plant throughout the inspection period, including:
the Unit I reactor and turbine-auxt-liary enclosure, the main control and auxiliary equipment rooms; battery, emergency switchgear and cable spreading rooms; and the plant site ferimeter.
During these teurs, observations were made of equipment condition, fire bazards, fire protection, radiological controls and conditions, housekeeping, tagging of equipment, or. going maintenance and surveillance, and the availability of required equipment. No violations were identified.
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1 3.4 Engineered Safeguards; Features Verification-
<7he inspector-independently verified the operability of the fuel
. pool cooling and cleanup (FDCC) system by performing a detailed walkdown of the accessible portions of the system, and confirmation
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of the following items:
Re' view of FPCC-related Technical Specification 3.9.11, FSAR
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Section 9.1.3, System Operating Procedures and P&ID M-53.
Identification of FPCC equipment conditions and items that may.
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degrade system performance.
System check-off list' S53.1. A (COL) and operating procedures
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consistent with plant drawings including performance of.
operating procedure S 53.9.A, Routine Inspection of the FPCC
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System.
Valves and breakers properly aligned, including appropriate
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locking devices.
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Instrumentation properly valved in and functional.
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Control room switches, indications, and controls appropriately positioned and operational.
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Surveillance procedures adequately implement Technicel l
Specification requirements, including observation and review of test procedure RT-6-053-310-1; Demonstration of Fuel Pool Cooling j
as a: Decay Heat Removal Method; and special procedure SP-S-044, Filling and Testing of the FPCC System.
No violations were identified.
4.0 Onsite Followup of Events The inspector performed onsite followup of the following events that occurred during the inspection period, The events were evaluated for proper notification to the NRC, reactor safety significance, licensee efferts to identify cause and propose effective corrective actios, and verification of proper system design response.
4.1,RWCU 1solations On May K, a reactor water clean-up (RWCU) System isolation occurred while the system was being returned to service.
The isolation was due to a high differential flow created when the RWCU suction valve was not closed within 45 seconds.
The system isolated as designed,
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the isolation was reset, and the systein was returned to normal.
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l On May 22, the'RWCU system isolated again'due to a.high temperature signal caused by workers decontaminating tne RWCU pump room.
A-temperature. sensor was inadvertently sprayed with steam causing the temperature to increase to the isclation setpoint.
The system func-
.tioned as designed, but was not immediately reset because the
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licensee'was in the' process of regenerating the RWCI demineralizers.
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At the: time.of both of the'above RWCU isolations,.the plant-was.
shutdown and in the refueling mode.
No violations were identified.
'4. 2 Radiation Monitor Bumped On May 19, personnel replacing unrelated equipment in a panel which contained the trip units for a reactor enclosure radiation monitor inadvertently tripped the units. A momentary upscale electrical spike'resulted in an isolation of six containment sampling valves, j
Two process radiation monitor valves and four contair. ment atmosphere i
sampling valves closed. The isolation was reset, and the inspettor verified that all systems functioned properly.
The plant was in a cold. shutdown condition with reactor coolant temperature at 118 F i
at the. time of the isolations.
No unacceptable-conditions were noted.
4.3 RHR Injection I
A Division 3 ECCS signal occurred on May 25 due to an error by a technician performing an instrument calibration.
The reactor'was in Operational Condition 5 (Refueling) at the time, with reactor level at the v'essel flange and coolant temperature at 98 F.
The 'C'. trains of RHR and ccre spray initiated, but only the RHR pump injected since the core spray loop was blocked for maintenance.
The 'C'
RHR pump ran for approximately 40 seconds, injecting 2.000 gallons of water and increasing reactcr vessel level by approximately ten inches, before being secured by operators. All other syst' ems initiated and func-tioned as designed.
The event is addressed in Detail 5.2.3.
4.4 Battery Charger Failure
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While performing a maintenance inspection on the Division 1 125 VDC batteries on June 11, a failure of the 1 AID 103 battery charger occurred.
The charger supplies power to and caused an isolation of Reactor Enclosure and ReS el Floor ventilation logic.
In order to restore the power, field engineers initiated a temporary circuit
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alteration (TCA) to provide a power supply to the de-energized panels. When the TCA was installed, the 'A' RPS shunt trip coil energized, causing one of the RPS power supply breakers to open.
This caused on inboard instrument gas valve to isolate and a Hgnal to various inside containment isolation valves that were alrea 2y either closed or blocked for maintenance. The isolation signals were restored, along with the battery charger, and all systems were returned to service. The inspector reviewed the event with field engineers
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,o and verified that the battery charger failure was unrelated to the maintenance inspections, and in fact a random. failure.
No unac-
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ceptable conditions were noted.
t 4.5 Ventilation Isolation l
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'An is'olation of refueling floor ver.t11ation and initiation of the'
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standby. gas treatment system occurred on June 11. A test engineer, working under troubleshooting controls to enable a containment-freon purge' of a charcoal filter as part of a modification acceptance test,. inadvertently lifted an electrical lead and caused'a low pressure signal which isolated' refuel floor ventilation.
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tion was reset and ventilation was returned to normal.
The'inspec-
l, tors discussed the event with test engineers involved with the l
troubleshooting, and concluded that the isolation was caused by an
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error incjndgement on the part of the engineer who lifted two wires instead of the ona specified on the troubleshooting control form TCF.
The inspector had no further questions.
4.6 Scram Signal Caused by Radiography While performing a radiographic non-destructive examination test on
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.the 'A' main steam line on June 12, an Iridium-192 source was exposed to the main steam line radiation monitors. Actuation of 3 of the 4 main steam line radiation monitors caused'a full scram signal to occur. 'Following the reset of the scram, the inservice
' inspection (ISI) personnel attempted to remove the source from the
'A' main steam line, causing the source to again be exposed to the radiation monitors. This caused a second. full scram signal to occur.
A' total of twenty-eight control rods unexpectedly moved, 13 of which had no blade guides installed.
The core was fully off-loaded at the time of the scram.
The inspectors attended a mneting held on June 12 to evaluate the j
l inadvertent scram, and the PORC (Meeting No.87-060) was convened on t
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June 15 to review the conclusions of the licensee's investigation, The cause of the unexpected rod motion was due to hydraulic control unit (HCU) accumulator repressurization.
The repressurization i
occurred when the control rod drive (CRD) system charging header supply valve was opened on a temporary clearance, and not
subsequently reclosed prior to CRD pump operation, resulting in a
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partial repressurization of the accumulators.
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l Initial visual inspection for potential damace to the control rod
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blade wing tips on June 12 indicated that the seventeen rods that moved in cells containing no blade guides had no damage. An under-j water TV camera survey of the blades while in the fully inserted l
position was conducted on June 16 for all control rod blados, and indicated no damage, Also, blade rellers were observed to be intact.
