IR 05000352/1986027
| ML20212J331 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 02/26/1987 |
| From: | Gallo R, Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212J306 | List: |
| References | |
| 50-352-86-27, NUDOCS 8703090009 | |
| Download: ML20212J331 (28) | |
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U.S. NUCLEAR REGULATORY COMMISSION
. REGION I Report No. 50-352/86-27 Docket No. 50-352 License No. NPF-39 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, PA 19101 Facility: Limerick Generating Station, Unit 1 Inspection Period: November 27, 1986 - January 26, 1987 Inspectors: Ah 2/[Wbf 7 Euge'ne M. Kelly, ior Resident ' ddte Inspector S. O. Kucharski, Resident Inspector M. Miller, Radiation Specialist T. F. Dragoun, Senior Radiation Specialist J. Prell, Reactor Engineer R. Paolino, Reactor Engineer Approved by: t Robert M. Gallo, Chief, Pro.iects Branch No. 2 M!87 da'te Summary: Routine daytime and backshift inspections (353 hours0.00409 days <br />0.0981 hours <br />5.83664e-4 weeks <br />1.343165e-4 months <br />) of Unit 1 by the resident inspectors and Region I Specialists consisting of: followup on outstanding items; walkdown of the Standby Gas Treatment system; plant tours including fire protection measures; maintenance and surveillance observations; and review of LERs and periodic report The inspection covered feedwater pump vibration on December 8; internally contaminated Unit 1-2 piping interconnections, and a drywell airlock leakage test on December 30. Also covered were increased secondary containment inleakage experienced on January 22 and increased drywell leakage on January 23-26. Independent inspections were conducted that evaluated the ESW pump design susceptibility to suction recirculation-cavitation damage; new fuel receipt; and SGTS single failure potentia Several meetings were held onsite during the period, addressing QATTS findings and a license condition concerning conduit seals and envitanmental qualification, and these are documented herei No violations were identifie Unresolved items were initiated for: temporary ERFDS monitoring connections; and secondary containment integrity under high wind condition gDR ADOCK 05000352 PDR
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DETAILS 1.0 Principals Contacted Philadelphia Electric Company W. Alden, Licensing Supervisor J. Doering, Superintendent of Operations R. Dubiel, Senior llealth Physicist J. Franz, Station Manager G. Hunger, Nuclear Safety Section Head K. McGinnis, Mechanical Engineer R. Moore, Superintendent, QA Division
'Also during this inspection period, the inspectors discussed plant status and operations with other supervisors and engineers in the PECO, Bechtel
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and General Electric organization .0 Followup on Unresolved Items
2.1 (Closed) Unresolved Item 85-36-03: Administrative Control of SDV Drain Valves
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The inspector noted that the handwheels for the scram discharge volume drain valves had been secured with locks and added to Administrative Procedure A-8, the locked valve list. Verification of proper valve positions and controls on several occasions during the inspection period satisfied the inspector's concerns, and the i item is therefore close .2 (Closed) Unresolved Item 85-36-04: Revision to HPCI Isolation Test
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i The inspector reviewed changes to the monthly HPCI steamline high
differential pressure functional tests that addressed previous
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concerns for containment isolation and logging-in of Technical
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Specification action statements, as well as HPCI system operability during the tests. ST-2-055-605 and 606 were found to reference proper technical specifications and had added precautions and prerequisites which satisfactorily addressed the inspector's l concerns. This item is therefore close .3 (Closed) Unresolved Item 85-43-03: Revised ESW System Testing The inspector reviewed revisions to the quarterly inservice testing procedure for the ESW system pump and valves. The principal concern of throttling the manual discharge valves at each ESW pump to achieve a desired flow has been addressed by removing the requirement to throttle and, instead, noting the flow achieved without valve position changes. As addressed in Detail 6 of this
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report, ESW system testing now compares the flow achieved with the system pump flow curves to determine proper pump operation. The item is therefore resolve .4 (0 pen) IFI 86-23-01; Containment Spray Isolation Valve HV51-1F016A LER 85-102 addressed the LLRT failure of the Loop A outboard isolation valve for drywell spray in December 1985. The valve (and associated spray loop) have been inoperable for over one year pending more extensive repairs to the valve scheduled for the May 1987 refoaling outag The inspector independently reviewed the design bases for drywell spray and evaluated the risk associated with only one of two loops available. Emergency procedures, accident analyses and operator
! training were assessed and the inspector concluded that the ( increased risk was marginal. Accident analyses do not take credit j for spray operation in reducing post-accident contaminant pressure
and airborne fission product inventory. While the effectiveness of
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the sprays in " scrubbing" radiofodines is high, there is also an associated risk in operating both spray loops at full capacity and drawing a negative internal pressure inside the drywell. Further,
- the reliability of loop 8 is high insofar as it has not experitsnced i any operational failures and is a relatively simple extension lof RHR piping / valving to the passive drywell spray loops / nozzles inside the drywell . Therefore, operation with only one available locp u1til May
1987 was deemed reasonabl The inspector also discussed with licensee representative < the e
modification unsuccessfully applied to the 16A valve in May 1986 of cutting a slot in the valve's Limitorque operator torque-limiting sleeve to release grease which may have been preventing proper valve
- operation. The sleeve contains a spring pack, into which
- non-compressible soft greaes migrates during valve operatio The
- pl.enomenon of hydraulic lockup had been observed during Unit 1 preoperational testing in 1984 for 5 larger-size Limitorque valves i
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out of a total population cf approximately 500 valver.. The spring packs were successfully slotted for the 5 Limitorques in question and subsequent MOVATS testing showed the desired linear spring pack
, compression.
l l Pending repairs, during the upcoming refueling outage, to the 16A spray valve, this item is still opan.
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2.5 (0pon) Items 84-66-06 and 86-26-01: PASS Design Froblems
A meeting with PECO engineering and chemistry representatives and
- NRC Region I personnel was held onsite on January 7,1987 to discuss i design problems associated with post-accident r,ampling systems. The l
purpose of the meeting was to identify measures being implemented to L
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improve the operability and long-term reliability of the Unit 1 i PASS, as well as to factor Unit I and PBAPS experience into the
refurbishment of the Unit 2 PAS Operation of and modifications to the Unit 2 PASS were reviewed and
a total of 92 items contained in lists prepared by Mechanical Engineering and Chemistry were discussed. Included in these items
! were the following principal commitments:
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Creating a set of PASS drawings unique to. Limerick which would ;
, include all modifications.
