IR 05000354/1999005
| ML20217A695 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 10/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20217A692 | List: |
| References | |
| 50-354-99-05, NUDOCS 9910120059 | |
| Download: ML20217A695 (15) | |
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, U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No: 50-354 License No: NPF-57 Report No: 50-354/99-05 Licensee: PSEG Nuclear LL Facility: Hope Creek Nuclear Generating Station Location: P.O. Box 236 Hancocks Bridge, NJ 08038 l l
Dates: July 11 - August 29,1999 Inspectors: J. D. Orr, Senior Resident inspector J. T. Furia, Senior Radiation Specialist
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Approved By: Glenn W. Meyer, Chief, Projects Branch 3 Division of Reactor Projects
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i 9910120059 991001 PDR ADOCK 05000354 G PDR
SUMMARY OF FINDINGS Hope Creek Generating Station '
NRC Inspection Report 50-354/99-05 The report covers a 7-week period of resident inspection using the guidance contained in NRC Inspection Manual Chapter 2515*. j Inspection findings were assessed according to potential risk significance and were assigned colors of green, white, yellow, or red. The inspection found only green findings, which were indicative of issues that, while not necessarily desirable, represented little risk to safety. White findings would have indicated issues with some increased risk to safety and which may have '
required additional NRC inspections. Yellow findings would have indicated more serious issues with higher potential risk to safety and would have required the NRC to take additional actb "r Red findings would have represented an unacceptable loss of margin to safety and would have resulted in the NRC taking significant actions that could have included ordering the plant to shut down. The findings, considered in total with other inspection findings and performance indicators, will be used to determine overall plant performanc <
Cornerstone: Mitigating Systems eGreen. NRC inspectors identified a long-standing degraded fire protection barrier in the 117' elevation cable spreading room (CSR). The inspectors identified an open 4 inch floor drain valve that provided a vent path and would have degraded the effectiveness of the automatic CO2 fire suppression system. The NRC staff used the significance determination process (SDP) and determined that this longstanding problem had a minimalimpact on safety due to the alternative safe shutdown and additional firefighting capabilities which existed, a conservative assumption for medium degradation of the automatic CO2 suppression system, and the low likelihood of a fire in the CSR. This issue was treated as a non-cited violation. (Section 1R05)
eGreen. NRC inspectors identified impreper fire protection compensatory actions for a degraded condition in the 117' elevation cable spreading room (CSR). PSEG had implemented an hourly firewatch for a degraded fire protection alarm in the 117'
elevation CSR, but the Hope Creek fire protection procedures specified a continuous fire watch. This issue had a minimal impact on safety due to the frequency of the existing fire watch and the low likelihood of a fire in the CSR. (Section 1R05)
Cornerstone: BarrierIntegrity eGreen. Control room operators failed to appropriately identify abnormal lineups in the primary containment instrument gas (PCIG) and feedwater heating systems after a reactor recirculation runback. The operators' failure to promptly correct these abnormal lineups placed the plant outside of its licensing basis. In the case of the feedwater heating system abnormal lineup, the plant was retumed to 100% power with feedwater inlet temperature was at a reduced temperature. The reduced feedwater inlet
'emperature affected the core thermal performance and placed additional strain on the li
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. Summary of Findings (cont'd)
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fuel barrier during the recovery to full power. Reactor engineers did not effectively monitor the plant recovery and contributed to the error in operation with reduced feedwater inlet temperature. The NRC inspectors noted that operation at reduced feedwater temperature is prohibited to protect the fuel barrier integrity. This problem related to the fuel barrier had a minimal impact on safety as determined by the SDP because no immediate or long-termed degradation of the fuel barrier occurred. This problem was treated as a non-cited violatio Operators were indirectly alerted to the abnormal PClG lineup by a different alarm 45 minutes after the fact. The abnormal PCIG lineup was then promptly corrected by the
- operators. An NRC risk analyst conducted an assessment of the risk associated with the l abnormal PCIG lineup and concluded that the overall plant risk was minimal. (Section l 1R14).