The potential for dislodged blade rollers was addressed in GE Rapid Communication SIL No. 011 issued on April 29, 1987.
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Another concern associated with the control rod movement was the
'l occurrence of the scram coincident with the closure of the HCU 1-12
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valves located on the piping connecting the above piston area to the
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Closure of the HCU 1-12. valve blocks flow
.j from the drive piston, and a potential existed for distortion of the
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CRD cylinder tube since the water above the piston was compressed.
l The pressure buildup was concluded by the licensee to be mitigated by y
the fact that the HCus had been observed for accumulator pressure
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prior to the incident and were only approximately 100 psi above the
exhausted accumulator pressure.
The licensee addressed this problem l
by stroking control rods to ensure proper movement, and 40 control
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rods which had had a previous history of reduced stall ficw (an
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indicator of potential mechanical interference problems) were satis-l factorily friction tested by June 19.
Successful control rod test results were also made a prerequisite fem re-eatry into Operational i
Condition 5.
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The licensee performed full friction testing at every notch of
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control rod 10-47, which during the scram incident moved from position 48 (fully withdrawn) to position 00 (fully inserted) with j
no control blade loaded in the cell.
The friction testing was i
recommended because of the potential that the unguided drive tubing i
could have been distorted.
No indications of excessive -friction or
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damage were found by site personnel.
Sample friction traces were sent to GE-San Jose system experts for indepenc%nt verification.
1 The inspectors reviewed the results of control rod friction testing
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during the inspection period with licensee reactor engineers, and J
discussed the lessons learned and proposed corrective actions with statior, management.
Temporary circuit alterations (TCA's) were.
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observed to be applied to block RPS trip signals from the main steam
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line radiation monitors during subsequent radiography.
The licensee I
was also addressing related issues of communications deficiencies between shift operating personnel.
Finally, control rod operability was verified by presentation of a safety evaluation to thn PORC on June 23, 1987 that presented the satisfactory results of visual inspecticas, stroke and friction testing, and independent engineering i
reviews.
The inspector identified no unacceptable conditions or vialations, and will follow the licensee's continuing evaluation of the June 12 scram and appropriate recommendations for improvements to j
equipment blocking procedures when LER No.87-026 is issued.
j 4.7 RPS Power Supyly Isclation On June 15 while field engineering was performing a modification i
li acceptance test (MAT) of the new protective relays for the RPS power i
supplies (See Detail 9.2), the
"B" channel series breakers opened when power was transferred from the alternate to the normal source.
The opened breakers caused a 'B' RPS channel trip, and isolation
signals to the reactor building and refuel floor ventilation systems.
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The event had been anticipated by the licensee and, pricr to the
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test,' field' engineers notified operatio'ns of the possibility of
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causing a half scram signal. using'a troubleshooting control form (TCF).
The isolations were reset and all systems.were returned.to normal.
Subsequent to the June 15 event,. the switchover from' alter-nate to standby RPS sources was tested twice with no.reccurence. At the time the plant.was in the Refuel Mode.with all the fuel removed from the vessel.
u The. inspector' discussed the event with the field engineers invnived
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in Modification No.85-490. The inspector noted that the RPS "A"
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channel relays had been successfully replaced, tested and transferred between preferred and alternate power sources prier to June 15.
The I
event involving the."B" RPS channel was appropriately controlled
'I ander administrative troubleshooting procedures, and the possibility of a breaker opening (and a half-scram condition) was noted on the TCF.
Following the June 15 event, several unsuccessful attempts to '
duplicate'the' event were made.
Since the. normal or preferred;"B" RPS-power supply (from the station batteries and the UPS/RPS-inverter)
had been isolated since June 1986, and was de energized at:the time of the June 15 event, the licensee suspected a lack of inverter
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warmup time caused the breakers to open on an overvoltage condition (including a 4 second time delay) when switching'from the alterna.te.
i RPS power source supplied from the~ Technical Support Center inverter.
However, the vendor for the UPS/RPS inverter and relays indicated that a few cycles would be sufficient to prevent cold-start electronic.
phenomena.
The cause of the June 15 event was, as of the end'of the
inspection period, still unknown.
The inspector noted that a detailed modification acceptance test (MAT) had been prepared for modification number 490, and had been revised on a number of occasions over the past year. Administrative procedure A-89b controlling the preparation and handling of MATS requires PORC approval of revic'ons to MATS.
PORC approval of the
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revised MAT for modification F ber 490 was obtained.
The inspector
will follow post modification 2 sting in future inspections, i
4.8 Relay Ground During Modification
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.l On June 16, an unexpected isolation of refueling floor ventilation occurred.
Inside containment isolation logic signals were initiated for a number of valves, but no valve movements were experienced since the systems were blocked for maintenance and are not required in the current plant status. A standby gas treatment system (SGTS) initiation also occurred, but the SGTS fans were already running as part of charcoal filter testing underway at the time, j
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The cause of the isolations was a ground created in the logic during the installation of a new relay associated with a license condition
modification to the drywell chilled water isolation valves.
The
isolation signals were reset within 75 minutes. At the ti.ne of the l
1 solation the reactor core was fully offloaded, and activities on the refuel floor included reactor vessel ISI and removal / rebuilding of 14
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contr,1 rod drives.
The inspector discussed with licensee field engineering supervision the procedures and detailed electrical design instructions associated with modification number 84-106.
The root cause was connecting the new relay to a neutral connection shared by numerous other relays. The proposed corrective action includes more involvement by field ano test engineers in the implementation of detailed electrical modifications. The inspector identified no violations and will follow the licensee's corrective actions in future inspections.
4.9 Refuel Platform Position By_ gassed While rearranging control rod blades on June 11 with the core completely offloaded, a reverse block was experienced that prevented the refueling platform from moving over the core.
The block was due to a malfunctioning reactor mode switch relay contact indicating that the unit was in startup.
Reactor engineers on the platform ascertained that the mode switch was correctly in the refuel position, and that the core was completely offloaded.
The engineers then raised two limit switches associated with platform interlocks (positien indication) to defeat the refueling platform blo:k and continue the control rod rearrangement. Without the refueling platform position switches, the control rod block interlock associated with the refueling platform being over the core would not have been operable if one of the plastform hoists were leaded. The hoist-loaded switch does not activate unless a fuel bundle is being handled.
No fuel was being handled at the time.
The cause of the event was an error in judgement on the part of the reactor engineers in not recognizing one requirement for platform position indication even when fuel is completely offloaded from the core (and hence core alterations as defined in technical specifica-tions are not possible).