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Investigating improvements to the radiation monitors, i i
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Implementing a new modification to insulate the jet pump sample
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Investigating short and long term operability and reliability improvements to the Unit 1 PASS (18 items identified) under a -
new modification reques Providing input to General Electric for refurbishment of the Unit 2 PASS (35 items)
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Providing support to Operations for an increase in the priority
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given to PASS repairs, modifications and preventative maintenance, i
i In addition to the above, Mechanical Engineering has prepared a '
j modification scheduled for the May 1987 refueling outage to add a control valve to the jet pump sample line and a sight glass on the demineralized water tank. Commitments were made to recalibrate
, instruments associated with the PASS, and to review operating air i
maintenance procedures. The unresolved item identified in NRC Inspection Report No. 50-352/86-26 was addressed in part by '
replacement of the broken Luer-Lok fittings on the gas sample battle
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- with a type of fittings that has been used with much greater i reliability on the offgas sample panels.
I i The licensee concluded that the Limerick Unit 1 PASS is currently
- operating satisfactorily. The numerous component failures that have
! occurred have bee resolved via modifications and/or repairs, and
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that experience was being factored into Unit 2. Additional actions were also underway to further improve the short and long-term
- reliability of the PAS These items therefore remain open pending
further NRC evaluation.
, The inspectors attending this meeting made the followirg
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observations:
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The problems experienced by PASS are not repetitive in nature, and they appear to be of different cause The problems with PASS appear to be unique at Limeric , Discussions with PECO headquarters personnel indicated that Peach Bottom had a high operability rate for PAS '
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The root cause of LGS problems appear to be the lack of management priority given to corrective and preventive maintenance related to the PASS. This now has been reccgnized by LGS and a higher priority is planned to be given to PASS maintenance activities. It also appeared Limerick was not communicating with Peach Bottom concerning PASS problem PASS was considered by the licensee to be operable at the time of this inspectio The inspector had no further questions at this tim .6 (0 pen) Violation 84-27-04: Sealing of Conduit Subject to High
- Humidity
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A meeting was held onsite on December 19, 1986 with PECO engineering
! and licensing representatives and an NRC Specialist Inspector i
concerning actions to be taken on License Condition Attachment I
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item 2a, regarding sealing of instruments in the RHRSW pipe tunne Information was presented that concluded that only the pipe tunnel instruments need to be moisture sealed, and that this would be done
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during the first refueling outage. Documentation supporting the adequacy of the seals was to be provided, and pending further review l by the NRC, this item is still considered open.
Also discussed during the meeting was PECO's existing program for the use of environmentally qualified seals. All electrical devices
, which are required to operate either during or after an accident are required to be qualified to function without a qualified conduit seal or have a qualified conduit seal installed in the conduit i adjacent to the device. The licensee emphasized the different l between conduit moisture seals to prevent the intrusion of moisture
, into electrical devices during normal operating conditions, and
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environmentally qualified seals which are designed to protect the electrical device during and after an accident. The licensee took
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the position that item 84-27-04 relates to the application of j moisture seals to improve device reliability during normal 1 operatio The licensee addressed the history of the conduit moisture sealing program, as questioned in a previous NRC inspection of the ESW t system which noted a high relative humidity condition in i the ESW pipe tunnel. Several safety related instruments were l inspected and found lacking moisture seals. Drawing E-1406
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specified sealing of instruments in specific high humidity areas of the plant but omitted the ESW pump tunnel, contrary to environmental specification M-171 which defined the ESW pipe tunnel as a high humidity area. PECO revised Drawing E-1406 to address all high humidity areas per Specification M 171, including the ESW pipe tunnel, the diesel generator corridor, and primary containmen PECO informed the NRC in subsequent correspondence that their program was to install moisture seals in conduits to electrical devices in all high humidity areas for improved reliabilit The last item discussed ws the licensee's revised moisture sealing program. During the preparation for the conduit moisture sealing program to be implemented during the first refueling outage, a re-evaluation.was performed to determine the maximum relative humidity in the diesel generator corridor and primary containment during normal operation. After performing several calculations, Bechtel revised Specification M-171 to re-define the maximum normal relative humidity in the diesel generator corridor and in primary containment as 90 percent. Drawings are presently being revised to conform to the changes made to Specification M-171. The licensee then summarized by re-iterating that their program for conduit moisture sealing is to provide moisture seals in conduits to safety related devices in high humidity areas for increased reliabilit Moreover, that program currently is being applied only to the ESW pipe tunne .7 [Open)IEBulletin85-03;LimitorqueMOVSwitchSettings The licensee's initial response to Bulletin 85-03 dated October 2, 1986 was reviewed and discussed with licensee Field Engineers and Mechanical Engineering representatives. The NRC will perform further detailed evaluations of the switch setting program and the adequacy of the design differential pressures for HPCI and RCIC motor-operated valve .8 (Closed) IE Bulletin 86-01; RHR Minimum Flow logic The licensee's June 9, 1986 response to the concerns for RHR pump
" dead-heading" potential described the Unit 1 design that precludes a single failure from damaging an RHR pump. Four independent RHR pumps each have flow sensors that control separate minimum flow return line valves. A single failure of any one flow sensor would only affect its associated RHR pump; the three remaining pumps would not be affected, and the logic problem described in Bulletin 86-01 therefore does not apply. The inspector had no further questions, and considered the item close .