Performance Indicator Verification i *The inspectors identified several errors in historical data and one error in recent data l (since the start of the pilot program and NRC PI submittal) for the Safety System
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Unavailability, Residual Heat Removal System performance indicator (PI). The NRC 1 inspectors determined that the RHR unavailability remained green (less than 2%) and changed to about 1.3% from 0.8%. The historical errors were carried forward from an
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old PSEG performance indicator database and were submitted to the NRC on a "best faith effort." The one error in recent data was a failure to include a support system unavailability, specifically station service water, into the RHR unavailability. PSEG initiated Notification 20003722 to correct the RHR unavailability Pl, verify all previous NRC Pl submittals, and improve the verification processes and validity of future Pl (Section 40A2)
Other i eGreen. Technicians did not provide adequate fuse protection and isolation for a non- I safety-related single cell battery charger installed on the safety-related batteries. This self-identified violation was reported in LER 99-007-00 and was treated as a non-cited violation. This issue had a minimal impact on safety as determined by the SDP because the batteries were able to properly perform their safety fur.ction. (Section 40A4)
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TABLE OF CONTENTS SUM MARY OF FI N DI NGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lv R EACTOR SAF ETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 R03 Emergent Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1R04 Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 R09 I nservice Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . 3 1 R10 Large Containment Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1R12 Maintenance Rule implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1R13 Maintenance Work Prioritization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 1R14 Nonroutine Plant Evolutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . 4 1 R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 1 R16 Operator Work-Arounds . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . .........6 1 R 19 Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1 R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1EP1 Drill, Exercise, and Actual Events ................................8 RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 OS1 Access C ontrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 OS3 Radiation Monitoring Instrumentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 OTH ER ACTIVITI ES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 40A2 Performance indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 4 0A4 Othe r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 40A5 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 ITEMS OPENED AND CLOSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 iv
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. Report Details SUMMARY OF PLANT STATUS Hope Creek operated at or near full power until August 27,1999. A reactor recirculation runback to about 70% power occurred on August 20* as a result of an electrical transient from a lightning strike in the Salem 500kV switchyard. The plant was returned to full power on August 21". A scheduled plant shutdown was initiated on August 27* to replace the A reactor recirculation pump seal and reduce main turbine bearing vibrations with a balance weigh . REACTOR SAFETY
Cornerstones: Initiating Events,' Mitigating Systems, and Barrier Integrity 1R03 Emeraent Work inspection Scope The inspectors reviewed troubleshooting activities and work controls associated with an A station service water pump inservice test failur Observations and Findinas There were no findings identifie R04 Epulament Alianments Inspection Scope The inspectors performed partial redundant equipment alignment verifications during system outages on the instrument air system, A 1E switchgear room cooler, A/C core spray subsystem, and D emergency diesel generator H fuel oil storage tan l l Observations and Findinas i There were no findings identifie R05 Fire Protection Inspection Scope The inspectors performed a walkdown of the 77' and 117' elevation cable spreading rooms' (CSRs) fire protection systems. The inspectors also reviewed fire impairments associated with the CSR m
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l Observations and Findinas The control building 117' elevation CSR has an automatic carbon dioxide (CO2)
suppression system and a fire and smoke detection system. The CO2 is the primary means to suppress a fire in the 117' CSR. A manual pre-action system is an available backup fire suppression system for the 117' CSR. The CSR boundaries must be sealed for the CO2 to be completely effectiv During a walkdown on August 17,1999, the NRC inspectors identified a 117' CSR 4-inch floor drain isolation valve that was open. Updated Finai Safety Analysis Report (USFAR)
section 9.5.1.1.9 described the floor drain valve as normally closed to prevent CO2 fire suppression agent dissipation. The inspectors informed the PSEG safety and loss prevention unit, who restored the drain valve to a closed position. These personnel suspected that the drain valve may have been open for a very long time, since the valve was difficult to operate, was not labeled and was not included in the valve configuration data base. PSEG determined that the open drain valve was not in accordance with Hope Creek operating license condition 2.C.(7) and reported the license condition violation to the NRC on August 18,1999. PSEG entered the problem into its corrective l action program as Notification 7000067 !
