IR 05000361/1999001
| ML20205E574 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 03/30/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20205E547 | List: |
| References | |
| 50-361-99-01, 50-361-99-1, 50-362-99-01, 50-362-99-1, NUDOCS 9904050226 | |
| Download: ML20205E574 (23) | |
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ENCLOSURE
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U.S. NUCLEAR REGULATORY COMMISSION
- REGION IV Docket Nos.
- 50-361 50-362 License Nos.: NPF-10
!. NPF-15 l Report No.: 50-361/99-01 1 50-362/99-01 i
Licensee: Southern California Edison C l l Facility: San Onofre Nuclear Generating Station, Units 2 and 3 l Location: 5000 S. Pacific Coast Hw San Clemente, California (
Dates: January 3 through February 20,1999 l Inspectors: J. A. Sloan, Senior Resident inspector J. G. Kramer, Resident inspector D. E. Corporandy, Resident inspector Approved By: L. J. Smith, Acting Chief, Branch E Division of Reactor Projects ATTACHMENT: SupplementalInformation
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9904050226 990330 PDR ADOCK 05000361 e PDR
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i EXECUTIVE SUMMARY San Onofre Nuclear Generating Station, Units 2 and 3 NRC Inspection Report No. 50-361/99-01; 50-362/99-01 This routine announced insp .:.on reviewed aspects of plant operation, maintenance, engineering, and plant support. This report covers a 7-week period of resident inspectio Operations
Operators carefully conducted two midloop operations during the Unit 2 refueling outage. Management oversight of the evolutions was excellent (Section 01.2).
Operators and refueling personnel performance during the core offload was goo Communications were clear and included repeat-backs. Fuel movements were performed in a controlled and deliberate manner (Section 01.4).
Operations management demonstrated conservati.sm in requiring a more direct backup boric acid flow path than had been planned, which was not required by Technical Specifications, and in delaying the core reload until satisfied with the flow path Additionally, the licensee exercised due precaution in delaying recommencement of the core reload until both trains of the control room emergency air cleanup system were operabis. These instances re,mied a philosophy of placing safety above production (Section 01.5).
- Operators' response to a slight overpower event was slow in that the operators did not promptly reduce power to less than 100 per :ent. Power peaked at 100.2 percent and was greater than 100 percent for 86 minutes. However, the reactor power excursion did not exceed the guidance provided in a 1980 NRC memorandum discussing licensed power loads and was therefore acceptable. Licensee corrective actions were adequate (Section O1.6).
Maintenance
- Operations Test Group and Health Physics performance during a high pressure safety injection pump surveillance was good. The operators used good communications and self verification, while using multiple procedures. A Health Physics technician provided active and continuous coverage of the job, which breached a poter:tially contaminated system (Section M1.3).
- Electricians' performance during an inverter calibration was good. The electricians used good self- and cross-checking of the results and were knowledgeable regarding i operation of both the inverter and testing equipment (Section M1.4).
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Operations' procedures and crew understanding of what constituted a reactor coolant system heatup were weak. The procedure incorrectly led operators to believe that a slow planned reactor coolant system heatup did not require formal documentation to verify that temperature, pressure, and heatup rate remained within acceptable limit However, the actual verification of these parameters was performed as required (Section M1.5).
Refueling per.sonnel performance during the reactor vessal head stud detensioning was good. The crews controlling the individual tensioneraere kreowledgeable regarding the operation of the equipment. The lead assistant refueling supervisor coordinated the performance of three tensioning crews and provided overall evolution and procedural control (Section M4.1).
Noncited violations (Enforcement Policy, Appendix C) of Technical Specifications 3.7.14 and 3.7.11 were identified as the result of filter surveillance testing not having been performed as required by current standards, affecting both the postaccident cleanup units and the control room emergency air cleanup units (Section M8.1).
A noncited violation (Enforcement Policy, Appendix C) of Technical Specification 3.7.14 was identified as the result of the Unit 3 Train B postaccident cleanup system being inoperable because of having inadequate flow. This had not been detected during surveillance testing because of a flow calibration error (Section M8.2).
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The licensee's response to a 1996 fire protection self-assessment resuted in a thorough review of cable sizing calculations based on testing of site-specific raceway configurations. The corrective actions for a cable ampecity design deficiency, identified
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by Nuclear Engineering Design during this process, were prompt and adequate. An l
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unresolved item was opened pending review of the licensee's reportability assessment l of the inoperable control room emergency air cleanup system (Section E1.1). ;
- A large foreign object (a foreign material exclusion cover for a moisture separator can)
had been left in Steam Generator 2E089 since the midcycle outage in early 1998. The ;
licensee's evaluation of the source and effects of the object was thorough, and the l planned corrective actions were adequate (Section E2.1).
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Maintenance and Station Technical responded aggressively to quantify undocumented aluminum found in the Unit 2 containment normal air cooler prefilters and to determine l that Unit 3 was not affected. The licensee's investigation was thorough in identifying causes and corrective actions, and the operability assessment was adequate
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(Section E2.2).
A noncited violation (Enforcement Policy, Appendix C) of Technical Specification 3.8.3.1.a (in the pre-1996 Technical Specifications) was identified as the
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result of the licensee's discovery that the line voltage regulator voltage setpoints were incorrect and that, in 1986,120 volt ac buses had been aligned to the inoperable line voltage regulator longer than allowed (Section E8.1).
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.- Health Physics demonstrated continued effectiveness in radiological dose reduction l through implementation of engineered features, including specially designed shielding for pressurizer heater nozzles and expanded use of the Comprehensive Application for Reduced Exposure System (Section R1.1).
