IR 05000424/1993027
| ML20059G285 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 01/11/1994 |
| From: | Balmain P, Brian Bonser, Skinner P, Starkey R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059G271 | List: |
| References | |
| 50-424-93-27, 50-425-93-27, NUDOCS 9401240086 | |
| Download: ML20059G285 (14) | |
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UNITED STATES
/p areg.g NUCLEAR REGULATORY COMMISSION y
REGION H
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E 101 MARIETTA STREET, N.W., SUITE 2000
'y ATLANTA, GEORGIA 30323-0199
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Report Nos.:
50-424/93-27 and 50-425/93-27 Licensee: Georgia Power Company P. O. Box 1295 Birmingham, AL 35201
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Docket Nos.:
50-424 and 50-425 License Nos.: NPF-68 and NPF-81 Facility Name: Vogtle 1 and 2
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Inspection Conducted: November 21, 1993 - December 18, 1993 Inspector:
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l /O W p B. Y.'Bonser,MpMor Resident Inspector
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I. IO W v. D'"St4X, Resident Inspector Date Signed e/
/ /O 9Y P.' A. Balfnai ident Inspector Date Signed Approved by:
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P./ Skinner, Chief Date Signed Reactor Projects Section 3B Division of Reactor Projects i
SUMMARY
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Scope:
This routine, inspection entailed inspection in the following
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areas: plant operations, surveillance, maintenance, Engineered Safety System walkdown, evaluation of licensee self-assessment and
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follow-up of open items.
- Results:
One non-cited violation (NCV) was identified.
The NCV involved a failure to initial and date applicable line entries on a Unit Operating Procedure checklist for systems not designated for lineup following the most recent. Unit I refueling i
outage.
The initials would have indicated a current system status
was verified (paragraph 2d).
A review of system alignment procedures and-alignment documentation identified several documentation and administrative problems. The problems identified were not safety significant.
There were no systems'found out of alignment and the licensee 9401240086 940111 PDR ADOCK 05000424-
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I maintains several other programs to_ ensure configuration control (paragraph 2d).
Overspeed trips of the Unit 2 Turbine Driven Auxiliary Feedwater (TDAFW) Pump during surveillance testing were reviewed. The inspectors concluded that the licensee had adequately resolved the problems identified with TDAFW pump and in the process had uncovered some errors related to troubleshooting and electrical
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overspeed device calibration (paragraph 4b).
The inspector reviewed the licensee's resolution of an unpinned residual heat system seismic strut.
The licensee conservatively declared the system inoperable upon identification of this degraded condition. Restoration of the strut was prompt and support engineering promptly evaluated the condition and determined its significance. The licensee response to this issue
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was adequate, timely and conservative, and focussed on the safety of the plant (paragraph 6).
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T REPORT DETAILS 1.
Persons Contacted
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Licensee Employees
- J. Beasley, General Manager Nuclear Plant
- P. Burwinkel, Plant Engineering Supervisor i
W. Burmeister, Manager Engineering Support j
- S. Chesnut, Manager Engineering Technical Support
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- C. Christiansen, SAER Supervisor
- R. Dorman, Manager Training.and Emergency Preparedness l
- G. Frederick, Manager Maintenance
- W. Gabbard, Nuclear Specialist, Technical Support
- J. Gasser, Unit Superintendent
- M. Griffis, Manager Plant Modifications K. Holmes, Manager Operations D. Huyck, Nuclear Security Manager W. Kitchens, Assistant General Manager Plant Support
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R. LeGrand, Manager Health Physics and Chemistry G. McCarley, ISEG Supervisor M. Sheibani, Nuclear Safety and Compliance Supervisor C. Stinespring, Manager Administration
- J. Swartzwelder, Manager Outage and Planning j
- C. Tynan, Procedures Supervisor J. Williams, Outage and Planning Supervisor Other licensee employees contacted included technicians, supervisors, engineers, operators, maintenance personnel, quality control inspectors, and office personnel.