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The NRC inspectors used the fire protection significance determination process (SDP) to understand the potential risk significance on safe shutdown (SSD) capability. Phase 2 of the SDP was performed to determine the significance of this finding. The inspectors assumed that the CO2 suppression system as well as the fire barrier had a medium level of degradation and had existed in that condition for more than 30 days. The inspectors compared the initiating event likelihood for the CSR with the remaining SSD mitigating capability and determined that the issue bed a minimal impact on safety. Therefore, the inspectors considered this license violation ard problem within the licensee response band (green). This violation is being treated as 6: non-cited violation, consistent with the Interim Enforcement Pol ;y for pilot plants. This violation is in the PSEG corrective action program as Notification 70000673. (NCV 50-354/99-05-01).
The NRC inspectors reviewed PSEG's immediate corrective actions for the open drain valve problem and determined that had the valve not been closeable, PSEG would have implemented a continuous fire watch for an open drain valve in the 117' elevation CS The inspectors noted that this was inconsistent with an hourly fire watch for another ,
known degraded fire barrier condition in the 117' CSR. PSEG reviewed the compensatory actions at the inspectors' request and determined that the appropriate compensatory actions were not in place for this degraded fire barrier in accordance with :
i Hope Creek fire protection procedure, HC.FP-AP.ZZ-0004(Q). A continuous fire watch was specified, not an hourly fire watch as implemented. PSEG entered the problem into
' its corrective action program as Notification 70000692. This failure to correctly implement the fire impairment compensatory action represented a procedure violatio This issue was a green finding and had minimal impact on safety due to the frequency of the existing fire watch and the low likelihood of a fire in the CSR. This violation is being ,
treated as a non-cited violation, consistent with the Interim Enforcement Policy for pilot j l
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plants. This violation is in the licensee's corrective action program as Notification 70000692. (NCV 50-354/99-05-02).
1R09 Inservice Testina Inspection Scope The inspectors reviewed inservice test results and the adequacy of inservice test procedures associated with the D safety auxiliaries cooling system (SACS) pump, the reactor core isolation cooling (RCIC) system pump, and the D emergency diesel generator H fuel oil storage tank transfer pum Observations and Findinas There were no findings identified.
1R10 L3 roe Containment Valves Insoection Scope The inspectors reviewed administrative controls for the drywell and suppression chamber purge system isolation valve Observations and Findinas There were no findings identifie {
1R12 NIaintenance Rule implementation Inspection Scope The inspectors reviewed maintenance rule implementation for three high risk significant equipment failures; Action Requests (AR) 990401439, 'C' station service water (SSW)
strainer failure; AR 990609245 'C' SSW strainer breaker tripped; and AR 990601157, 'B'
control room ventilation train tri Observations and Findinas Each of the ARs was initially screened as a system functional failure (SFFs). System engineers had not yet screened ARs 990609245 and 990601157 for maintenance preventable system functional failures (MPFFs). The NRC inspectors asked the Hope Creek m.dntenance rule program manager for the results or' the MPFF determination The maintenance rule program manager subsequently discovered that MPFF determinations were not yet made and in all likelihood would have gone unexplored because of a recent conversion to a new PSEG administrative computer system. PSEG performed a search and found eight other system functional failures which could have gone unnoticed for maintenance rule implementatio .
The third AR,990401439, had been reviewed by the system engineer for MPFF determination, who had determined that the specific SSW strainer equipment failure was not a system functional failure and was reclassified as such. The NRC inspectors i reviewed the circumstances of the strainer failure and disagreed with the system l engineers decision.' The system engineer reconsidered the failure, agreed with the inspectors, and reclassified the failure as a SFF and a MPF R13 Maintenance Work Prioritization Insoection Scope l
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The inspectors evaluated PSEG's on-line risk management for an instrument air system outage'on July 19,199 Observations and Findinas There were no findings identifie l 1R14 Nonroutine Plant Evolutiong Full Power Operation at Reduced Feedwater Temperature Insoection Scooe The inspectors reviewed the circumstances surrounding an August 20 reactor l recirculation runback and recovery,
' Observations and Findinas On August 20,1999 at 11:58 p.m., a lightning strike in the Salem switchyard induced a voltage transient in the Hope Creek plant. (The Hope Creek and Salem switchyards are !