The control rod rearrangement was suspended approximately one hour after lifting the limit switches, upon recog-nition of the problem and involvement by refueling supervision.
The limit switches were returned to normal and the reactor mode switch position contact was cleaned and returned to operability.
The failure to initiate and use an approved troubleshooting control form (TCF) in accordance with Administrative Procedure A-41.1, Troubleshooting Safety-Related and Tech Spec Equipment, was identified as a violation (50-352/87-13-01).
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The. inspector concluded that the Technical. Specifications (TS)
related to refueling pistform po ition during offloaded. conditions
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i are misleading and contributed to the June 11 error..The one-rod-out interlock may be defeated under offloaded. condition to move multiple control blades (as occurred on June 11); but,'this partially defeats the hoist operability' requirement of TS 4.9.61
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(hoist-loaded control rod block interlock when load exceeds 485
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J 50 pounds).
The licensee recognized the-potential problems associated with multiple control blade movement during offloaded conditions and created PORC Position No.'30 on June 4,' 1987 to l
address the TS distinctions between offloaded blade movement and i
The inspector discussed the June 11 refuel platform event with the l
reactor engineers involved and station management. A proposed TS
change 1s being considered to remove the' misleading requirements of l
TS 3.9.6 for control rod and hoist-loaded interlocks when completely
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c f floaded. The inspector also reviewed a June 25 memorandum from
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the reactor engineer to station staff concerning the use of TCF's and proper administrr.tive controls (e.g., maintenance request forms to perform refuel 'oridge repairs) and the importance of taking time
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during critical path outage activities and of involvement of super-vision.
The inspector had no further concertis.
4.10 Meeting on June 17
The inspectors attended PORC Meeting No.87-062 held on June 17, 1987 to discuss the increased incidence of reportable events experienced since comniencing the outage on May 15.
The station i
manager, operations superintendent, and other plant staff were l
present and reviewed 16 potentially reportable events that had occurred in the previous month.
i The PORC focused upon the impact of the outage as a contributing
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cause of the error rate experienced. Approximately half of the events were concluded to be likely occurrences independent of plant status (non-outage, random); two were attributable to implementation
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of modifications, but not necessarily driven by schedule or indica-tive of carelessness; and, the remaining events were considered as containing an aspect of inattention to detail which would not other-wise have occurred during non outage periods.
For the third set of events concerning attention to detail end care, the PORC identified two principle factors:
one was the overall volume of outage activi-ties; and, the second was a perceived self generated feeling by personnel of the need to hurry.
The station manager issued a letter to the Unit 1 staff dated June 17, 1987 to remind all employees of l
the need to maintain attention to detail at pre-outage levels.
The
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inspector observed a marked reduction in reportable events for the remainder of the inspection period.
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. 5.0 Licensee Reports j
5.1 In-Office Review of Licensee Event' Reports The inspector reviewed-Unit 1~LERs submitted to the NRC Region I
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. office to_ verify that ' details of the event were clearly reported,
.I including the accuracy of description of the cause and adequacy of'
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corrective action. Where multiple cau'ses are suspect, or may be different.than reported in the LER, this is indicated below. The
' inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site. followup.
The'following LERs were reviewed:
LER Number Report Date-Cause Subject-87-012 5/18/87 Personnel error Secondary contain-
and de sign ment isolation and deficiency SGTS/RERS initia-tion due to isola-tion of instrument air. supply 87-013 6/08/87 Personnel error Secondary Contain-ment isolation and
.SGTS/RERS-initia-tion due to open filter plenum hatch 87-014 6/12/87-Unknown / design Group VI C (samp-
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ling' valves) con-tainment isolation suspected to be caused by workers bumping a radia-
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tion detector
'87-015 6/16/87 Equipment HPCI turbine / shut-down and subse-i quent stop valve
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failure and system inoperability due to loose lead on flow controller
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87-016 6/11/87 Personnel error Secondary contain-ment isolation and SGTS/RERS initia-tion due to removal of an L
instrument cap L
from a pressure sensing line 87-017 6/18/87 Unknown (could-Group VI C (samp-not be duplicated)
ling valves) con-i tainment isolation l
suspected.to be caused by replace-ment of an adja-cent' radiation monitor drawer 87-018 6/19/87 Valve seat wear MSIV LLRT failures ano subsequent ex-ceeding of com-bined Appendix J Type B and C total leak rate limit 87-019 6/24/87 Personnel error-Division 3 LOCA by technician.
signal and LPCI incorrectly injection during venting prior to level transmitter isolating a pres-surveillance sure transmitter testing 87-020 6/22/87 Personnel error RWCV system isola-due to inadequate tion on tempera-communication be-ture sensor acti-tween test engin-vation during de-i eer and cleanup contamination of I
crew pump room using a Kelly vacuum (high temperature steam)
LER Nos.87-012 through 016 were addressed in Detail 4 of Inspection Report 50-352/87-09.
LER No.s87-017 through 020 are addressed in Detail 4 or Detail 5.2 of this report.
5.2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup as noted in Section 5.1, the inspector verified that the reporting requirements of 10 CFR 50.73 and Technical Specifications had been met, that appropriate
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corrective action had been taken, that the event was appropriately reviewed by the licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limits.
5.2.1 LER No.87-015; HPCI Stop Valve Failure The inspector reviewed the subject LER describing a failure of the High Pressure Coolant Injection (HPCI) system on May 14 during a surveillance test.
The cause of the HPCI turbine shutown was stated by the licensee to be caused by a loose lead on the output of the HPCI flow controller.
As a result of the turbine failure, the stem of the HPCI turbine stop valve was also discovered separated from the coupling connecting the valve and actuator stems.
The inspector attended several meetings addressing the HPCI stop valve failure during the inspection period, and dis-cussed the maintenance repair and related June 16 report with maintenance representatives.
The separation of the stop valve stem from the coupling was determined to be caused when the valve opened and the disk overtraveled because of incorrect adjustment of the stop valve balance chamber.
The balance chamber had been previously adjusted in April 1985 in accordance with the General Electric SIL No. 352.
The licensee contacted the valve manufacturer, Schutte and Koerting, to discuss the valve j
throttle adjusting screws on the bonnet.
If the screws l
were opened only one turn (as they were during the first cycle of Unit 1 operation), the holes could potentially become clogged with rust which apparently contributed to the rapid opening of the valve as occurred on May 14, 1987.
The maintenance investigation concluded that the probable cause of the valve failure was plugging of the throttle adjusting holes or the possible introduction of hot con-densate into the system, or both.
Recommendations for repair included checking stop valve balance chamber pressure prior to HPCI turbine testing, and readjustment in accordance with GE SIL No. 352.
The inspector observed the condition of the valve as it was disassembled, and reviewed dimensional checks and valve repairs with maintenance craft.