I l * An unresolved item was identified to review the applicability of both the Physical Security l Plan and the implementing procedure requirements to openings in a vital area barrier ;
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Report Details Summary of Plant Status Unit 2 began this inspection period in Mode 4, on the second day of the Cycle 10 refueling ;
outage. The unit reached Mode 5 on January 3,1999, Mode 6 on January 7, and was defueled on January 17. The core reload was commenced on January 29 and completed on February Mode 5 was entered on February 11 and Mode 4 on February 20, the last day of this inspection perio On February 1, the licensee declared an unusual event at Unit 2 because shutdown cooling l was lost for more than 10 minutes. Operators restored shutdown cooling after 26 minutes and !
terminated the unusual event. Details of this event are discussed in NRC Inspection Report 50-361;50-362/99-0 :
Unit 3 coerated at essentially full reactor power for this inspection period, except from ;
February 13-17,1999. On February 13, power was reduced to lower the circulating water differential temperature in order to increase the component cooling water (CCW) temperature to the emergency chillers. This action was taken because of uncommonly cold seawater. The unit returned to essentially full reactor power on February 1 . Operations 0 Conduct of Operations 0 General Comments (71707)
The inspectors observed routine and nonroutine operational activities throughout this inspection period. Some of the activities observed included:
Low pressure safety injection pumps swapped from Train A to Train B (Unit 2)
Operation management control room oversight turnover (Unit 2)
Loss of plant monitoring system computer and transfer to core operating limits backup (Unit 3)
Shift turnovers (Units 2 and 3)
Secure saltwater cooling (SWC) and CCW Train B (Unit 2)
Core offload (Unit 2)
- Outage management turnover (Unit 2)
Fill and drain of refueling cavity (Unit 2)
- Solid plant operations (Unit 2)
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Operators were thorough and methodical in preparing for and conducting routine evolutions. Close management and supervisory oversight of operational activities were evident. Procedure use and operator communications were consistent with written j expectathns. Specific comments on activities are discussed belo .2 Midlooo Opet ations - Unit 2 I
- Insoection Scope (71707)
The inspectors observed the preparations for, and conduct of, midloop operations on January 5-6 and February 11,1999. The inspectors reviewed Procedures SO23-3-1.8,
" Draining the Reactor Coolant System," Revision 14, and SO23-5-1.8.1," Shutdown Nuclear Safety," Revision Observations and Findinas On January 5, the licensee's prejob briefing for the draindown to midloop addressed expectations, contingencies, and responsibilities for those involved. This briefing was conducted using the licensee's enhanced programmatic controls for higher risk evolutions. Problems had been encountered while placing the diverse level monitoring system (DLMS) into service. Consequently, the licensee made the decision to perform the draindown without the DLMS being in service. The unavailability of the DLMS was discussed during the prejob briefin The inspectors reviewed licensee commitments regarding the DLMS and other level monitoring systems and determined that the commitments were being met even with the DLMS out of service. Other level monitoring systems that were functioning included the heated junction thermocouples (two trains), the refueling water level indicator (narrow-and wide-range), and the refueling sight glass. Some of the heated junction thermocouple probes were not functioning in both trains, but the licensee had only committed to having Probe 6 (at 21 inches above the bottom of the hot leg) on one train functionin During draindown the licensee closely monitored the calculated time-to-boil for the reactor coolant system (RCS) and had established a minimum time-to-boil limit of 16 minutes. During the draining evoletion, the inspectors frequently calculated the time-to-boil and verified that the i; .see calculations were accurat An Operations management representative continuously and closely monitored the draindown and subsequent midloop operations, until the reduced inventory condition was exite The initial draindown commenced at 12:30 p.m. on January 5 and was carefully j conducted. Operators frequently monitored the direct level indications discussed above, l as well as indirect indications, such as inventory changes in the radwaste primary tanks that were aligned to receive the water from the RCS. All level indications were frequently correla:ed. After level was lowered to the top of the hot leg, approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of steam generator tube draining had to be completed before level could be
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lowered further. During this time the CLMS was placed into service, providing both l narrow- and wide-range indication that correlated well with other indications. However, j the DLMS was not declared operable until after the final drain,26 inches above the
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bottom of the hot leg, was completed. Reduced inventory conditions were exited at approximately 11 a.m. the following day, after the installation of the steam generator nozzle dams.
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l On February 11, the inspectors observed the second draindown to midloop for the l removal of the steam generator nozzle dams. The evolution was parformed with similar ( '
management oversight. The draindown was conducted in a deliberate and cautious l manner, Conclusions Operators carefully conducted two midloop operations during the Unit 2 refueling ,
outage. Management oversight of the evolutions was excellen l l
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l 01.3 Loss of Shutdown Coolino - Unit 2 (93702)
j- On February 1,1999, while Unit 2 was in Mode 6 conducting a reactor core reload, a l loss of shutdown cooling occurred. A loss of voltage on the Train A 4160 volt electrical l bus occurred when licensee personnel inadvertently closed the feeder breaker from the l grounded reserve auxiliary transformer. An unusual event was declared because l shutdown cooling was lost for more than 10 minutes. Shutdown cooling was restored l after 26 minutes, and the unusual event was terminated 15 minutes later. This issue is l being addressed in NRC Inspection Report 50-361; 362/99-03.
i O1.4 Core Offload - Unit 2 l Insoection Scope (71707. 71750)
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, The inspectors observed aspects of the core offload. The inspectors reviewed ,
l Procedures SO23-X-7," Nuclear Fuel Movement for Refueling Cycles." Revision 7; I l
SO23-1-3.42," Refueling Machine Operation," Revision 5: SO23-I 3.19, " Spent Fuel Handling Machine Operation," Revision 5; and SO123-1-1.18, " Foreign Material Exclusion (FME) Control," Revision 4.