normally tied through a 500 kv transmission line.) The Salem plants were unaffected, but an incoming Salem switchyard transmission line was tripped by the lightning strik No Hope Creek electrical busses were lost, however several pieces of equipment tripped; back-up equipment auto-started as designed due to these equipment trips. Four plant systems were affected that had an immediate effect on the continued operation of the Hope Creek plant: all drywell coolers tripped, the A reactor feed pump turbine tripped, each motor operated extraction steam valve to the high pressure feedwater heaters closed, and both' primary containment instrument gas (PCIG) compressors locked ou ,
i nrwgh interviews and log review, the NRC inspectors determined that operators '
w:ocuted the appropriate abnormal procedures. However, the inspectors determined that operators failed to appropriately notice abnormal lineups in the primary containment instrument gas and feedwcter heating systems. The operators' failure to promptly correct these abnormal lineups placed the plant outside of its licensing basis. These problems are further discussed in detail in the following paragraph _
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The trip of the A RFPT and subsequent reactor water levelimering to 30 inches caused, as designed, an_ intermediate reactor recirculation runback from 100%. The plant was
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stabilized at about 70% power, Operators promptly restarted all drywell coolers to
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maintain drywell temperatures normal. The high pressure feedwater heaters extraction I steam motor operated valves (MOV) closed during the electrical transient. However, '
control room operators did not notice the abnormal feedwater heating lineup until after the plant had been recovered to 100% power. The operators began a power ascension at about 12:52 a.m. The operators believed that plant conditions were stable, the cause of the runback was understood, and that equipment lineups had been restored to a point of allowing a plant recovery to 100%. The operators also understood that continued plant operation below about 85% power was potentially undesirable because of known main turbine bearing vibration problems at reduced load. Since restart from the refuel ,
outage ending in April 1999, the number 7 main turbine bearing had experienced I increased vibrations at reduced loads. The vibration problem also tended to increase with time at reduced load. See report section 1R16 for further details about the main turbine bearing vibrations. The operators completed the ascension to 100% power at 4:19 At about 06:00 a.m., the operators became concerned that some plant parameters were not the expected normal full power values: reactor pressure was about 10 psig less, feed flow was about 7% less, and RFPT controller demand was about 3% les Operators had also been concerned about core thermal values (core maximum fraction
. of critical power, core maximum average planar linear heat generation rate, and core i maximum fraction of limiting power density) throughout the duration of the transient. The operators updated reactor engineers via telephone on the core thermal behavior since shortly after the runback occurred. In their investigation of the unusual plant parameters, the operators discovered that feedwater inlet temperature was low and the high pressure feedwater heaters extraction steam MOVs were closed. Feedwater temperature was at about 365 degrees Fahrenheit during the event compared to the normal 420 degrees Fahrenheit. Hope Creek operating license condition 2.C.(11) prohibits full power operation with a feedwater intet temperature below 400 degrees Fahrenheit without prior NRC approval. The operators reported the operating license condition violation to the j NRC Operations Center on August 21,199 The operators entered the abnormal procedure for loss of feedwater heating and recovered the high pressure feedwater heaters. Reactor engineers and nuclear fuels engineers were called on-site to investigate the immediate and long-term effects on the fuel. The cooler water entering the reactor affects the strain induced on the fuel rod cladding, potentially challenging the integrity of this barrier. The nuclear fuels engineers I determined that one PSEG administrative power ramp rate limit was exceeded, but that no technical specification core thermal limits had been exceeded. The nuclear fuels engineers also determined that sufficient margins existed on core tharmal values and the ,
plant was not operated outside the design basis. Normal reactor coolant activity :
samples and offgas system activity during subsequent plant operation confirmed that in all likelihood, no long-term fuel defects were induced during the plant transient.