The licensee's mobile mechanical group assigned specialists to the repair and to
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analysis of the valve repair.
The damaged threads from the l
coupling were sent to the licensee's metallurgy laboratory for analysis but it was concluded that there was not enough
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material to be analyzed.
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Another aspect of the failure.found by the maintenance
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investigation was that the valve bonnet was found galled'
and the valve plug was damaged because the plug hit the top of the bonnet.
ISI inspection found a 7/16' inch'11near indication on the stellite of the seat in the valve body, along with two other smaller indications and machine marks
.on the valve plug. A recommendation from the valve vendor based on similar experience at Peach' Bottom was to open'the-drain valves on the HPCI turbine prior to using the_stop valve to eliminate the chance of introducing hot condensate which would flash when the valve was being opened.
The inspector will follow the valve replacement'and subsequent HPCI testing prior'to startup.
No violations were identi--
fied.
5.2.2 LER No.87-018; MSIV LLRT Failures
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The inspector reviewed LER 87-018 describing local. leak rate test (LLRT) failures'of the main steam isolation valves (MSIVs) and exceeding the Appendix J total combined primary containment leakage limit.
Initial LLRT of the MSIVs on May 20 resulted in all four main steam lines exceeding the penetration leakage limits of 11.5 standard cubic feet per hour, The tests were con-ducted at 22 psi with off. scale leakage on all four inside containment MSIVs, and measurable leakage in excess of'the-
. limit on 3 of the.4 outboard MSIVs.
The licensee attributed the cause of the high leakage to wear of the valve seating.
surfaces.
Subsequent testing during the inspection pe;iod'
was successful for tne C main steam line penetration.
The other MSIVs were being tested at the close-of the inspec-tion period and will be followed in future inspections.
The licensee committed to supplemental information regard-ing the repairs and retests in a future revision to LER 87-018.
Also reported in this LER was exceeding the total combined Appendix J, Type B and C leakage limit of 0.6 La or 94,964 standard cubic centimeters per minute..The limit was exceeded by local leak rate testing of the drywell purge exhaust valves on May 19. The results of the local leak rate testing performed during the current refueling outage were being followed as part of NRC Inspection Report 50-352/87-17 and will be followed in future inspections.
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l No violations were identified and the inspectors had no further questions.
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5.2.3 LER No.37-019; LPCI Injection The inspector reviewed the subject LER describing an unplanned low pressure coolant injection (LPCI) system injection on May 25, 1987 as a result of a surveillance test on a reactor water level transmitter.
The inspector discussed the event with ILC supervision and the technician involved in the error.
The technician stated that while following the test procedure, he came to a i
point where a health physics survey was required prior to valving the transmitter out of service.
Upon return to the jobsite with the health phsyics technician and after the HP survey, the technician lost his place in the procedure and incorrectly bagan to vent the transmitter, not realizing that the transmitter had not yet beer. isolated.
The procedural steps required in venting the transmitter start at the top of the page immediately following the steps which start the isolation.
By losing his place 'n the procedure, the technician caused a pressure spike to occur in the 'evel sensing tubing upon beginning to vent.
The technician stopped the procedure as soon as he realized that water had begun to flow out of the head chamber above the vent valves which he had just opened.
However, the pressure surge in the reference leg of the transmitter simulated a low reactor water level signal for all pressure transmitters sharing that common reference leg.
A Division 3 LOCA signal occurred which caused the start of the C RHR pump as well as a start of the C core spray pumps.
All systems responded as expected and the isolation logic was quickly reset.
The LPCI injection caused a water level rise in the reactor vessel of approximately 10 inches corresponding to approximately 2000 gallons of water.
The reactor was in Operational Condition 5, Refueling, and in the 10th day of the refueling outage.
Refueling activities underway at the time included flooding-up the reactor cavity on the refuel floor and preparations for fuel removal.
The reactor vessel head had already been removed on May 25, as were the vessel internals (dryer and separa-tor), prior to the injection.
Core unloading began 3 days after the injection.
The "C" core spray injection valve had been closed prior to the injection to support mainte-nance activities; therefore, no core spray water was injected into the vessel. A half scram signal occurred as did a D13 diesel start signal; however, the D13 diesel had been blocked prior to the injection for maintenance and did not start.
A safeguards load center shed also occurred as designed and resulted in loss of power to various equipment which resulted in isolation of the main control room ventilation, reactor enclosure, cnd refuel floor ventila-tion systems.
The Control Room Emergency Fresh Air Supply (CREFAS) and standby gas treatment systems responded es
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?xpected. Additionally, an'HP technician was in the reactor.
vessel cavity performing a. survey at the time that the injection occurred; Reactor water level (which was already at the top of the. vessel flange) began to rise and fill the cavity.
The technician safely left the cavity'and was not contaminated.
The inspector reviewed the details of LER 87-019 and concluded that.no. additional information was required and that the LER was thorough in evaluating the consequences and explaining the expected sy' tem initiations.
The licensee's corrective action consisted of counseling the technicians involved in performing surveillance testing and discussion of the event at an.all-hands meeting of I&C technicians on June 3, 1987. The inspector had no further concerns and identified no violations.
5.3 Review of Periodic and Special Reports Periodic or special reports subnitted by the lic,nsee were reviewed by the inspector.
The reports +
reviewed to determine that the report included the requirad information, that test results and/or supporting information were consistent with design predictions and performance specifications, and whether any information in the report should be classified as an abnormal occurrence.
The following reports were reviewed:
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Monthly operating report for May 1987
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Annual Non-radiological Environmental Operating Report for 1986, dated April 28, 1987
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Semi Annual Effluent Release Report No. 5 - Revision 1, dated June 15, 1987 Diesel Generator Test Failure Report, dated June 5, 1987
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Response to NRC concerns regarding Unit 2 contamination by Unit 1, dated June 8, 1987
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Seismic Monitor Inoperability report, dated June 12, 1987 i
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PECO response to NRC Inspecti, Report 50-352/87-07, L
Requalification Training Program Deficiencies; dated June 19, 1987 No violations were identified.
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6.0 Surveillance Activities 6.1 Test Observations The inspector observed the performance of and/or reviewed the results of the following tests:
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ST-6-107-591-1; Daily Surveillance Log - Opcons 4 & 5 l
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ST-6-107-593-1; Daily Surveillance Log During Core Offload ST-2-047-000-1; Control Rod Scram Relay Response Time Test
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ST-4-921-1; Division I 125/250 VDC Safeguard Battery Inspection
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ST-4-951-1; Division I 125/250 VDC Safeguard Battery Service
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ST-6-107-630-1; Core Alteration Testing
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ST-2-042-449-1; RPS Reactor Vessel Water Level Calibration
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ST-1-LLR-661-1; Leak Rate Test for Suppression Pool Spray
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ST-6-107-594; Spent Fuel Pool Level Surveillance The tests were observed to determine that surveillance procedures conformed to Technical Specification requirements; proper administra-tive controls and tagouts were obtained prior to testing; testing was performed by qualified personnel in accordance with approved proce-dures and calibrated instrumentation; test data and results were accurate and in accordance with Technical Specifications; and equipment was properly returned to service following testing.