Oglethorpe Power Company Representative T. Mozingo NRC Resident Inspectors
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- B. Bonser
- D. Starkey
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- P. Balmain i
- Attended Exit Interview An alphabetical list of abbreviations is located in the last paragraph'
of the inspection report.
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2.
Plant Operations - (71707)
a.
General The inspection staff reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, TSs, and administrative controls.
Control logs, shift supervisors' logs, shift relief records, LC0 status logs, night orders, standing orders, and clearance logs were routinely reviewed. Discussions were conducted with plant operations, maintenance, chemistry, health physics, engineering support and technical support personnel. Daily plant status meetings were routinely attended.
Activities within the CR were monitored during shifts and shift changes. Actions observed were conducted as required by the licensee's procedures. The complement of licensed personnel on each shift met or exceeded the minimum required by TS. Direct observations were conducted of CR panels, instrumentation and recorder traces important to safety. Operating parameters were
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verified to be within TS limits. The inspectors also reviewed DCs.
to determine whether the licensee was appropriately documenting problems and implementing corrective actions.
The inspectors observed that Operations management has undertaken an initiative to increase the effectiveness of CR operations.
This effort includes a reduction of lit or disabled CR annunciators, a reduction of inoperable or degraded CR instrumentation and chart recorders, and a reduction of Caution
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tags on the control board.
The inspectors. agreed that a reduction
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of these conditions can only serve to enhance CR operations and reduce operator distractions. The inspectors will continue to monitor progress in this area.
Plant tours were taken during the reporting period on a routine
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basis. They included, but were not limited to the turbine i
building, the auxiliary building, electrical equipment rooms, cable spreading rooms, NSCW towers, DG buildings, AFW buildings, and the low voltage switchyard.
During plant tours, housekeeping, security, equipment status and radiation. control practices were observed.
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The inspectors verified that the licensee's health physics policies / procedures were followed. This included observation of i
HP practices and review of area surveys, radiation work permits, postings, and instrument calibration.
The inspectors verified that the security organization was properly manned and security personnel were capable of performing
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their assigned functions.
Inspectors observed that persons and
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packages were checked prior to entry into the PA; vehicles were properly authorized, searched, and escorted within the PA; persons within the PA displayed photo identification badges; and personnel in. vital areas were authorized.
b.
Unit 1 Summary The unit began the period operating at 100% power and operated at
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full power throughout the inspection period, c.
Unit 2 Summary The unit began the inspection period at 100% power. On December 3, power was reduced to 20% to permit performance of steam generator hideout return chemistry testing and to make repairs to Heater Drain Pump B.
Testing and maintenance activities were completed on December 4 and ascension to 100%
power was started. The unit reached 100% power on December 6 and
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remained there throughout the remainder of the inspection period.
d.
Review of System Alignment Procedures During this inspection period the inspector reviewed U0Ps and system alignment procedures to determine if system alignments were performed as required following recent refueling outages.
Lineup program requirements are contained in procedure 10000-C, Conduct of Operations, and in the UOPs.
Program requirements in procedure 10000-C establish administrative requirements for performing system lineups, maintaining a system status file and the.
performance of periodic lineups at least every 30 months. The UOPs direct the performance of selected system lineups following a refueling outage.
Requirements for performing system lineups in the UOPs are provided in a checklist attached to the U0P.
Systems that must have an alignment are designated on the checklist by the Manager of Operations or his designee. Systems-are aligned using specific system alignment procedures.
The inspector found some of the system alignment procedures requirements to be unclear. 00P requirements did not clearly state the level of completion desired or give acceptance criteria, and appeared to conflict with procedure 10000-C requirements.
Guidance for the timeliness of lineup completion was not given in procedure 10000-C or the UOPs.