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On January 13,1999, the inspectors observed the core offload from the refueling machine in containment. The refueling personnel used cameras and direct observation as means to determine assembly grappling and movement. Fuel movement and refueling machine operational movements were in accordance with
'. Procedure SO23-1-3.42, coordinated by the control room, and under direction of the refueling senior reactor operato >
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i On January 15, the inspectors observed the core offload from the spent fuel pool. The l operator used appropriate radiation protection practices when handling the spent fuel handling tool. Fuel movement included continuous visual verifications by the operator ]
as to the fuel position and awareness of interferences during fuel movement. The operator was knowledgeable about the handling of the spent fuel handling machin Operators and refueling personnel in both the containment and spent fuel pool areas maintained FME control as directed by Procedure SO123-1-1.18 and were observed using good closed loop communication Conclusions Operators and refueling personnel performance during the core offload was goo Communications were clear and included repeat-backs. Fuel movements were performed in a controlled and deliberate manne O1.5 Core Reload - Unit 2 Insoection Scoce (71707)
The inspectors observed portions of the preparations for and conduct of core reload activities in Unit 2 from January 29 through February 3,1999, and reviews a the refueling engineer and control room operator logs associated with reload activitie Observations and Findinos The commencement of the core reload was delayed several hours because Operations management was not satisfied with the backup boric acid flowpath established at the time. Operations management determined that the flowpath was not sufficiently direct to be as effective as desired and directed that a more direct path be established. The l inspectors determined that oni/one boric acid flowpath was required by Technical l Specification (TS) 3.1.10, but the licensee's conservative defense-in-depth strategy l required an additional available backup flowpath. The core reload was commenced on l January 29,1999, after an acceptable backup flowpath was established.
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core and to inspect and remove debris. The core reload was on hold for this purpose, when the loss of shutdown cooling (Section 01.3) forced cessation of core alteration At the time, approximately 177 of 217 fuel assemblies had been loaded into the cor While core alterations were suspended, the licensee determined that one train of the control room emergency air cleanup system (CREACUS) was inoperable because of a recently identified cable ampacity design issue (Section E1.1). The licensee decided not to recommence core alterations until both trains of CREACUS were operabl The core reload was recommenced on February 3 and completed later the same da r-
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l Conclusions
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boric acid flow path than had been planned, which was not required by TS, and in delaying the core reload until satisfied with the flow paths. Additionally, the licensee l exercised due precaution in delaying recommencement of the core reload until both l trains of the CREACUS were operable. These instances reflected a philosophy of l pla;ing safety above productio .6 ' Licensed Power Limit Exceeded - Unit 3 l inspection Scope (71707)
l The inspectors reviewed the circumstances surrounding operators exceeding the l l licensed power limit. The inspectors reviewed Procedures SO23-3-2.4, "RCS '
i Purification and Deborating lon Exchanger Operation," Revision 10; and l SO23-15-50.A1, " Annunciator Panel,50A PZR/CEA Windows 1-30," Revision 2, l Temporary Change Notice 2-1. The inspectors discussed the event with the Operations l superintenden Observations and Findinas On January 7,1999, the inspectors were informed by the Operations superintendent l l that the licensed power limit had been exceeded during an RCS delithiation. The l l operators performed the delithiation with an ion exchanger that was known not to be .
baron saturated. Procedure SO23-3-2.4 allowed continuous borations with the letdown !
flow aligned to the volurne control tank (VCT) instead of diverting the flow to radwaste if !
the RCS boron concentration was less than 500 ppm (the RCS boron concentration was approximately 238 ppm). A chemistry memorandum requested a 223 minute delithiation. Procedure S023-3-2.4 stated that the saturation of a new lon exchanger should take approximately 90 minutes. The operators realized, during the evolution, that it was going to take a much longer time to saturate the ion exchanger, due to the low RCS boron concentration at the end of core lif During the delithiation, the core operating limits supervisory system (COLSS) alarm ,
annunciated twice, once for 13 minutes and a second time for 8 minutes. Operators ;
borated the RCS, resulting in these alarms clearing. A third COLSS alarm occurred I after the completion of the delithiation. The delithiation caused the VCT to become diluted. The operators continued to borate to lower power, but not fast enough to compensate for the diluted VCT. Power continued to rise for the next 30 minutes and peaked at approximately 100.2 percent. The COLSS alarm was in for approximately 86 minutes and, therefore, reactor power was greater than the licensed power limit of 100 percent for that tim l l
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The licensee initiated Action Request (AR) 990100513 to evaluate the event. The ,
licensee determined that the 8-hour iolling average for power was 99.97 percent with a i fluctuation over 100 percent power and was not reportable based on guidance from an August 22,1980, NRC memorandum discussing licensed power levels. The inspectors l
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concurred with the licensee's determination that the event was not reportabl I The licensee performed several corrective actions. The operators involved in the l evolution were counseled. A Priority 2 reading / event preshift brief was generated that ,
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outlined management's expectations for conservative decision making. The reading further explained that the intent of the annunciator response procedure was to take prompt action to lower reactor power as soon as practical by lowering turbine load or borating. In addition, the licensee planned to revise Procedure SO23-3-2.4 to incorporate lessons learned from this even Conclusions Operators' response to a slight overpowe'. event was slow in that the operators did not promptly reduce power to less than 100 percent. Power peaked at 100.2 percent and !