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. 6 1 PSEG initiated a level 1 root cause investigation for the equipment responses, operator errors and reactor engineer weaknesses that occurred related to the lightning strike l transient, reactor recirculation runback and subsequent plant recovery at reduced 4 L feedwater temperature. The corrective actions were initiated as Notification 2000353 i The NRC inspectors used the significance determination process (SDP) to understand the potential risk significance of operation at reduced feedwater temperature. The inspectors noted that the basis for the feedwater temperature limit is to protect the fuel barrier integrity due to core analysis uncertainties. This problem related to the fuel barrier screened out in phase 1 of the SDP since the additional strain placed on the fuel
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barrier during the full power recovery did not cause any immediate or long-term degradation of the clading. Also, the performance indicator (PI) for reactor coolant system specific activity measures the consequences of any fuel barrier problem. This violation of Hope Creek operating license condition 2.C.(11) is being treated as a non-cited violation, consistent with the Interim Enforcement Policy for pilot plants. (NCV 50-364/99-05-03)
The safety lockout of the PCIG compressors prevented the compressors from auto cycling on PCIG system receiver pressures. PCIG compressors are necessary to support the main steam isolation valve sealing system and is required by technical specification 3.6.1.4. The operators did not notice the immediate lockout of both PCIG compressors until an instrument gas low pressure overhead annunciator was received about forty five minutes after the transient. The PCIG compressors were made available j after the annunciator was received and operators responded locally to reset the safety lockout. An NRC risk analyst conducted an assessment of the risk associated with the i locked-out PClG compressors and concluded that the overall plant risk was minima i 1R15 poerability Evaluations' , Inspection Scope l The inspectors reviewed all operability determinations initiated during the report period ,
J and included degraded conditions on the No. 2 turbine control valve and the 'A' master trip solenoid valv Observations and Findinos There were no findings identifie R16 OperatorWork-Arounds Inspection Scope The inspectors reviewed all Hope Creek operator workarounds to assess the impact on the operators' ability to effectively respond to plant event .. .. .. .
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. 7 Observations and Findinos Elevated turbine bearing vibrations at reduced loads were present during the plant startup after refuel outage No. 8 in April 1999 and were experienced on every scheduled plant load reduction below 85% power. The vibrations tended to increase with load reduction and the time spent at reduced load. The vibrations could increase to the point where operators would have been required to manually trip the turbine. Hope Creek operators considered this turbine bearing vibration problem an operator workaroun PSEG had scheduled a plant shutdown on or about September 11 to install a weight balance and reduce the main turbine bearing vibrations. . In the interim, Hope Creek operators were provided with guidance to recover any unplanned load reducticn in an expeditious manner after the initiating problem was corrected and understood. The guidance emphasized plant safety above load recovery, Nonetheless, the turbine .
bearing vibration problem was an operator workaround and contributed an element of urgency for recovery to full power operation after any plant transient. On August 20, 1999, a reactor recirculation runback to about 70% power occurred. The details of the reactor recirculation runback are described in Section 1R14, NonRoutine Plant Evolutions. Some operator errors occurred during the recovery and PSEG considered that this workaround may have been a contributing factor. This and other human error problems during the event were included in PSEG's corrective action program. The scheduled plant shutdown was moved up to August 27,1999, and the main turbine vibration problems were correcte R19 Post Maintenance Testina Inspection Scope l
The inspectors reviewed the resu'ts and adequacy of post maintenance tests associated with condensate storage tank low level instrument design changes for the reactor core isolation cooling and high pressure coolant injection systems. The inspectors also reviewed post maintenance tests for the D emergency diesel generator H fuel oil storage tank drain and refil Observations and Findinos There were no findings identifie R22 Surveillance Testina
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l i The inspectors reviewed the performance and adequacy of technical specification I surveillance tests for the reactor core isolation cooling system steam leak detection, D l emergency diesel generator 184 day fast load, and 1E 4kV feeder breaker degraded i voltage instrumentatio ;
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. 8 Observations and Findinas There were no findings identifie Cornerstone: Emergency Preparedness 1EP1 Drill. Exercise. and Actual Events Inspection Scope The resident inspectors observed control room simulator and emergency operations facility performance as it related to event classification, notification and protective action recommendations during a facilities emergency dril Observations and Findinas There were no findings identifie . RADIATION SAFETY Cornerstone: Occupational Radiation Safety OS1 Access Control Inspection Scope The inspector reviewed the access control program by examining the controls established for exposure significant areas, including postings, markings, control of access, dosimetry, surveys and alarm set points. Areas selected were located throughout Hope Cree Observations and Findinas l There were no findings identifie OS2 ALARA Plannina and Controls Inspection Scope The inspector reviewed radiological work performance during the refueling outage in February-March 1999 (RF08). Selected jobs which exceeded their exposure estimates were examined relative to: work integration; coordination between working groups; shielding and other engineering contres to minimize exposures; accuracy of person-hour and effective dose rate estimates; post-job reviews; and, ALARA reports. The inspector also examined audits and self-assessments conducted by the licensee of its ALARA program.