No unacceptable conditions were noted.
6.2 Rosemount Static Pressure Correction The inspector discussed with I&C supervision a revision to the Rosemount Model 115 DP Alphalina differential pressure transmitters instruction manual which contained revised static pressure span correction factors.
The new values were based on the factory calibration of a large sample of Rosemount transmitters, and reflect a more accurate determination of span shift due to static pressure.
Setpoint methodology and field calibrations had been developed with the previous correction factors; therefore, I&C engineers updated field calibrations to reflect the revised static pressure span correction factors.
There were no Technical Specification changes required as a result of the revised correction factors.
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The inspector reviewed the revised calibration data sheets and discussed the changes to reactor vessel level instrumentation with I&C engineers.
The inspector also reviewed calibrations for level transmitters associated with the low water level (Level 3) scram performed under procedure ST-2-042-449-1.
The inspector concluded that the revised static pressure corrections had an insignificant effect upon the calibrated span, and that the corrections indicated good attention to detail by the I&C staff.
No unacceptable conditions wtre noted.
6.3 Color Coded Ir.strument Panels As an interim corrective measure to reduce the potential for human error associated with testing divisional and channelized safety equipment, the licensee placed a highlighted border (colored electrical tape) around equipment on safety related auxiliary equipment room panels.
The colored border has been placed on the front panel and rear access doors around locks, and a color coded label with the division or channel designation was placed on the front panel.
The color coding is a short term measure to reduce the likelihood of human error.
Licensee engineering was requestad to investigate long term improvements.
The inspector observed the new color coding, observed surveillance testing in progress on several occasions, discussed the improvements with I&C technicians and engineers, and concluded that the color coding would reduce the potential for testing the wrong channel or division.
No unacceptable conditions were noted.
6.4 Scram Relay Testing I
The inspectcr cbserved portions of ths ::r. duct cf procedure l
ST-2-047-000-1 to test the response time of the scram relays, C71-K14A through D.
The response times were from 9 to 21 l
milliseconds, and within the recommended limit of 31 milliseconds for relay pick-up time.
The limit was based on GE recommendations associated with observable delays in measuring full control rod scram times, and is added to the individual rod scram times.
The licensee performs the response time test every 18 months, although not required by Technical Specifications.
The inspector had no further questions.
7.0 Maintenance The inspector observed selected maintenance activities on safety related equipment to ascertain that:
the work was conducted in accordance with Administrative Procedures A-25, 26 and 27 and with approved work instructions or precedures; proper equipment permits and tagging were administratively controlled; craft performing the work were appropriately
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qualified and supported; and return-to-service of equipment include'd adequate post-maintenance testing and operational verification. Also evaluated was associated QC coverage and inspection.
7.1 Work Observation Pcrtions of the following work activities under maintenance request forms (MRFs) were observed or reviewed:
MRF # 87-4463; 1A1D103 battery charger circuit board replacement
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MRF # 87-4733; A RHR pump-motor replacement MRF # 87-1506; Fer' rater check valve examinations
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MRF # 86-6449; Dr.
il' spray HV-51-1F016A valve repair
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MRF # 86-5222; RHR/ u JI injection HV-51-1F017C valve repair
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MRF # 87-3660; HPCI; Turbine Stop Valve Rcjair
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No unacceptable conditions were noted.
7.2 MSIV Repairs The inspector followed the progress on (le repair of the main steam line isolation valves.(MSIVs) which had failed local ieak rate tests on.May 20, 1987 and which were reported as part of LER No.87-018 (see detail 5.2.2) on June 19, 1987.
The inspector reviewed procadure M-041-001 used to perform maintenance on the MSIVs, and discussed the progress of maintenance activities with maintenance division pipefitters and mobile maintenance specialists involved in MSIV work.
The Unit 1 MSIVs are 26-inch Atwood and Morrill valves.
The licensee is a member of a BWR owner's group involving modifications to the MSIVs in order to improve leakage performance.
The vendor's retrofit and upgrading program involves modifications to the MSIV topworks, high pressure' cylinder, and anti-rotation devices.
The major observation by maintenance craft performing the valve repair was that no steam cutting of the disc or internals was fou w, and that the lower half of the poppet-to-stem coupling had sufficient thread engagement to preclude rotation problems.
The inspector concluded that maintenance procedures were thorough and detailed with appropriate vendor manual information, and that maintenance craft involved in this activity were experienced and well-treined.
The effectiveness of repairs to the MSIVs, including the addition of new lantern rings and chevron packing material as well as BWR cwner's
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group modifications, will be followed in future inspections of local leak rate testing of the valves. The inspector had no further questions and identified no violations.
7.3 Control Rui Drive Rebuild Work The inspector reviewed the progress of the rebuild of 20 control rod drives -(CRDs) during the refueling outage.
The CRD rebuilds were begun on June 13 and were completed by June 19.
The inspector observed work in progress on several occasions during the six-day neriod above and noted that tne licensee had sufficiently detailed procedures for re.noval, rebuild, and replacement.
The inspector reviewed the completed procedures M47-001 and 002 and the individual maintenance request fctms (MRFs) for the 20 drives being rebailt.
l The inspector interviewed the licensee's maintenance supervision
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overseeing the job, including a dedicated subforeman.
Tne inspector l
also interviewed the contractor assigned to rebuild the drives. The
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contract crew included two quality control engineers and a project
manager at the rebuild site as well as 26 craft.
The maintenance i
procedures contained a number of QC hold points and witness points and the irspector observed coverage by the licensee's QC group.
The licensee employed video tape coverage of the CRD rebuilds since the under-vessel area was a high radiation area. Discussions with maintenance supervision and management indicated that the rebuild crew had training on a CED under-vessel mockup located at the Peach Bottom site.
The licensee's health physics personnel also provided continuous coverage of the under-vessel work.
The personnel contami-nation clothing required by the related RWP involved an 8-mil plastic suit. HP technicians were aware of the importa" " and radiological significance of the CRD rebuild work.
Additional CRD rebuild activity was required at the end of the inspection period to rebuild two additional drives.
During the work the licensee discovered damage to instrumentation and cable under the vessel on June 25.
The damage involved approximately 14 local power range monitors, TIP (transversing incore probe) tubes, and SRM/IRM cable.