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2.9 (Closed) IE Bulletin 86-02: Static "0" Ring Differential Pressure Switches The inspector independently verified the licensee's July 25, 1986 response to Bulletin 86-02 by confirming that no Static "0" Ring switches are installed as electrical equipment important to safet .0 Review of Plant Operations 3.1 Summary of Events The reactor operated at full rated power for the entire inspection perio Plant load drops to approximately 60% were performed on four occasions during the period. Control rod pattern changes for the remaining rod groups still inserted in the core were made to extend core life. Subsequent returns to full power were in accordance with preconditioning limits. End-of-cycle coastdown began at the end of ,
the period, as target burnup was reached and all control rods (except '
8) were fully withdrawn. The first refueling is scheduled to begin on May 16, 1987. New fuel (268 assemblies) arrived onsite on January 21-23 (see Detail 3.5). A license amendment to extend core life by allowing increased core flow and partial feedwater heating'was submitted to the NRC on November 16, 1986 and was awaiting approval as of the end of the perio A record for continuous first-cycle BWR operation of 198 days was set on January 26. A controlled Unit 1 shutdown was begun on January 27 and a manual scram from 27% power was performed to repair three
. valves found later to be contributing to high unidentified drywell leakag The licensee announced changes in November 1986 in PECO organization and senior management associated with nuclear power programs. The Senior Vice President for Nuclear Power and the Vice President for Electric Production retired. J. S. Kemper was appointed to a new position of Senior VP with three new VPs reporting to him. These changes became effective on November 24, 198 The annual emergency preparedness exercise was held on January 15, ,
1987, and was observed as part of NRC Inspection 50-352/87-0 '
3.2 Operational Safety Verification >
3. Control Room Activities The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs. The inspector reviewed shift superintendent, control room supervisor, and
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operator logs covering the entire inspection perio Instrumentation and recorder traces were observed and the status of control room annunciators was reviewed. Nuclear instrument panels and other reactor protective systems were also examined. Effluent monitors were reviewed for indi-cations of abnormal releases; none were evident. Panel indications for onsite/offsite emergency power sources were examined for automatic operabilit Also during the inspection period, control room activities were regularly observed for the following attributes:
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Noise Control
, Conduct of business with shift management has contin-ued to be held in an orderly manner, with little interference from routine duties. Noise levels associated with Unit 2 control panel construction underway during the inspection period were kept to a minimu Control Room Access New access control measures, including signs to preclude routine entry during shifts turnovers and entry for other than official business, were effective during the period observe Annunciating Alarms The number of nuisance and routinely alarming condi-tions was maintained at a low number over the inspec-tion period. An average of less than approximately five alarms on safety-related panels were present, and the licensee continues to track and aggressively pursue solutions towards unnecessary alarming condi-tions. Modifications were being undertaken to remove j the remaining alarms.
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! Sampling reviews were made of equipment trouble tags, night 1 orders, and the temporary circuit alteration (TCA) and LCO tracking logs. The inspector also observed shift turnovers
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during the period. The operations activities were observed i for conformance with the applicable procedures and require-ments; no unacceptable conditions were note The number of active TCA's were being tracked and reduced l during the inspection period, and new formalized turnover j
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procedures were observed to be effectively implemented.
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, 3. Security and Radiological Controls i
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During entry to and egress from the protected area and
! . vital island, the inspector observed access control,
security boundary integrity, search activities, escorting
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and badging, and availability of radiation monitoring equipment including portal monitors. No unacceptable
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conditions were foun .3 Station Tours The inspection toured accessible areas of the plant throughout this
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inspection period, including: the Unit I reactor and turbine-auxiliary enclosures; the main control and auxiliary equipment rooms; i battery, emergency switchgear and cable spreading rooms, and the i plant site perimeter. During these tours, observations were made of i equipment condition, fire hazards, fire protection, adherence to i procedure, radiological controls and conditions, housekeeping,
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security, tagging of equipment, ongoing maintenance and surveillance
. and availability of redundant equipment. No unacceptable conditions j were identified.
- 3.4 System Walkdowns t
3. Standby Gas Treatment System (SGTS)
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j The inspector performed a detailed walkdown of the Standby i Gas Treatment System (SGTS) in order to independently i verify system operability. The walkdown included
) verifications of the following items:
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Review of SGTS technical specifications, the FSAR,
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System check-off-list (COL) and operating procedures j consistent with plant drawings.
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Valves, breakers, and switches properly aligned, l including appropriate locking devices.
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Instrumentation properly valved-in and operable.
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Satisfactory control room switches, indicators and
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Within the scope of the inspection, no unacceptable ccnditions were note . Single-Failure Susceptability to Filter Train Cross-Tie Based on generic information from Pilgrim, the inspector independently reviewed the Limerick SGT', design, operation and potential failure mode The identified design deficiency was a single failure of a charcoal deluge system, concurrent with a loss of off-site power. The condition would result in loss of SGTS filter radioiodine removal capability due to a failed open outlet cross- ,
The Limerick SGTS design includes: two redundant charcoal !
filter trains, each with electrical air heaters; two banks of HEPA filters a vertical 8-inch deep charcoal absorber i bed (with fire detection temperature sensors and a water flooding system for fire protection); and associated dampers, ducts, instruments, valves and control The inspector concluded that the Limerick design was not susceptible to the Pilgrim single failures. With respect to the deluge system rendering the charcoal bed incapable of removing radiciodines from the air stream, the fire water flooding system is manually operated. The system is connected to the station fire protection system and a manual valve is mounted outside of the charcoal bed. Any l section of the charcoal bed outlet thermistors sensing a temperature higher than preset charcoal ignition tempera-tures alorts the operator to either initiate SGTS charcoal cooling mode or manually open the valve introducing the deluge water to the charcoal plenum. On a loss of I power or air, the Limerick SGTS inlet and outlet dampers !
fail closed and there is no cross-tie connection on the !
outlet of the filter trains, 3.4.3 Solitech Power Controllers On March 11, 1986 the 'B' terminal block of the master power controller in the Standby Gas Treatment System ($GTS) ,
had been discovered to be charred or partially melted. On May 4, 1986 the problem occurred again in the 'B' terminal block. These events caused an investigation by the licensee and eventually a Part 21 report on Solitech power controllers, i _ _ _ _ _ - _ - ___
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From the investigation it was suspected that loose t i wire-terminal connection could have caused the charring of the terminal blocks. Power to the electric heaters is carried through strained wire through these terminal i blocks. The blocks are safety related and located in a mild environment, requiring operation in an 80' F environ- 3 ment. The design operating temperature at the panel location is 65/104* F. The investigation also determined that the loose wiring could have been caused by the ener-
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gizing and de energizing of the electric heater on four ,
second intervals to maintain the appropriate temperature rise across the heater during SGTS operation. Cyclic
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1 in-rush current could cause the wires to expand and contract which, after a number of cycles, may cause loosen-
! ing of the terminal screw connections, i j The master power controllers and two slave controllers for ,
j each train of the SGTS were replaced during a surveillance testing outage (May 2 to June 19,1986). The new units 1 were upgraded to environmentally qualified units manufac-i
, tured by Solltech. This was performed under modification
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86-5114 and post modification testing was performed unde ST-1-072-106-1, and ST-1-072-107-1, SGTS Test, Revision 2,
- May 30, 1986. No unacceptable conditions were identifie '
3.4.4 SGTS Fan Capacity Increase and Connection to the Refuelinq
! Area (MDCP-614)
MDCP-614 is a major construction modification to increase
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the SGTS capacity and also to connect the refueling floor i to the SGTS. The existing smaller fans (3000 cfm capacity)
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will be replaced by two larger fans with the capacity of t
8400 cfm each. In the past, the licensee has experienced !