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, 9 j Observations and Findinos License exposures during RF08 were 15 person-rem above estimated (less than 10%
above the total estimated for the outage). The majority of the additional exposure was traceable to significantly higher than anticipated exposure rates under vessel. The j licensee anticipates that the recently installed iron reduction system will aid in lowering l dose rates in this and other plant areas by reducing the amount of crud in the primary i system over tim OS3 Radiation Monitorina Instrumentation Insoection Scope The inspector reviewed and verified licensee records of survey instrument, personnel contamination monitor and whole body counter calibration, daily check, maintenance and repair. Records of calibration source traceability to the National Inctitute of Standards 3 and Technology (NIST) primary standards were also reviewed and erifie Observations and Findinas I There were no findings identifie l OTHER ACTIVITIES [OA]
l 40A2 Performance Indicator Verification r Lntsoection Scooe (71151)
The inspectors verified the accuracy of and methods used to calculate the Safety System J Unavailability, Residual Heat Removal performance indicator (PI) for the previous 36 I months. Limiting Condition for Operation logs, control room operating logs and maintenance rule electronic data bases were reviewe i Observations and Findinas ;
During the inspection, the NRC identified errors in the Safety System Unavailability, ResidualHeat Removal (RHR) PI data submitted to the NRC. The errors included several omissions of RHR train unavailability throughout the historical data (prior to May 30,1999) and one error in June 1999. The error in June 1999 did not account for a planned 'B' station service water loop outage that rendered the 'B' RHR train unavailabl The inspectors determined that the RHR unavailability PI remained green and changed to about 1.3% from 0.8% and did not exceed the white threshold (2%). PSEG initiated a corrective action Notification (#20003722) to improve the completeness and accuracy of all future NRC Pl submittal .
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40A4 Other (Closed) LER 99-007-00: license condition violation - class-1E battery charging operation. This LER described the improper installation of a non-1E battery charger on single cells of an operable class-1E battery. The inspectors evaluated the improper battery charge installation and the circumstances in the LER. The inspectors determined that the charger installation, although not in accordance with the license requirements, did not render the class-1E battery inoperable. Specifically the battery charger installation did not include redundant class-1E fuses on the cha ger lead PSEG promptly removed the improperly installed battery charger and initiated corrective actions (Action Request 990614116) to preclude repetition. This issue was considered a GREEN finding with minimal impact on nafety as determined by the significance determination process. Specifically, although the event did not render the class 1E batteries inoperable, it did have the potential to impact the operation of safety-related equipment. The improper battery charger installation was a violation of Hope Creek additionallicense condition amendment 114. This violation is being treated as a non-cited violation, consistent with the Interim Enforcement Policy for pilot plants. This violation is in the corrective action program as Action Request 990614116. (NCV 50-354/99-05-04)
40A5 Manaaement Meetinas 1 Exit Meetina Summarv l l
On September 8,1999, the inspectors presented their overall findings to members of !
PSEG Nuclear management led by Mr. Dave Garchow. PSEG Nuclear management l
acknowledged the findings presented and did not contest any of the inspectors' i conclusions. Additionally, they stated that none of the information reviewed by the inspectors was considered proprietary. During this inspection, four non-cited violations were identified as discussed in the report. If PSEG contests these NCVs, a response j should be provided within 30 days of the date of this inspection report, with the basis for i
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the denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region I, and the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident inspector at the Hope Creek I facilit !
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l Ooen/ Closed 50-354/99-05-01 NCV License condition violation - degraded fire protection
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barrier in the 117' elevation cable spreading roo j
(Section 1RO5)
50-354/99-05-02 NCV Failure to implement appropriate fire protection impairment compensatory actions. (Section 1RO5)
50-354/90-05-03 NCV License condition violation - operation at reduced feedwater inlet temperature. (Section 1R14) 3 l
50-354/99-005-04 NCV License condition violation - class-1E battery charging operation. (Section 40A4)
50-354/99-007-00 LER License condition violation - class-1E battery charging operation. (Section 40A4)
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