was greater than 100 percent for 86 rranutes. However, the reactor power excursion did not exceed the guidance provided in a 1980 NRC memorandum discussing licensed power loads and was therefore accaptable. Licensee corrective actions were adequat II. Maintenance M1 Conduct of Maintenance M1.1 General Comments Inspection Scope (62707)
The inspectors observed all or portions of the following work activities:
= Replace Train A Emergency Diesel Generator 2G00216-cylinder engine air boost line (Unit 2)
= Install Field Change Notice F14323E; add external wiring for engineered safety feature test cables (Unit 2)
= Perform eddy current testing of Steam Generators 2E088 and 2E089 (Unit 2)
= Perform visualinspection of Reactor Coolant Pump 2P001 hydraulic snubber (Unit 2)
= Remove SWC Spool S2-SC-003-014 to facilitate SWC piping inspections (Unit 2)
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Remove CCW Heat Exchanger 2E002 bypass valve (Unit 2)
- Repair intake structure (Unit 2)
Roll tube sleeves in Steam Generator 2E088 (Unit 2)
- Inspect Steam Generator 2E088 sleeve weld (Unit 2)
Reinstall removable barrier walls for CCW heat exchangers (Unit 2) Observations and Findinas The inspectors found the work performed under these activities to be thorough. All work observed was performed with the work package present and in active use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applicable, appropriate radiation controls were in plac ... addition, see the specific discussions of maintenance observed under Section M belo M1.2 General Comments on Surveillance Activities l Inspection Scope (61726)
The inspectors observed all or portions of the following surveillance activities:
l * Perform quarterly inservice testing of Train 8 Auxiliary Feedwater Pump 3P504 l (Unit 3)
- Check valve open test for refueling water storage tank to Train B low pressure l
safety injection pump suction Check Valves 2MUO77 and 2MU199 (Unit 2)
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- Inspect Train B Emergency Diesel Generator 2G003 day tank for accumulation of water (Unit 2)
- Perform integrated test of engineered safety features (Unit 2)
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- Visually inspect reactor coolant pump hydraulic snubbers (Unit 2)
- Perform hydraulic fluid analyses for reactor coolant pump and steam generator hydraulic snubbers (Unit 2)
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l Observations and Findinos The inspectors found all surveillances performed under these activities to be thoroug All surveillances observed were performed with the work package present and in active l
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use. Technicians were knowledgeable and professional. The inspectors frequently observed supervisors and system engineers monitoring job progress, and quality control personnel were present whenever required by procedure. When applicable, appropriate radiation controls were in place, in addition, see the specific discussions of surveillances observed under Sections M and M1.5, belo M1.3 Hioh Pressure Safety Iniection (HPSI) Pump and Valve Testino - Unit 3 l
l Inspection Scope (61726)
The inspectors observed a surveillance test of a Train B HPSI Pump 3P019 and reviewed Procedures SO23-3-3.60.1,"High Pressure Safety injection Pump and Valve
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Testing," Revision 2, and SO23-3-3.60, " Inservice Pump Testing Program," Revision 4.
l Observations and Findinos l On January 21,1999, the inspectors observed Operations Test Group perform a test of
! HPSI Pump 3P019, using Procedure SO23-3-3.60.1, Attachment 5, and install temporary measuring and test instrumentation using Procedure 8023-3-3.60, Attachment 6. The operators used good communications when performing the evolution. The installation of the temporary instrumentation required the operators to simultaneously perform both procedures. The temporary instrumentation was installed to provide a greater accuracy of the pressures, suction and discharge, monitored during the test. The operators carefully and methodically performed the procedures. A Health Physics technician provided excellent coverage of the job since the testing required the operators to breach a potentially contaminated syste Conclusions Operations Test Group and Health Physics performance during a HPSI pump surveillance was good. The operators used good communications and self-verificatio while using multiple procedures. A Health Physics technician provided active and continuous coverage of the job, which breached a potentially contaminated syste _
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M1.4 Inverter Calibration - Unit 2 Insoection Scoce (61726)
The inspectors observed electricians perform an inverter calibration. The inr,pectors reviewed Procedures SO23-ll 11.185, " inverters-YOO1,2,3, & 4 for Vital Buses Test / Calibration," Revision 2, and SO23-II-15.3, " Temporary System Alteration and Restoration Form," Revision 7, and Maintenance Order 9801121 Observations and Findinas On January 11,1999, the inspectors observed electricians perform a calibration of Inverter YOO4 voltmeters and ammeters. The electricians were knowledgeable regarding operation of both the inverter and the testing equipment. The electricians properly documented tcmporary system alterations in accordance with Procedure SO23-11-15.3. The electricians each verified the meter readings during the testing, which was beyond the requirement of Procedure SO23-ll-11.185. The electricians adjusted the input signals slowly and more precisely than required by the procedure to achieve accurate reading Conclusions Electricians' performance during an inverter calibration was good. The electricians used good self and cross checking of the results and were knowledgeable regarding operation of both the inverter and testing equipmen M1.5 RCS Heatuo Verification - Unit 2 Inspection Scoce (61726. 71707)
The inspectors observed an RCS heatup and discussed operator performance with Operations management. The inspectors reviewed Procedure SO23-5-1.8," Shutdown Operations (Moae 5 and 6)," Revision Observations and Findinas On February 10,1999, the operators were performing an RCS heatup from approximately 70 to 90 degrees. The inspector questioned a reactor operator about performing an RCS heatup plot verification, and the operator indicated that a plot was not necessary since the heatup was less than 10 degrees per hou Procedure SO23-5-1.8, Attachment 13, provided the limitations and specifics. Steps and 2.8 indicated, in part, that a heatup was defined as any increase in RCS l temperature greater than 10 degrees in any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and that logging and plotting were required for all heatups. Based on the procedure definition of an RCS heatup, two separate crews interpreted the procedure as meaning that a formal documented heatup verification was not required. The inspectors discussed the observation with Operations management. Operations management expressed the expectation that the heatup l
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verification documentation be performed. The licensee planned to make revisions to the necessary procedures to clarify the requirement to perform formal heatup verificatio The inspectors reviewed TS Surveillance Requirement 3.4.3.1 and identified f iat a verification of the RCS heatup was required.' The inspectors had observed operator performance during the heatup period and held discussions with the operators regarding L
the heatup. In addition,' the inspectors reviewed an historical trend of the planned -
- heatup and observed that the maximum change in temperature was approximately l
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7 degrees in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> with the RCS depressurized. The operators were closely monitoring
the heatup rate to avoid exceeding 10 degrees per hour so that plotting could be
. avoided. The inspectors concluded that the operators had met the intent of T Surveillance Requirement 3.4.3.1 and verified that the RCS temperature, pressure, and heatup rate were within the TS limit of 60 degrees in any 1-hour period. In addition, the inspectors noted that the only significant source of heat input to the RCS was decay heat from the reloaded core, and that heatup rate could not exceed the TS limit in the configuration the unit was in at the time.