, problems with combined in-leakage and draw-down time, and l
! the larger capacity fans will help to eliminate the !
i problem. At the present time, construction progress on j this modification includes the following:
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Hanger Installation - 98% complete
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Duct installation - 91% complete !
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Electrical raceway installation - 90% complete
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Cable pulling - 75% complete ;
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Based on a condition to the Unit I license, the licensee is required to complete and test all modifications required to connect the refueling floor volume to the SGTS, prior to any movement of irradiated fue The licensec at the present time is preparing a safety evaluation to temporar-11y connect the smaller capacity fans to the refueling floor, which will enable removal of the drywell and RPV head in order to handle irradiated fuel. The progress of MDCP-614, which is the most extensive of the 75-80 modi-fications planned for the May 1987 outage, will be followed in future inspections until the modification is completed and teste .5 QATTS program An onsite meeting was held on December 22, 1986 with licentee representatives from the licensee's Quality Assurance Organization to discuss their use of the QA Trending and Tracking System (QATTS).
The meeting was the second such discussion in response to an NRC SALP report recommendatio The inspector discussed items in QATTS currently open and requiring verification. The inspector also reviewed data presented in the Third Quarter 1986 QATTS report and discussed the meaning of those findings with licensee representatives. Trends dating back 12 months were displayed, and a negative trend was identified with the issuance of 12 significant NCR's issued to vendors for security system program deficiencies. The inspector also reviewed a listing of 28 signif t-cant QA findings (SNCR's) at Limerick in 1986. The majority (18 findings) addressed vendor security screening. No violations were identifie .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 efforts to identify cause and propose effective corrective action, and verification of proper system design respons .1 Feedwater Pump _ Vibration On December 8th, the 'B' reactor feed pump inboard bearing exceeded its vibration alert setpoint, and over the next 1-2 days showed higher vibration than the alert setpoint and intermittently exceeded the danger setpoint. On December 12, 1986, the licensee removed the feed pump from service and investigated the problem during a scheduled load drop. Before tripping the pump, it was run down to a low speed and run back up 4200 rpm full speed. Vibration stabilized at approximately 3.0 mils on the inboard bearing; outboard bearing
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vibration remained steady near the alert setpoint. The vibration has
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been monitored since the load drop at between 2.9 - 3.2 mils on the inboard bearing and between 7.5 - 7.8 mils on the outboard bearin The setpoints were changed using TCA-801 to the following vibration values (in mils):
Bearing X probe Y Probe Inboard Alert .5 i Danger .0 Outboard Alert .0 Danger 1 .5 The inspectors monitored 'B' feed pump vibration over the remaining I inspection period and observed acceptable stable values. The l licensee demonstrated high quality technical diagnostic capability l using the permanently installed Bentley-Nevada system. The concern ,
for pump impeller metallurgic problems similar to those originally experienced in 1984 was alleviated. All three feedwater pump impe11ers are scheduled for replacement during the May-July 1987 refueling outage. No unacceptable conditions were identifie .2 Unit 1/2 piping Isolation Boundary Contamination At approximately 2:00 p.m. on December 9 Health Physics technicians surveying hot spots on a 2-inch line connected to the Unit 1 reactor l
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water cleanup resin backwash receiving tank traced back the pipe to a termination extending into unrestricted areas in Unit The internally contaminated piping, extending 4 inches up to a Unit 1-2 isolation valve and pipe cap, was found to read 10 mr/hr at contact and 0.6 mr/hr at 18-inches away. The valve had been chained and locked closed, no leakage was evident, and smear samples showed no external contamination. Work was suspended in the area, and a barricade was erected to preclude entry into the small alcove area where the penetration exists. The area is not a normally travelled passage, and HP surveys were commenced twice per shif The licensee unsuccessfully flushed the piping on December 9 but residual internal contamination (thought to be resin beads) was still presen Lead blankets were installed on the pipe and valve, redoc- l ing readings to approximately 1 mr/hr at 12-inches. A meeting l between NRC Senior Residents from Units 1 and 2, a Region I Radiation Specialist, and licensee HP supervision was held on December 10 to review and discuss the event. No apparent worker exposures were experience Immediate inspection of 35 similar potentially contami-nated penetrations revealed one isolation valve physically located on the Unit 2 side and connected to the common radwaste floor drain collection tank with a packing leak. The valve and immediate area were found not contaminated,
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A PECO Nuclear Review Board meeting was held on December 12 to discuss this event, and corporate management interest was eviden The licensee reisolated the contaminated 2-inch line inside of Unit l's radwaste tunnel and evaluated similarly affected penetrations throughout the Unit 1-2 construction interfaces. An NRC letter dated December 22, 1986 to PECo requested the results of the licensee's review of Unit 1-2 interfaces be provided to the NR No violations were identifie .3 Secondary Containment Isolations 4. Blown SGTS Fuse
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A reactor enclosure isolation occurred on December 18 due to a blown fuse shorted during maintenance being performed on ths A train of SGTS. The 1 amp fuse found to be shorted i
was apparently intended to be a 4 amp fuse, and the licensee undertook an investigation into why the smaller rating fuse was installed. Operators manually started the B standby train of SGTS and the RERS also automatically initiated as expected with a secondary isolation. The isolation signal was reset and all HVAC returned to normal within one hour. The reactor was at 100% power at the time, and the NRC was properly notified via the ENS.