The licensee held a number of meetings at the end of this inspection period to investigate the cause and institute a corrective action program for the undervessel damage experienced during CRD rebuild activities.
The licensee's investigation included viewing of tFe closed circuit videos of portions of the CRD reouild work.
Althcugh the licensee's investigation was in progress at the end of the inspection period, the licensee was proposing better protec-ti-on of instrumentation and cable under the vessel, and better organization and supervision of undervessel work in future outages.
The licensee estimated that approximately 14 days of critical path time had been lost as a result of the damage.
The inspectors will review the conclusions of the licensee's investigations in future inspection i
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7.4 Orywell and Reactor Vessel Head Remova_1_
The inspectors witnessed portions of the below listed refuel floor activities in preparation for refueling under the following maintenance (M-041) procedures:
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014; Mirror Insulation Removal
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016; Reactor Head Detensioning 017; Reactor Head Removil
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044; Reactor Head Spray Pipicg Removal
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No violations were identified.
In addition, the activities listed above were confirmed to be in accordance with NRC sa'fety evaluations issued to PECO dated May 12 and 16, 1987, which approved the above activities.
8.0 Snubber Testing l
8.1 Scope l
The inspec tor reviewed the following documents to ascertain compli-ance with Technical Specifications, applicable. industry standards and station administrative guidelines.
The inspector also witnessed snubber inspections and testing, and held discussions with the licensee garding the documentation of test results, repairs and retestir
,llowing failed tests.
PL.,00-080, Preventive Maintenance Procedure for the Removal,
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Stroking cf Spherical Bearings, Stroking and Installation of Q-Listed Snubbers, Rev hion 4., May 14, 1987.
ST-4-103-072-1, Accessible Snubber Visual Ir,spection - SBLC #3,
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Revision 1, May 18,. 1987.
ST-4-103-080-1, Accessible Snubber Visual Inspection - RCIC #1,
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Revision 1, May 18, 1987.
ST-4-103-092-1, Accessible Snubber Visual Inspection - HPCI #3,
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Revision 1, May 14, 1987.
ST-4-103-301-1, Snubber Function Test, Revision 2, May 15,
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1987.
iT-4-103-501-1, Inaccessible Snubber Visual Inspection - RHR
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- 1, Revision 2, June 5, 1987.
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.ST-4-103-621-1, Inaccessible Snubber Visual Inspection -
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Containment Atmo' spheric Control #2
'A' Post LOCA'Recombiner, Revision 1, May 26, 1987.
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ST-4-103-700-1, Inaccessible Snubber Visual! Inspection
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Main Steam #1, Revision 1, May 27, 1987.
ST-4-103-716-1,. Inaccessible Snubber' Visual Inspection - Main
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Steam #17, Revision 1,.May 31, 1987.
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ST-4-103-740-1, Inaccessible Snubber' Visual Inspection - Vessel Instrumentation #1, Revision 1, May 19, 1987.
17819-1, Procedure for Functional. Testing of Pacific. Scientific
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Mechanical Snubbers using The Wyle Model 100. Test Machine-Exclusively for Philadelphia Electric Company at-Limerick Station, Unit 1 & 2, Revision 0, May 12, 1986.
MSS-004, Procedure for Functional Testing of Pacific Scientific
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Mechanical Snubbers using The Wyle Model 100 Test Machine on the Wyle Model 150 test machine, Revision A, March 4, 1987.
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Snubber LCO Status Sheetr.
Snubber Functional Test Results
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Certificate of Calibration
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LGS 1, Snubber-Sample Plan for First Refueling Outage, May 1, 1987.
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~ Safety Evaluation for Modification Request Number 5316.
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The procedures reviewed were technically accurate and in conformance with ASME B&PV Code Section XI, Subsection IWF and ANSI N45.2.6 -
1978Property "ANSI code" (as page type) with input value "ANSI N45.2.6 -</br></br>1978" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. Qualifications of Inspection Examination, and Testing -
Personnel for Nuclear Power Plants.
The inspector also discussed testing and inspection procedur9s with licensee and sub-contract personnel, and found their knowledge to be adequate.
No unacceptable conditions were identified.
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. 8.2 Test Witnessing Throughout the inspection period the inspector witnessed several functional tests on various sized snubbers.
The tests were performed by sub-contract personnel from Wyle Laboratories who were knowledgeable and have sufficient work experience in the area of snubber testing to adequately perform their assignments. Also noted by the inspector during the performance of snubber testing was QC involvement.
The Quality Control department is committed to 100%
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surveillance of the snubber functional testing..For each snubber l
tested, QC personnel' submitted a Quality Control Inspection Report
(QCIR) which summarizes the test performed, the snubbers tested and the results..No unacceptable conditions were identified.
8.3. Testing Apparatus and Instrumentation The. inspector received the calibration records for the Wyle Model 100 Snubber Test Machine. The calibration records were found to meet applicable accuracy requirements, and were traceable to the National Bureau of Standards.
The inspector also observed the operation of the automatic data collection system during the conduct of the test.
No unacceptable conditions were identified.
8.4 Test Methods Limerick technical specifications require that-an ins _rvice inspection program be conducted to determine snubber operability. The inservice inspection program at Limerick consists of visual inspection and functional testing of snubbers. The snubber functional _ testing of the drag and activation ievels was determined in both tension and-compression.
The acceptance criteria for mechanical snubber testing is as follows: The snubber drag level is 2% of the rated load for snubbers located in sensitive areas and 5% of the rated load for
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snubbers located in non-sensitive areas.
The activation level is 0.049 for snubbers located in nonsensitive areas and 0.02g located in sensitive areas.
8.4.1 Visual Inspection Under the visual inspection program the licensee inspected each snubber to assure that there are no visible indica-tions of damage or impaired operability, that the attachment to the foundation or supporting rtructures are secured, and that the fasteners for attachment of the snubber to the component and to the snubber anchorage are secure.
If a snubber is rejected because of the visual inspection, it can aither be remedied for that particular snubber or functionally tested.
If a failure is discovered, based on.
the results of this intpection, the frequency of inspection for that given system could be shortened.
8.4,2 Functional Inspection For the first refueling outage the licensee has decided to test 55 snubbers in accordance with Technical Specifi-cations Section 4.7.4.e sample plan 3.
Based on this sample plan, the representative sample selected for L
the functional test was randomly selected and reviewed by engineering prior to testing.
The review concluded that they represented various configurations, operating l
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environments, sizes and capacities.
The acceptance criteria was stated prior to the beginning of the testing and for each snubber that failed another sample of 28 additional snubbers will be selected.