l' However,10 CFR Part 50, Appendix B, Criterion XVil, requires, in part, that sufficient l
records shall be maintained to furnish evidence of activities affecting quality and shall be l l identifiable and retrievable. The failure of the operators to perform documentation of
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Appendix B. This failure constitutes a violation of minor significance and is not subject to formal enforcement actio Conclusines
. Operations' procedures and crew understanding of what constituted an RCS heatup were weak. The procedure incorrectly led operators to believe~ that a slow planned RCS heatup did not require formal documentation to verify that ternperature, pressure, and '
heatup rate remained within acceptable limits. However, the actual verification of these parameters was performed as require M4 Maintenance Staff Knowledge and Performance
! M4.1 Reactor Vessel Head Stud Detensionina - Unit 2 Insoection Scooe (62707)
..The inspectors observed the refueling group perform stud detensioning and reviewed
Procedure SO23-1-3.24, " Reactor Vessel Head Stud Detensioning." Revision 7.
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'On January 6 1999 the inspectors observed refueling personnel perform detensio in ng
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- of the reactor vessel head using three tensioners. .The licensee used three-person crews (an assistant refueling supervisor and two craft contractor personnel) to operate ;
each of the tensioners. The inspectors observed that the correct procedural sequence l for detensioning the studs was used and that the proper hydraulic pressure was applied l
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l to the studs and was appropriately adjusted when necessary to free the studs.
l Communications, both voice and hand gestures, adequately provided a means to l transfer information. The lead assistant refueling supervisor maintained procedural l
control of the detensioning evolution and directed the activity.
l l Conclusions l Refueling personnel performance during the reactor vessel head stud detensioning was l
good. The crews controlling the individual tensioners were knowledgeable regarding the operation of the equipment. The lead assistant refueling supervisor coordinated the performance of three tensioning crews and provided overall evolutior . r.0cedural contro M8 Miscellaneous Maintenance issues (92902,92700)
M8.1 (Closed) Licensee Event Reoort (LER) 361/1997-013-00: charcoal filter surveance testing not current.
l The licensee identified that the charcoal filter surveillance tests in effect for the )
I postaccident cleanup units (PACUs), and CREACUSs did not meet the requirements of '
( the TSs, because the surveillance requirement was revised during the Technical !
Specification improvement Program and a revised test was not performed. This issue I was discussed in NRC Inspection Report 50-361; 362/98-0 l q
The LER remained open to evaluate the appropriate enforcement action. .The invalid J surveillance tests rendered the PACUs inoperable. The PACUs were required by TS-3.7.14 to be operable during movement of irradiated fuel assemblies in the fuel handling building. Such fuel movements had occurred during the Cycle 9 refueling outages-(November 30,1996, thicugh Apr.11,1997, for Unit 2 and April 12 through July 21, 1997, for Unit 3). The CREACUSs werc similarly rendered inoperable and were required by TS 3.7.11 to b9 operable during movement of irradiated fuel assemblie The inspectors found that the PACUs were not credited in the safety analysis and that the safety analysis only assumed a 95 percent efficiency for the CREACUS charcoal filters. Actual test results for the CREACUS charcoal filters indicated a 96 percent efficiency. Therefore, the filters were shown to be able to perform the safety functions that were credited in the safety analysis. Consequently, the inspectors determined that the potential safety consequence of this issue was lo These Severity Level IV violations of TS 3.7.14 (361; 362/99001-01) and TS 3.7.11
, (361; 362/99001-02) are being treated as a noncited violations, consistent with l Append _ix C of the NRC Enforcement Policy. These violations are in the licensee's corrective action program as AR 971000527.
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' M8.2 (Closed) LERs 361/1998-010-00. -01: PACU inoperable due to flow calibration erro The licensee originally reported that the flow recorders used to confirm that the air flows through the PACUs in both units were incorrectly calibrated, resulting in the inoperability of the Train A PACU in Unit 2 ano both PACUs in Unit 3. The remaining Unit 2 PACU was also declared inoperable due to lack of confidence in the surveillance data. The LER was revised to state that, upon further investigation, only the Unit 3 Train B flow had actually been outside its TS 3.7.14 limit (TS 3.9.12 prior to implementation of the Technical Specification improvement Program in August 1996). With one PACU
. inoperable, TS 3.7.14 required restoration of the PACU to aperable status within 7 days and, if this was not accomplished, movement of irradiated fuel assemblies in the fuel building had to be suspended, or the operable PACU had to be placed in operatio Irradiated fuel was mcved in the fuel building during the Cycle 9 refueling outages (November 30,1996, through April 1,1997, for Unit 2 and April 12 through July 21, 1997, fer Unit 3). The action required by the TS was not taken within the required time,
, because the licensee wes not aware of the deficienc The surveillance requirements associated with the PACUs required verification that the flow rate was within 10 percent of the design flow. The licensee determined that calibration of the PACU flow loops was questionable due to incomplete or suspect data
' om previous nonconforma=e reports. The cause of the error, which occurred before ork;inal plant startup, was not determined because of the passage of tim The licensee acknowledged two significant missed prior opportunities to have identified and corrected the problem, in 1993 and 1996, and noted that some previously identified f corrective actions had not been fully implemented. The licensee was still investigating these most recent personnel performance issue The fuel handling accident analysis in the Updated Final Safety Analysis Report (UFSAR) does not credit the PACUs for mitigation, although the PACUs are described in the UFSAR. The potential safety consequence of a PACU being inoperable (degraded but functional) was minima This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as AR 980502296 (362/99001-03).