I The event was reported on January 20, 1987 in LER 86-05 Differential pressure controller PDIC-76-041A was being re-installed following calibration when the isolation occurred. The A SGTS train did not automatically start since its handswitch was off at the time of the maintenance to allow re-installation of the fan controlle The blown fuse was in the power supply to the A SGTS logic; however, upon reset of the logic (at which time the blown fuse had not been discovered) another isolation occurre The undersized 1 ampere fuse was later found during troubleshooting and was replaced with a properly-sized 4 ampero fuse. Also, attempts to recreate the isolation (with the smaller 1 amp fuse) were unsuccessful and the Itcensee concluded that the event was caused by re-insor-tion of the controller into the circuitry and therefore an
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isolated inciden The Itcensee's report in LER 86-054 committed to a supplemental report that would provide further dotail on actions to prevent recurrence. Those actions, along with
the reason for installation of a smaller fuse will be followed in future inspection .
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! 4. Loss of Auxiliary Boiler Heating Steam l
- A reactor enclosure secondary containment isolation l occurred at 10
- 42 p.m. on January 5 due to a low l differential pressure of less than 0.10 inches water gage
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sustained for greater than 100 seconds. A loss of .
auxiliary boiler heating steam to the normal reactor enclosure ventilation supply fan coils had caused a supply r
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fan trip 2 minutes prior to the isolation. The loss of I
supply air created excessive negative pressure in the reactor enclosure, which in turn caused the exhaust fans to tri The exhaust fan trip was a modification added in May 1986 to ensure personnel safety and access within the reactor enclosure. Proper isolations and SGTS/RERS initiations were verif'ed, and the isolations were reset
, and normal ventilation restored at 10:45 p.m., 3 minutes
! after the ESF actuation. The NRC was properly notified via '
l the EN ,,
i The inspectors confirmed proper system response and l operator action, although there is no apparent corrective l action to prevent secondary containment isolations as a result of auxiliary boiler trips in cold weather. The
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scenario leading ta the secondary isolation is apparently unavoidable but also an exp9cted response which licensee
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representatives are considering a formal waiver request from the NRC regarding 10 CFR 50.73 reportabilit During the followup to this event, a separato concern for SGTS flow and secondary containment operability was raised and discussed in Detail 6.2.
l 4.4 RCIC/ERF05 Interface An emergency response facility display system (ERF05) modification was evaluated by the Itconsee and found to potentially affect RCIC operability at the remote shutdown panel. Temporary wiring connected during the power ascension test program in 1985 to monitor RCIC
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turbine performance was in the process of bein permanently connected I as an ERFDS data point. However, the licensee s safety evaluation of the modification identified that the wiring did not route through a-j remote shutdown panel transfer switch, thereby creating the potential for RCIC inoperability if an electrical fault in the main control room were to occur. The licensee made the ERFDS inoperable for approximately 80 minutes on December 19 to de-terminate the temporary ERF05/RCIC connections, pending further engineering evaluation. RCIC was appropriately declared inoperable during the de-termination and the problem was reported to the NRC via the ENS.
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The resolution of why the original change had not been properly evaluated for electrical separation and safe shutdown considerations is open pending further review of LER 86-55 which reported this event. The extent of other temporary ERF05 monitoring points for other systems, and why these may have been improperly installed with respect to fire protection / isolation considerations is unresolve (UNR50-352/86-27-01)
4.5 Containment Airlock Leakage Test On December 30, 1986 it was discovered that the Appendix J Type B surveillance test for the leak tightness of the Primary Containment Air Lock was overdue by 16 day During a review of outstanding scheduled tests, it was discovered that ST-1-LLR-803-1, " Equipment Access with Personnel Lock", should have been performed on December 14, 1986. Because of an error in the scheduling program input, the test was scheduled every 6 months with a grace period, instead of requiring testing at 6-month intervals without a grace period. Technical Specifications require that the air lock leakage be tested at least once every 6 months; but, the extension provisions of Technical Specification 4.0.2 are specift-cally excluded by the use of an asterisk and a footnote. The last previous test was properly performed on June 14, 1986. All previous tests had been performed within the 6-month interval The cause of the event was an error in loading the data into the computer program which schedules surveillance tests (Sis). The air lock test was performed successfully and the appropriate scheduling data was entered into the ST computer scheduling program. Program input was reviewed and it was verf fled that no similar conditions exist for any other test which is not allowed an extension to its surveillance interval. A routine test has been written to verify the ST scheduling data bas The inspector witnessed the successful retest of the airlock, discussed the event with licensee personnel, and had no further questions. The inspector concluded that this event represented a licensee-identified item as described in 10 CFR 50 Appendix C. No violation was issued since the licensee discovered the overdue test and promptly corrected the computer code. The event existed over a relatively short period of tim Finally, the licensee accurately reported this event in LER 86-057 and had experienced no similar problems for which previous corrective action should have prevented the erro ______--__________L
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4.6 HPCI Isolation During Testing The outboard steam suppl / valve HV-IF003 to the HPCI turbine was isolated on January 21 when an I&C technician connected a volt-ohmeter to a test circuit incoYrectly. The technician was setting up to perform a monthly surveillance when he connected the meter in the resistance mode instead of in the bypass mode, causing a short which closed the valve. The technician had apparently not followed a pro-cedure step calling for placing a test switch in a position that would have prevented the isolation. The isolation was reset within 5 minutes and the testing was resumed. A one-hour ENS call was made to report the isolation valve actuation and momentary HPCI inoperabi-lit The licensee's investigation and proposed corrective actions were not completed as of the end of the inspection period, and will be followed in further inspection .7 Control Room Ventilation Isolation A main control room ventilation isolation occurred on January 22. A heavy snowstorm underway at the time deposited an excess of snow in the ventilation intake plenum, saturating the chlorine detectors and causing a false high chlorine concentration signal that actuated the emergency fresh air supply (CREFAS). The detectors were modified in April, 1986 with new electrochemical type probes that have been identified as susceptible to moisture. The detectors were bagged to protect them from mosture during the storm, and the control room remained isolated with the CREFAS system in operation until the probes could be dried out on January 23. Further discussion of detector susceptibility to moisture is provided in Detail The resident inspector was in the control room at the time of the isolation and verified proper system response and operator action The licensee properly notified thc NRC of the isolation via the EN A separate concern for SGTS single train flow in excess of 1250 cfm, and its relation to secondary containment operability, is provided in Detail .8 Drywell Unidentified Leakage Unit 1 was manually scrammed from 27*4 power on January 27 as part of a controlled shutdown due to increased drywell leakage. Unidentified floor drain leakage had been gradually treading upward at a rate of about 0.5 gpm por month over the previous two months. Leakage increased from 2.5 gpm on January 23 to 4.7 gpm on January 26 when the decision to shut down was mado prior to exceeding the technical specification ilmit of 5 gpm. The licensee had unsuccessfully attempted to reduce the leakage by electrically backseating seven valves on January 26.