8.5 Test Results 8.5.1 Visual Inspections The licensee conducted a 100% visual inspection of 1600 snubbers. Of these snubbers 185 failed the visual inspection. Of the 185 only 16 had to be functionally tested.
Based on that testing one snubber failed the functional testing, which increases the surveillance requirements from 18 months to 12 months for the related system.
No unacceptable conditions were identified.
8.5.2 Functional Inspection The licensee conducted functional testing of a total of 110 snubbers.
The added snubber testing was due to the failure of two snubbers.
Component EBB-104-H15 which is a size PSA-100 and has a rated load of 120,000 pounds locked up during the performance of an acceleration test in tension, and component DCA-318-El-H3, Size PSA-1/2, with a rated load of 650 pounds failed to stroke the final 3/4 of an inch in compression.
Both snubbers were replaced.
No l
unacceptable conditions were identified.
9.0 Plant Modifications l
The following modifications were evaluated to assess, in part, the:
detaiis and adequacy of the safety evaluation; proper consideration of Technical Specification changes; implementation under Administrative Procedure A-14; status of completion of physical installation; effective-ness of modification acceptance testing; and, accurate update of operating and test procedures, as-built drawings. and operator training programs.
The inspector verified that appropriate engineering desion support and PORC review and approval were received; that Construction Division installation was in accordance with Engineering and Research Dept. (ERDP)
procedures including appropriate QC coverage and with a minimal effect on plant operations; and, that an operable system was returned to service with no apparent unreviewed safety questiors.
Within the scope of this inspection, no violations were identified.
9.1 License Condition 2.C(12); Remote Start Capability for Service Water The inspector reviewed the safety evaluations for modification numbers 84-0026 (PHR service water); 86-0176 (RHR); and 86-050R (ESW) associated with License Condition 2.C(12) requiring remote
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start capability for the above Loop B pumps from their respective breaker compartments.
The modifications are required for redundant remote shutdown considerations.
A new key-lock switch was added, which can be moved from the normal to the emergency position, to eliminate the need to utilize jumpers.
An additional cable is also required for a control room alarm when the key-lock switch is in the emergency position.
The safety evaluation had not originally addressed Appendix R enalyses for the new cable; however, PORC review determined that a failure of the cable in the open circuit condition during a fire would disable the alarm function and a hot short would bring up the alarm. Also, a fault to ground would have minimal impact since it is on a non grounded DC system and the annunciator panel is protected by fuses.
Therefore the absence of the Appendix R analys:s did not impact the safety evaluation for the modification.
The inspector discussed the progress of the modification with responsible system engineers, and will follow completion in subsequent inspections.
9.2 RPS.P_ower Supp'ly rrotective Relays
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The inspector reviewed a revision to modification number 490 installing new under and over-voltage relays for the RPS power supply panels.
l The mod'. ;ation also installed more appropriately sized control fuses j
to protect the RPS inverter. The safety evaluation for modification 490 was reviewed by the inspector and discussed with responsible field engineers.
The reasons for replacing the 36 amp control fuses with the 6 amp fast-acting type fuses were described as better protection for the inverter from a short circuit since the larger fuse did not act fast enough to prctect the inverter from damage. While not criginally intended to be part of the chanae, this aspect was learned during implementation of the modification.
The new relays were required because of the relay sensitivity to waveform harnonics associated with the inverter outauts of the normal and alternate RPS power supplies.
The normal RPS inverter and the alternate Technical Support Center inverter square way, outputs were different enough that, during the original installation of the new protective relays, the output of one source would trip the relay during calibration but the eutput of the other source would not. The relays were sent to the manufacturer, Brown & Boveri, for modification to add a t.armonic filter module. Revision 6 to the modification was approved by PORC in December 1986 and the implementation was delayed until the refueling outage.
The new fuses and relays were installed on June 15 for RPS channel B.
The inspector reviewed the troubleshooting control forms initiated to install the fuses, observed work in progress, reviewed the installation with field engineers, and reviewed the results of the successful modification acceptance test.
The inspector also reviewed the results of surveillance tests
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ST-8-036-419 through 422 performed on June 15 - 17 for all relays..
The test was an 18-month calibration performed by licensee's Plymouth Test Labs. The inspector verified the check-out of the new relays for initial calibration.cf the drop out and pick-up ratios and time delays, and to verify the acceptability of the harmonic filters.
That initial testing was found acceptable..
Finally, the licensee replaced'an existing color cap neon lamp with a transparent LED cap as an operator aid to clearly determine when the relays have tripped.
The inspector identified no concerns or violations, and had no further questions.
l 9.3 Feedwater Pump Imp 911er Replacement The inspector reviewed the safety evaluation and modification
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progress for the replacement of the reactor feedwater pump impeliers and miscellaneous internal parts. Modification number 86-0987 is intende; to enhance the reactor feed pump reliability by minimizing vibration preblems at low flow which had been experienced during
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power ascension testing of Unit 1 1r February 1985. After the high pump vibration at low feedwater flow was experienced, disassembly of the A feedwater pump found impeller damage due to an incorrectly repaired impeller using dissimilar weld metal.
The pump manufac-turer, Ingersoli Rand, corrected the Sad weld repairs, but reinstal-
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lation of the cepaired impellers still showed unsatisfactory vibra-tion levels when the pump was operated below 60's of its efficiency flow point. Modification number 0987 was initiated to modify and replace the impellers of all three feedwater pumps during the refueling outage.
The new impeller expected performance curve developed during a series of tests at the vendor's factory remains similar, including at pump runout conditions but with a slight increase in the required pump turbine speed.
The insrector reviewed pcrtions of the feedwater impeller replacement work in progress and periodically disr.ussed the maintenance with responsible staff engineers.
During *,ha installation of the new feedwater pump impellers, damage was found on the B reactor feed pump turbine rotor which was later shipped to the vendor for blading repairs.
The inspector identified no concern: and will follow the post maintenance testing of the feed pumps during plant startup.
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10.
Scram Discharge Volume Capacity (TI 25-15-90)
The inspector reviewed the licensee's evaluation of NRC Information
Notice Number 87-17 entitled Response Time of Scram Instrument Volume Level Detectors, issued on April 7, 1987.
The information n'otica addressed the' potential for long response times of level detection instruments used on the scram' discharge volume.
The notice described the NRC's generic safety evcluation report dated December 2, 1980 addressing the improvement of scram discharge volume design, and noted a continuing area of concern for the reliability and response time of float switches used on the instrument volume.
The minimum capacity of the. scram discharge volume was related to the potentially generic concern that the response time of the level switches 'under degraded scram air header conditions, could result in a failure to. scram.on a high level in the volume. The scenar_io described is commonly referred to as the " fast fill event" and involves scram outlet valve leakage at a sufficient rate into the discharge volume before the level switch can respond and initiate a scram. ' The inspector discussed the 'information notice with plant test engineers and I&C supervisors, and in a conference call held with General Electric representatives on June 19.