Ill. Enoineerin_g E1- Conduct of Engineering E CREACUS Cable Amoacity - Units 2 and 3
, Insoection Scope (37751)
On February 1,1999, the licensee informed the inspectors that Nuclear Engineering Design had determined that a cable associated with Control Room Emergency Air Conditioning Unit E418 lac.ked adequate ampacity, under certain operating conditions,
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to satisfy its intended safety function. The inspectors reviewed the licensee's actions in response to this condition, which was documented in AR 990200051, and discussed the licensee'c motive for reviewing and revising existing ampacity calculations with Nuclear Engineering Design personne Observations and Findinas
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in 1996, the licensee performed a fire protection program self-assessment. The self-assessment evaluated the method derating cables routed through raceways covered with barriers that had been installed to provide adequate cable separation and fire protection. The self-assessment identified that the derating method may not always have been conservativ In 1998, the licensee completed the performance of site-specific raceway configuration testing for different types of barriers to establish appropriate ca'de derating fa : tor During this inspection, Nuclear Engineering Design was in the process of revising the cable-sizing calculations by using the relevant industry standards and the results of the 1998 site-specific testin On February 1,1999, the licensee discovered that the 480 volt cable from Transfer Switch DB0416 to Train A Control Room Emergency Air Conditioning Unit E418 may not have adequate ampacity under certain operating conditions to satisfy its intended safety function. AR 990200051 documented that the most limiting raceway for this cable had an evaluated allowable ampacity of 122.5 am.R and that the maximum circuit adjusted load current for the worst loac'ing condition vr ;66.8 amps. The cable involved was the only cable in the affected raceways, and tu.; raceways were covered with Cerabianket, a barrier used to provide for cable separatio The licensee declared the Train A CREACUS inoperable, which resulted in a delay in the Unit 2 core reload (Section 01.4). The nonconformance report assignment on AR 990200051 established measures to restore Unit E418 to operable. This included removal of the Cerablanket from the affected raceways and posting of an hourly fire watch. Following these actions, the Train A CREACUS was declared oper.tble. The long term corrective action was to protect the cable with an approved barrier that did not unacceptably degrade the cable's ampacit Th licensee was stillin the process of completing the cable-sizing calculation revisions at the end of the inspection perio This issue is unresolved pending a review of the licensee's reportability assessment (361; 362/99001-04). Conclusions The licensee's response to a 1996 fire protection self-assessment resulted in a thorough review of cable-sizing calculations based on testing of site-specific raceway configurations. The corrective actions for a cable ampacity design deficiency, identified by Nuclear Engineering Design during this process, were prompt and adequate.
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E2 Engineering Support of Facilities and Equipment E Foreian Object in Steam Generator 2E089 - Unit 2 Inspection Scoce (37551)
The inspectors reviewed the circumstances of the licensee's discovery of a foreign object in Steam Generator 2E08 Observations and Findinas During inspection of the secondary side of Steam Generator 2E089, the licensee found a FME cover from a steam generator moisture separator can that was resting in the blowdown lane on the tubesheet. The FME cover was approximately 8.5 inches in diameter and had a lip that was approximately 2 inches in depth. The cover was made of galvanized stainless stee The licensee performed an investigation and determined that the FME cover had been in the steam generator since the midcycle outage that had ended in February 199 During the midcycle outage, the licensee had designed and installed the FME covers on the cans to prevent foreign objects from falling through the cans once the moisture separators had been removed for maintenance purposes. Two instances occurred in which can covers had been inadvertently knocked off and had fallen down the annulus at the periphery of the tube bundle. In response the these problems, the licensee had
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conducted a stop-work briefing and a standdown with the contractor performing work in the steam generator. The licensee also installed a flexible hose to plug the periphery annulus, individually numbered the FME covers, and tied the covers together in groups of three, although these actions were not all taken at the same tim In reviewing the current discovery, the licensee found that the FME cover was numbered 214. A review of records revealed that Cover 214 had been identified as missing during the midcycle outage, but that an FME inspector had found Cover 21 This occurred after the covers were numbered but before the licensee had begun to tie the covers together. However, the licensee had numbered the covers for use in both steam generators identically and did not realize that the "found" Cover 214 was the cover for the other steam generator. The licensee was falsely convinced that the correct cover had been found Subsequent inspections of the steam generator for foreign materials during the midcycle outage did not identify the cove As a result of this discovery, he Nuclear Construction manager stated that the covers would be renumberud uniquely and that other material that was going to be used in the steam generator secondary side would also be un:quely numbered, rather than being identified only by a physical description of the item. The licensee also planned to
- . develop a section of the FME procedure that was specific to the steam generators and
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review the foreign object search and retrieval progra I l
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Site Technical Services performed an evaluation of the effects of the FME cover on the steam generator. The licensee determined that the FME cover was in excellent condition, with no evidence of nicks in the zine coating and no dents or other indications of impact or wear. Zinc or.ide and metallic zine were determined not to present chemistry problems of concern in the steam generator. The licensee did not identify any new fretting indications during inspection of the steam generator tubes. A small number of new dent indications were identified and evaluated; none appeared to be related to ,
the FME cover. The licensee concluded that no steam generator degradation was I evident as a result of the FME cove I 4 Conclusions The licensee's evaluation of the source and effects of a large foreign object (an FME cover for a moisture separator can) in Steam Generator 2E089 was thorough, and the planned corrective actions were adequat E2.2 Aluminum in Containment Normal Air Cooler Prefilters - Units 2 and 3 l Inspection Scope (37551)
On February 4,1999, the licensee informed the inspectors that an unknown amount of I undocumented aluminum was found on the prefilters for the containment normal air coolers in Unit 2 and that Unit 3 might also have some undocumented aluminum from the same source. The inspectors discussed the issue with licensee personnel, monitored the licensee's response and corrective actions, and reviewed AR 990200397, which documented the issu Observations and Findinas
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On February 4,1999, while replacing containment normal air cooler prefilters in Unit 2, l Maintenance personnel discovered that some of the new prefilters were bound with aluminum, while others (with the same material code) were bound with plasti Aluminum was known to be carefully controlled and not generally allowed in containment, because of its contribution to hydrogen production in postaccident i environment The licensee conducted an inspection of all the normal air cooler prefilters in Unit 2 and !