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A drywell entry was made on January 27 to identify the source of the leakage. Three valves were subsequently identified as the sources of the leakage. A 24-inch feedwater check (IF010A) valve external l gasket and 12-inch manual RHR shutdown cooling return (1F0608) valve '
! packing, a smaller packing leak was found on a 2-inch motor operated l
reactor vessel hood vent valve (1F005).
The licensee replaced flexitallic gaskets on the shaft bearing side covers of both feedwater line inboard check valves - a leakage problem previously experienced during the June 1986 mini-outag Packing replacements were also completed on the loop A and D RHR l shutdown cooling return valves - these are manual valves with I unusually designed internally spring-loaded ' live' Teflon packin i
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5.0 Licensee Reports In-Of fice Review of Licensee Event Reportt
The inspector reviewed Unit 1 LERs submitted to the NRC Region I office to verify that details of the event were clearly reported, l' including the accuracy of description of the cause an adequacy of corrective action. The inspector determined whether further infor-j mation was required from the licensee, whether generic implications l were involved, and whether the event warranted on-site followu The following LERs were reviewed:
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I LER Number Report Date Subject 86-050 11/17/86 Removal of HPCI from service to l j (Note a) repair valve packing 86-051 11/24/86 Fire watch not established for
{ (Note b) missing conduit seal
!86-052 12/10/86 HPCI steam supply isolation (Notec) during testing
!86-053 12/10/86 Group VI C isolation caused by (Notec) improper root valve manipulation i
86-054 1/20/87 Reactnr Building Isolation caused
, (Note d) by improperly sized-blown SGTS fuse 86-05 1/20/87 RCIC/ERFDS cables improperly
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(Noted) isolated
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.86-056 1/21/87 Inconsistency between control rod block and SDV level instrument ST 86-057 2/2/87 Overdue containment airlock leak (Note d) test Notes:
a- Previously addressed in Detail 7 of Report 86-23 b- Addressed in Report 50-352/87-02 c- Addressed in Detail 5.2 of this report d- Addressed in Detail 4 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 the reporting requirements of 10 CFR 50.73 and technical specifications had been met, that appropriate corrective action had been taken, that the event was reviewed by the licensee, and that continued operation of the facility was conducted in accordance with technical specification limit . LER Nos.86-039 and 046: Chlorine Analyzer Failures Four actuations of the main control room ventilation system, with automatic emergency fresh air supply (CREFAS)
starts, occurred in July 1986 which were attributed to moisture and iron particles found on the chlorine analyzer probe wicks. The events were reported in LER Nos.86-037 and 039. NRC review of the events was documented in Inspection Report 50-352/86-1 Three additional actuations occurred in September 1986 which were attributed to high winds (35-55 mph) and rain and were reported in LER 86-046. The manufacturer of the probes Anacon, confirmed that the presence of rainwater on
, the probe wicks caused a chemical imbalance that simulates t
a high chlorine condition. This moisture effect eliminated a possible root cause under consideration from the July 1986 events; namely, slight amounts of actual chlorine present (in the intake plenum where the probes are located)
due to routine cooling tower chlorination. The Anacon electrochemical probes had been installed in May-June 1986 to replace a more unreliable type that had used a
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photosensitive tape subject to frequent failures and resultant challenges to the CREFAS system. The sensitivity
- of the probe (0-4 ppm chlorine range) is such that a slight
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amount of moisture, debris or pollutant is enough to effect th* detector's response and cause a ventilation isolation /
CREFAS start at the 0.4 ppm concentration setpoint, i
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On January 22, 1987, an isolation and CREFAS initiation occurred during a snowstorm that was attributible to moisture which affected the chemical balance of the probe's electrolyte. As with previous isolations, the inspector's observed control room personnel to properly respond to the actuation and investigate the cause. During the past month, the surveillance frequency for calibration checks of the chlorine detectors has been doubled, so that every two weeks I&C technicians and chemistry personnel introduce a
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small concentration of chlorine to the probes to verify i proper response time and detector sensitivity (i.e., no rust or debris accumulation, or moisture which could mask the presence of actual chlorine influent). The inspector l concluded that the licensee had addressed all possible engineering alternatives in deciding upon the final probe design, and that much of the past 8 month's difficulties were attributable to a learning curve with a prototype solid state system that is now better understood by plant staff. Vendor assistance and corporate engineering support were appropriately involved. From a safety significance perspective, the inspector reviewed Section 7.1.1 of the
, Limerick Severe Accident Risk Assessment (SARA) for external events such as the release of chemically toxic
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vapors. Chlorine is the only vapor for which automatic detection and isolation are required. Five other vapors 1 are automatic 1aly detected and activate alarms, but do not i
cause ventilation isolation /CREFAS start. The SARA i
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concludes that the release of toxic gases is a small contributor to risk-calculated to be approximately 0.3% of i the total core damage frequency. No outstanding concerns with respect to current chlorine detection systems were
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identified by the inspector.
i 5.2.2 LER Nos.86-052 and 053: Isolations Caused by Personnel
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Error i The subject LER's addressed isolation valve closures on November 10, 1986 caused by I&C technician error in the
, first instance and non-licensed operator eerror in the j second. The first instance involved a Rosemont calibration j being used in place of the normal Riley temperature
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switches to read thermocouple data. The second instance involved blocking performed in-sequence but too rapidly for i the equalizing valve of a pressure switch. Both instances l are commonly performed evolutions that have not had i previous occurrences, although instrument root valve mani-
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pulations are the subject of past reportable events that
, have resulted in special instrument rack signage and
- training classes. The inspector discussed both instances
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with I&C supervision and identified no further concerns.