The response time of. level switches associated with the Unit 1. scram discharge volume is not required.to be tested by Limerick technical specificaticas.
However, the licensee routinely observes the response time of the screm discharge volume on plant scrcms by review of the sequence--
of-events log.
Tha inspector rev'iewed and discussed a sequence of events printout'for the plant shutdown that occurred on May 15, 1987 to begin the outage.
Response times for the level instruments on the instrumented volume of Unit I were such that, from the time the scram was initiated until the scram discharge volume vents and drains were observed to close, was approximately 21 seconds.
The response time included the time for vent and drain valve closure.
The inspector also reviewed Unit 1 procedures that address potenti-ally slow scram volume response times such as offnormal (ON) proce-dure -108 for low air-header pressure and operational transient (OT)
procedure -105 for scram discharge volume high level.
Those proce-
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dures were found to provide appropriate precautions and directions to crerators.
The inspector discussed the design requirements of the scram dis-chat ge volume with General Electric system engineers and licensee I
representatives..The design specification allows for 3.34 gallons per control rod drive on a screm.
The design basis for sizing the scram discharge volume is to minimize the back pressure associated j
with the free volume on a scram situation.
The inspector evaluated the results of preoperational test P55.1 conducted in March 1984 to confirm the volume in the scram discharge volume as being 634.8 i
gallons, which was in excess of the minimum required 618 gallon
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capacity.
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Based on independent review of the sizing of the' scram discharge volume, and the level at which a. scram is initiated, the inspector concluded'that sufficient free volume existed to minimize back
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pressure and to not affect CRD scram times.
The inspector also concluded that.the diverse level instrumentation on the instrumented volume was sufficient to respond to the degraded air header condition described in Information Notice 87-17.
The differential-pressure type transmitters are expected to respond quicker than the float type switches, but both types have been shown to adequately respond during actual scrams.
No violations were identified and the inspector had-no further questions.
'11.0 ReactoF Cavity Seal Integrity (TI-25-15-66)
Prior to filling the reactor cavity on.the refuel floor to commence fuel' offloading, the inspector independently walked down the reactor <
cavity seal to verify its integrity. The inspector observed.the seal to be in good condition, and discussed seal design.and testing with.
responsible test engineers prior to placing it in service The inspector noted that daily shift tours by plant operators chec' E
conditions in the spent fuel pool cooling and cleanup system which would be indicative of seal leakage during outage activities over the inspection period.
Reactor cavity leakage monitor FSH 53-101 was-regularly observed to be within required ranges and manual drain valves were periodically checked to detect leakage. No leakage conditions were found.
The' inspector also reviewed the licensee's response to NRC Informa-tion Notice 87-13 dated February 24, 1987 entitled Potential for High Radiation Fields following Loss of Water from the Fuel Pool.
In response to that information notice, the licensee prepared a special operating procedure S53.0.A entitled Response to a Low Level in the Fuel Storage Pool and/or Reactor Well.
The procedure was found to contain necessary operator actions to react to a low level alarm in the reactor cavity indicative of a potential leak.
The inspector reviewed procedure S53.0.A, discussed the procedure with licensed operators and refuel floor coordinators, and concludec.
that personnel were sufficiently aware of the importance of the cavity seal integrity and early detection of a leak.
The inspector also reviewed the licensee's November 6, 1984 response to NRC Bulletin 84-03 addressing the cesign of the refueling cavity water seal and found that that response was still valid for the current L
refueling outage.
Finally, the inspector observed successfully preoperational leakage testing of the cavity seal prior to placing it in service during the outage.
No violations were identified and the inspector observed no unacceptable conditions.
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q 12.0 Containment Spray Nozzle ~ Inspections
The inspector accompanied maintenance personnel on an inspection of I
the Unit 1 containment spray headers in.the.drywell and suppression pool on June 30, 1987. The inspection was initiated based on a concern j
by NRC personnel for_ the integrity of the spray headers as a
result of the discovery of corrosion products in spray headers and.
j nozzles at another BWR facility on June 10.
The inspection consisted of the removal of two spray nozzles on either side of the two i
loops. of spray headers in both the drywell and. su'ppression' pool, and visual inspection with a boroscope for indication of rust particles.
No rust, foreign material or debris was -found as a result of the inspections.
The' inspector concluded that based on: _(a) the fact.
that tFere have been no inadvertent sprays in the drywell; (b) that the spray headers in the drywell are typically under an inerted atoosphere; and (c) that a monthly spray test of the suppression pool spray headers is performed during power operations, that there was
assurance that no rest would be generated which would block the spray
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nozzles on the Unit 1 systems. No unacceptable conditions were i
identified.
13.0 Allegations During the inspection period, the inspector conducted inspections and interviews in response to an allegation received by the NRC.
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(RI-87-A-0058) The NRC received an anonymous allegation that j
procedures were not used to conduct the refueling floor operations,
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specifically during reactor vessel head removal. As discussed in
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sections 3.2.1 and 7.4 of this report' refueling operations procedures i
do exist and have been properly followed except for the violation I
which is cited in section 4.9 which occurred about one month after
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the allegation.
Specifically, the remce l of tne reactor vessel head is included in procedure M 041-017 which was properly completed and portions of which were cbserved by the inspectors.
Based on this review the inspector determined the allegation to be unsubstantiated.
14.0 Management Meetings J
14.1 Preliminary Inspection Findings I
The NRC resident inspectors discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with the Station Manager, Mr. John Franz on July 1, 1987.
At the meeting, the licensee's representatives indi-cated that the items discussed in this report did not invalve pro-prietary information subject to 10 CFR Part 2 restrictions.
No written inspection material was provided to licensee representatives I
during tho inspection period.
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14.2 Region-Based Inspections The inspectors attended management meetings to discuss preliminary findings for the following specialist inspections conducted during this report period.
Inspection Subject Exit (Octes)
. Inspector)
Date (
87-12 Generic Letter 83-28 5/22/87 (5/18-22)
Q-List Classification (Dev)
87-14 Health Physics 6/5/87 (6/2-5)
(Dragoun)
87-17 LLRT 6/19/87 (6/16-19)
(Golls)
87-15 ISI 6/5/87 (6/2-5)
(McBrearty)
87-16 Maintenance and Modifications 6/26/87 (6/16-26)
(Finkel)
14.3 Other Meetir.gs Date Subject 6/4/87 NRB Meeting No. 203 6/19/87 Radiography Safety Briefing by Unitech Services (U S.
Tes+1ng)
6/25/87 SALP Management Meeting