identified that 7 of 52 old prefilters and 19 of 48 new prefilters were bound with l aluminum. On February 6, the licensee made an at-power entry into the Unit 3 containment and determined that none of the prefilters in Unit 3 were bound with aluminum.
t- An operability assessment was performed for Unit 2. Because the old prefilters that had already been removed and replaced in Unit 2 had been destroyed, the licensee could not determine the actual number of prefilters with aluminum that had been in Unit 2 during Cycle 9 operation. The operability assessment was based on 26 prefilters being bound with aluminum and concluded that this was a 33 square foot increase in the surface area of aluminum over the licensee's previous bounding calculation. The
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licensee calculated that the 4.0 volume percent hydrogen limit would be reached in i 9.0 days instead of 9.1 days, the previously calculated time based on the previous )'
bounding value (500 square feet). The operability assessment concluded that ample time would be available to place the hydrogen recombiners in service before the )
hydrogen limit was exceeded and that the containment systems remained operabl l The licensee removed all the aluminum-bound profilters from the Unit 2 containment and, in evaluating the cause of the condition, identified two problems. For one purchase, the vendor had substituted parts but had left the packing slip indicating that ;
the correct nonatuminum parts were shipped. Another shipment was properly marked ;
but had not been properly serified by receipt inspection personnel. The licensee determined that the vendor no longer manufactued the nonaluminum bound prefilters, and the purchase order had allowed substitutions. Corrective actions were initiated for each of these problem Conclusions Maintenance and Station Technical responded aggressively to quantify undocumented aluminum found in the Unit 2 containment normal air cooler prefilters and to determine that Unit 3 was not affected. The licensee's investigation was thorough in identifying causes and corrective actions, and the operability assessment was adequate.
E8 Miscellaneous Engineering Issues (92903,92700)
E8.1 (Closed) LER 361/1986-036-00: line voltage regulators cause vital buses to be inoperabl In Frbruary 1998 the licensee determined that the acceptance criteria for the procedural setpoint for the line regulators was incorrect, resulting in vital buses being inoperable when supplied by the line regulators, due to line losses and regulator output tolerance TS 3.8.3.1, Action a. (the TS in effect prior to the August 1996 implementation of the Technical Specification improvement Program), required that, when an inverter (the normal power supply to the vital bus) becomes inoperable, the bus be powered from its Class 1E constant voltage source transformer within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The licensee identified three instances over a 2-day period in 1986 during which a Unit 2 vital bus had been aligned to a line regulator for longer than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, resulting in the TS requirement not having been satisfied. The duration of the three periods ranged from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 20 minutes to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> 39 minutes. (The same requirements are now contained in TS 3.8.7, which was the requirement mistakenly reported in the LER as having been violated.)
The Class 1E 120-volt ac system, as described in the UFSAR, is normally supplied through the inverters, which are considered as uninterruptible power supplies. The line regulators are connected by a manual bus transfer switch and are intended for maintenance and testing purposes onl l
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l Because the line regulators are not required to be operable while the inverters are in i service, and because of the 4-channel redundancy and the short duration of the configuration in which the deficient line regulators were in service, the inspectors ,
determined that the reported condition had no actual and little potential safety l consequenc The licensee determined appropriate acceptance criteria, revised the affected maintenance procedure, and adjusted the line regulator voltage setpoints to the correct value. Because the condition existed since the maintenance procedure had been initially prepared in about 1984, the licensee was unable to determine the cause of the erro This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as AR 980200847 (361/99001-05).
i E8.2 (Closed) Escalated Enforcement item 361/98005-02: inoperable emergency core cooling systems and containment spray systems. In a letter dated November 12,1998, the NRC staff exercised enforcement discretion for a Severity Level ill violation related to the inoperability of both trains of two safety systems in Unit 2, reported in LER 361/1998-00 E8.3 (Closed) LER 361/1998-009-00: condensate storage tank outside design basis due to procedural error. Supplement 1 of this LER was reviewed and closed in NRC Inspection Report 50-361; 362/98-1 E (Closed) LER 361/1996-012-01: condensate storage tank outside design basis. This LER was reviewed and closed in NRC Inspection Rt port 50-361; 362/98-14. Although Supplement 1 of the LER was reviewed in that in: acction, the supplement was inadvertently omitted from the documentatio IV. Plant Support R1 Radiological Protection and Chemistry Controls R As Low As Reasonably Achievable Practices - Unit 2 Inspection Scope (71750)
The inspectors toured work areas in the radiologically controlled area during the Unit 2 refueling outage and observed work practices and engineered features associated with radiological dose reduction.