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5. LER 86-050; HpCI Packing Maintenance The maintenance associated with LER 86-050 was reviewed in detail as part of Inspection 50-352/86-23. 9 he LER describing the event was reported on November 17, 1986 as a voluntary report. The inspector discussed the reportabi-lity of this event with plant staff and a PECO corporate licensing representative. The licensee's rationale for voluntary reporting was described as a cognizant decision on plant staff's part to isolate the steam supply to HPCI so as to repair the outboard isolation valve packing. The licensee considered the valve to be capable of isolation because it had been stroked once after the packing was found dislodged. However, the inspector considered the extent of the damage to the valve stem and collar (as well as the dislodging of all packing) to be such that the maintenance was non-deferrabl Since continued operation with the outboard isolation valve in the as-failed open condition was considered by the inspector to place into question the continued isolation capability for that pene-tration, the LER was therefore required by 10 CFR 50.73 and not voluntary as concluded by the licensee. The inspector had no further questions, and identified no violatio .3 Review of Periodic and Special Reports Periodic or special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed to determine that the report included the required information, that test results and/or supporting information were consistent with design predictions and performance specifications, and whether any information i the report should be classified as an abnormal occurrenc The following reports were reviewed:
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Monthly operating reports for November and December 1986
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Annual Plant Modification Report, dated October 31, 1986 These reports were found acceptabl .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-6-092-311 thru 314; Diesel Generator Operability Test Runs
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ST-2-051-614-1; RHR/LPCI Mode Pump Discharge Pressure (ADS Permissive), Channel Functional Test
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ST-2-052-609-1; Core Spray Pump Discharge Pressure (ADS Permissive), Channel Functional Test
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ST-6-043-320; Jet Pump Operability
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ST-6-051-233-1; RHR Division 3 Quarterly Pump and Valve IST
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ST-6-107-730-1; Weekly Containment Atmosphere Cooling / Cleanup CLOW Valve Exercise
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ST-6-001-760-1; Main Turbine Stop Valve /CIV Exercise The tests were observed to determine that test procedures conformed to techn9:al specification requirements; proper administrative controls and tagouts were obtained prior to testing; testing was performed by qualified personnel in accordance with approved procedures and calibrated instrumentation; test data and results were accurate and in accordance with technical specifications; and equipment was properly returned to service following testin No unacceptable conditions were note .2 Secondary Containment Integrity 6. January 22 Event On January 22 reactor building isolation was manually initiated due to snow clogging the reactor building roll filters. When the isolation was initiated the standby gas treatment system flow indicated in excess of 1250 cubic feet per minute, the Tech Spec 18 month surveillance test criteri Indicated flow was 1500 cubic feet per minute, indicating the possibility that secondary containment integrity was in question. Meteorological conditions at the time of the 1500 cubic foot por minute observation included an 18 mile an hour wind out of the north, which had a significant impact on building leakag Inspection of the secondary containment for leakage and identification
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of several areas where slight improvement could be gained by the use of duct tape, building inleakage was reduce In addition to the taping, licensee Engineering personnel conducted various tests of building inloakage in order to utilize the refueling floor ventilation to control refueling floor pressure, such that the pressure was zero (gauge). Under high wind conditions, the refueling floor has a tendency to pressurize and increase leakage into the secondary containment from any available leak paths on the
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refueling floo It was also noted that during operation of the 'B' standby gas train, ~slightly higher leakage was observed than with the 'A' train. Therefore, the test engineers established a test condition where the 'B' train (i.e. the one with greater leakage) was operated with the building setpoint at the normal value of 0.27 inches of water differential, and the refueling floor ventilation operating in the mode described abov During the 20-minute test period, the building leakage was noted to be trending down. The average of the final ten minutes of steady state operation indicated a flow of 1207 cubic feet per minute. Secondary containment leakage was demonstrated to be less than a value established for the 18 month surveillance test and therefore, secondary containment integrity existed. At 3:08 p.m. on January 22, the Shift Superintendent was notified of the results of the testing in order that no Tech Spec action would be take The plant operating review committee (PORC) reviewed the data for reasonableness, including an ERFDS plot. A safety evaluation was prepared by Engineering discussing the net effect on site boundary dose of increasing wind speed, including the adverse effect on building leakag . Standby Gas Treatment System Test Normally, a test is run once every 18 months to determine secondary containment in-leakage; however, an indicator of in-leakage occurs every 31 days during the standby gas treatment system operability test and during any inadver-tent isolation of the reactor building. The indicated flow on standby gas during these events is not necessarily the same as the indication of building leakage obtained during the controlled conditions of the 18-month tes Items which impact the flow rate under non-standard test condi-tions are:
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Wind Speed The wind speed impacts the building in-leakage by increasing the leakage on the windward side of the building. Offsetting this is the effect that the wind -
has on dose rates at the site boundary. A site boundary dose calculation utilizing a 12 mph average
. wind found that the site boundary dose is reduced by a factor of 4, indicating that the consequences of having a higher indicated building leakage on a windy day are mitigated by the impact of the same wind on the dose calculation. Correlations of the effect that wind has on the increased building leakage have not
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7.0 Receipt of New Fuel The licensee's program for accepting new fuel on site for their firs refueling outage was examined for conformance with regulatory requirement .1 References The following references were used:
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Limerick Generating Station (LGS) FSAR Section LGS Technical Specifications
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LGS License Conditions
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ANSI N45.2.2-1972, Packaging, Shipping, Receiving, Storage and Handling of Items for Nuclear Power Plants 7.2 Program Review i
The inspector reviewed the procedures relating to receipt of new fuel and attended a licensee planning session to determine:
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that the requirements and commitments identified in section were met
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that maintenance, reactor engineering, quality control, security, and health physics responsibilities were clearly t
defined and consistent with the requirements of Section 2.1, and i
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that licensee personnel were prepared and trained to receive new fue The following procedures were reviewed:
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FH-201, Rev. 4, New Fuel Inspection, Channeling and Placement in the New Fuel Pool
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-FH-603, Rev. O, Certification of Fuel Inspectors
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FH-101, Rev. 7, Receipt of New Boiling Water Reactor Fuel
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FH-102, Rev. 5, Transfer of New Fuel from New Fuel Storage Area (NFSA) to Refuel Floor
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QCI-008, Rev. 4, QC Monitoring
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L-FH-02, Rev. 2 (Draft), NFSA Daily Inspection L-FH-03, Rev.1, Fuel Transfer from NFSA to Refuel Floor
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L-FH-04, Rev. 1, Preparation and Shipment of Empty Boxes
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L-FH-05, Rev. 5, Uncrating / Unpacking of New Fuel on the Refuel Floor
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L-FH-06, Rev.1, New Fuel Inspection Shift Activity Summary
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M-041-053, Rev. A, Unloading of New Fuel at New Fuel Storage Area 7.3 Program Implementation To verify that the program was being properly implemented the inspector did the following:
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Made a tour of the outside new fuel storage area to determine if l the new fuel would be protected from rain, dust and debris;
! flooding, weed control, and physical damage. No problems were identifie Held discussions and made observations to determine that the following security controls were in place: a chain link fence topped with concertina surrounded the area, 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> posting of a security guard with controlled access to the area, area lighting was inadequate for monitoring purposes, and the security force j was aware of their responsibilities during receipt of the fuel, i
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Witnessed the receipt of the first shipment of new fuel from the General Electric Co. From observations made the inspector determined that Q1 inspected each crate for damage and verified the crate number and security seal number against the invoice, HP took contamination swipes and radiological surveys of each container, security inspected each container for foreign objects, and maintenance moved the crates in a controlled and planned manne Reviewed the certification and load test results for the fork-lift used to transfer from the fuel bundle crates from the trailer to the storage location. Also verified that the fork lift operator was trained and experienced on the proper use of the fork lif .4 QA/QC Involvement QA was observed performing surveillance of the fuel receipt activities. They also planuan audit of the fuel inspection and refueling activitie No unacceptable conditions or violations were identifie .0 Service Water Pump Operation 8.1 Background The inspector reviewed the design and operational history of the RHR (RHRSW) and emergency service water (ESW) pumps, and independently evaluated the susceptibility to the pitting and corrosion problems discovered in May 1986 at Susquehanna Station. The failures at Susquehanna were characterized by flow-induced cavitation and erosion caused by a phenomenon termed " impeller suction recirculation" that occurs when pumps are operated at flows significantly below design j values.
I The inspector reviewed a June 30, 1986 letter from PP&L to the NRC that provided information on the pump damage at Susquehanna, and
- discussed its relevance to the Limerick Station design with licensee engineering and test personnel. Limerick and Susquehanna both employ
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spray ponds as ultimate heat sinks, and have similar RHRSW and ESW l piping configurations, including the same pump manufacturer - Byron
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Jackson. The inspector assessed operational methods at Limerick,
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including running times and typical flow rates, as well as j operational precautions or methods to preclude similar flow damage.
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8.2 Pump House Inspections On June 6 and 7, 1986 a diver had examined the east wetwell of the Spray Pond Pump House. The 'B' and 'D' RHRSW pumps were inspected and found to be in satisfactory condition. . Inlet sluice gates were also. inspected. The licensee concluded at that time that further inspection or action was not necessar The diver inspected the 'D' RHRSW pump first. He was instructed to look at and feel the exterior, as well as the interior, of the pump suction bell for pitting and corrosion--he found none. The diver was able to feel the lower impeller, finding no physical flaws. Also inspected were the suction bell, series case, and top case fastening bolts, as well as the lower lump mounting molts. All were intact and tigh He also inspected the 'B' RHRSW Pump and reported the same results. Due to a failure of the crane used to pull the pump suction screens and outage time restraints, the 'B' and 'D' ESW Pumps could not be inspected at this tim '~
8.3 System Testing The inspector reviewed quarterly surveillance test records for the ESW and RHR service water systems for 1986. Proper established flows for both systems (3000 gpm for each of 4 ESW pumps, and 9000 gpm for each of 4 RHRSW pumps) were verified. Also verified were proper discharge pressures, motor amps and speed, and vibration data. The Byron-Jackson vendor manuals for the two-stage vertical type pumps provide the following design data:
Type / Design RHRSW ESW Design Operating Flow / Pressure (gpm/psig) 9000/90 6400/104 Minimum Continuous Flow (gpm) 900 500 Size 28 KXL 24 KXH During suppression pool cooling operations in November 1986, control room operators noticed abnormal discharge characteristics from the
'A' RHR service water pump. The pump had exhibited normal charac-teristics when run earlier. Following investigation and testing, a diver removed a 4" x 4" x 2" piece of wood from the impeller. All pump parameters were verified normal by flow tests and the pump was declared operable. Additional parameters available from Bentley-Nevada vibration monitoring were reviewed and verified no impeller damage or change .
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8.4 Conclusion:
Inspection of two RHRSW pumps provided the licensee a level of confidence that Limerick is not presently experiencing the same pitting and corrosion problems as exhibited by the Susquehanna ESW pumps. None of the Limerick pumps have, as of the end of 1986 (estimated at 200-400 hours), experienced the number of operating hours as the ESW pumps at Susquehanna (on the order of 20,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />)
when the failures occurred. The Limerick pump inspection provided a representative idea of the condition of all eight pumps. Also, the Limerick pumps are of a different material, aluminum-bronze liners, than were the cast iron Susquehanna pump bell Although no operating precautions currently exist to preclude pump operation significantly below design flow values, experience has shown that the Limerick pumps are not operated near minimum contin-uous flow values. Finally the licensee has performed previous hydraulic modeling (Western Canada' Hydraulic Lab) for vortexing concerns in the spray pond pump pits. The analyses included scale modeling under different operating modes, such that the wet pit design is not expected to develop destructive flow patterns or turbulence. The inspector will review the licensee's Mechanical
' Engineering study of the susceptability of the Limerick design to the Susquehanna cavitation damag .0 Exit Meeting The NRC resident inspector discussed the issues in this report throughout the inspection period, and summarized the findings at an exit meeting held with Mr. John Franz on January 21 and later discussions on January 22 and 26. At these meetings, the licensee's representatives indicated that the items discussed in this report did not involve proprietary informatio :
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