l Observations and Findinas I
l The licensee inst;"ed specialized shielding on each of the individual pressurizer heater nozzles, substar.tlally reducing the dose rate in the area while allowing access for work immediately under the pressurizer. The shields were designed by a licensee Health
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Physics engineer and consisted of specially fabricated polyvinylchloride canisters and lead. The shields were evaluated for the seismic loading they added to the pressurizer heater nozzles. Previously, only lead blanket shielding had been used around the bottom of the pressurizer to reduce general area dose rates. Use of the new shielding reduced the head-level dose rates under the pressucizer by a factor of 4 to 6, based on surveys performed by the licensee on January 10,1999. The licensee predicted that the new shielding would result in a 10 person-rem dose reduction during the current Unit 2 Cycle 10 refueling outag The inspectors observed use of the Comprehensive Application for Reduced Exposure System (CARES), an integrated system of cameras, teledosimetry, and cellular telephones that allows detailed remote monitoring, and limited inspection, of work in high radiation areas from outside the radiologically controlled area. Activities observed included monitoring of the eddy current testing of Steam Generators 2E088 and 2E08 Health Physics technicians were not normally on the steam generator platforms, but were available outside the bioshield to respond as requested by the technicians monitoring the CARES station. The use of the CARES was effective in achieving an overall dose reduction, in that Health Physics technicians did not have to routinely j remain in high radiation areas and the workers in the high radiation areas were being j effectively monitored and coached to reduce their exposures. The licensee estimated j that use of the CARES resulted in a 7.4 person-rem and 12.7 person-rem dose reduction during the Units 2 and 3 Cycle 9 refueling outages, respectivel Approximately 11.7 person-rem were avoided during the two Cycle 9 midcycle outage The actual cumulative dose for the current Unit 2 Cycle 10 refueling outage was significantly (30 person-rem) less than the outage goal, as of February 18, although the licensee had not yet estimated the benefit resulting from use of the CARE Conclusions Health Dhysics demonstrated continued effectiveness in radiological dose reduction through implementation of engineered features, including specially designed shielding for pressurizer heater nozzles and expanded use of the CARE S1 Conduct of Security and Sareguards Activities S1.1 yital Area Breach - Unit 2 Inspection Scoce (71750)
The inspectors observed openings in a vital area boundary. The inspectors informed the licensee of the concern and monitored the licensee's respons . Observations and Findinas On January 23,1999, the inspectors identified openings in a vital area boundary. The i inspectors informed the on-shift outage manager of the observation. The outage manager informed Security of the observation, and a security officer wa s dispatched to the area. The inspectors met the security officer and a Maintenance supervisor at the
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area. The security officer assessed the opening and determined that it was a vital area breach. Appropriate compensatory measures were establishe An NRC security specialist will evaluate the application of the Physical Security Plan and the application of the implementing procedure to these circumstances. This issue will '
be tracked as an unresolved item (361/99001-06). Conclusions An unresolved item was identified to review the applicability of both tha Physical Security .
Plan and the implementing procedure requirements to openings in a vital area barrie F2 Status of Fire Protection Facilities and Equipment F2.1 Control of Doors - Units 2 and 3 (71750)
On January 13,1999, the inspectors observed a contract Health Physics technician's response to an opened door. The technician questioned why the unposted door was blocked-open between the radwaste building and the Unit 3 fuel handling building on the 70 foot elevation. The technician discovered that personnel had blocked the door open to use as a passageway for a cart, after filling the cart with protective clothing. The personnel filling the cart had line-of-sight with the door, but did not need to go through the door for several minutes. The technician applied conservative logic and unblocked and clored the door. The inspectors concluded that the Health Physics technician displayed a questioning attitude towards barrier protectio V. Manaaement Meetinas X1 Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the exit meeting on February 24,1999. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information wcs identifie !
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ATTACHMENT SUPPLEMENTAL INFORMATION i
PARTIAL LIST OF PERSONS CONTACTED Licensee D. Brieg, Manager, Station Technical )
J. Fee, Manager, Maintenance D. Herbst, Manager, Site Quality Assurance
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J. Hirsch, Manager, Chemistry R. Krieger, Vice President, Nuclear Generation
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J. Madigan, Manager, Health Physics D. Nunn, Vice President, Engineering and Techn: cal Services A. Scherer, Manager, Nuclear Regu:atory Affairs T. Vogt, Plant Superintendent, Units 2 and 3 R. Waldo, Manager, Operations INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee's Process to identify, Resolve, and Prevent Problems IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92700: On Site LER Review IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED AND CLOSED t
Opened 361; 362/99001-04 URI review of reportablitiy assessment regarding CREACUS operability (Section E1.1).
361/99001-06 URI evaluation of Physical Security Plan and implementing procedures regarding openings in a vital area barrier (Section S1.1),
Opened and Closed 361;362/99001-01 NCV TS 3.7.14 charcoal filter surveillance testing not current (Section M8.1).
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2-361;362/99001-02 NCV TS 3.7.11 charcoal filter surveillance testing not current (Section M8.1).
362/99001-03 NCV PACU inoperable because of flow calibration error (Section M8.2).
361/99001 05 NCV vital bus aligned to inoperable line regulator for longer than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (Section E8.1).
Gosed 361/1997-013-00 LER charcoal filter surveillance testing not current (Section M8.1)
361/1998-010-00- LER PACU inoperable due to flow calibration error (Section M8.2)
361/1998-010-01 361/1986-036-00 LER line voltage regulators cause vital buses to be inoperable (Section E8.1).
361/98005-02 eel inoperable emergency core cooling systems and containment spray systems (Section E8.2).
! 361/1998-009-00 LE condensate storage tank outside design basis due to procedural l error (Section E8.3).-
361/1996-012-01 LER condensate storage tank outside design basis (Section E8.4).
LIST OF ACRONYMS USED AR action request CARES comprehensive application for reduced exposure system-CCW component cooling water CFR Code of Federal Regulations COLSS core operating limits supervisory system CREACUS control room emergency air cleanup system l DLMS diverse level monitoring system FME foreign material exclusion HPSI high pressure safety injection LER licensee event report NCV noncited violation NRC Nuclear Regulatory Commission PACU postaccident cleanup unit
~RCS reactor coolant system SWC saltwater cooling TS- Technical Specification UFSAR Updated Final Safety Analysis Report 4 VCT volume control tank