The inspector reviewed completed copies of U0P 12001-C, Unit Heat Up To Hot Shutdown, for refueling outages 1R4,1R3, 2R3 and 2R2;
and reviewed a sample of the completed system 1ineup~ procedures performed during 1R4. The inspector identified several systems in U0P 12001-C, Checklist' 1, System Requirements for Unit Startup, completed for 1R4, that were not designated for lineup and were
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not signed off as being verified. Guidelines in Checklist I require that systems not designated for alignment must be verified
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by ensuring that a current alignment is on file in the system status file. A sample of safety related system lineups were reviewed by the inspector and found to be current.
The inspector also identified several systems where partial lineup procedures were performed during outage IR4 and were not completed promptly following 1R4. Normal practice has been to perform partial lineups to support an evolution during an outage and complete the remainder of the lineup-shortly after the outage.
The inspector did not identify any discrepancies on the completed procedure 12001-C checklists reviewed for-the other refueling outages. The inspector also verified with the licensee that the
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lineups performed during 1R4 were reviewed by_the licensee to assure they would support the desired evolutions and the
exceptions left did not warrant additional action.
The inspector found that the signature continuation sheets were
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not always used when the system lineup procedure signature / comment page was full. Operations personnel completing the system lineup-procedures used the comments and resolution section as signature continuation sheets.
Comments and exceptions were documented in the body of the field copies of the alignment procedures, which were not retained.
The inspector considered the issues described above as documentation and administrative problems and of no safety significance.
There were no systems found out-of-alignment and the licensee maintains several other programs to ensure configuration control. These include the clearance and tagging program, safety related locked valve manipulation controls, system operating procedures, operator rounds, and surveillance procedures which are performed prior to mode changes and periodically as required by TS.
In addition, the inspectors have observed no
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significant events following recent refueling outages which indicate a configuration control problem.
However, failure to initial and date the applicable line entries for nondesignated systems on Checklist 1, System Requirements for Unit Startup, of procedure 12001-C, to indicate a current system status was verified, is a violation of U0P 12001-C requirements. This NRC identified violation is not being cited because criteria specified in section VII.B of the enforcement-policy were satisfied. Th i s --
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item is identified as NCV 50-424/93-27-01, Failure to Document Verification of Alignment Status Prior to Unit 1 Startup. The inspector found that these problems were isolated to IR4.
The licensee has acknowledged the problems identified and committed to review and revise their guidance for performing
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system lineups.
One violation was identifie.-
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Surveillance Observation (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, data collection, independent verification where required,. handling of deficiencies noted, and review of completed work.
The tests witnessed, in whole or in part, were inspected.to determine that approved procedures were available, equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable, and systems restoration was completed.
SVRVEILLANCE NO.
TITLE 24060-2 AFW Pump Turbine Speed Indication and Control 2S-15109 Channel Calibration.
14810-2 TDAFW Pump and Check Valve IST.
14701-2 Reactor Trip Breakers UV and Shunt Trip Test 28911-102,104 Weekly Battery Inspection The inspectors did not identify any problems or concerns during the observation of these surveillance activities.
No violations or deviations were identified.
4.
Maintenance Observation (62703)
a.
General Maintenance activities were observed and/or reviewed during the reporting period to verify that work was conducted in accordance with approved procedures, TSs, and applicable industry codes and standards. Activities, procedures, and work orders were examined to verify proper authorization to begin work, provisions for fire, cleanliness, and exposure control, proper return of equipment to service, and that limiting conditions for operation were met.
The inspectors witnessed or reviewed the following maintenance activities:
MWO NOS, WORK DESCRIPTIO3 29303900 TDAFW Trips On Mechanical Overspeed 19302946 Replace Fadwater RTDs 15200-15203
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29302246 Perform PM On TDAFW Trip Linkage 19303080 Valve 1HV7126 Exceeded IST Action Time The inspectors did not identify any problems or concerns during the observation of these maintenance activities, b.
Overspeed Trip of Unit 2 TDAFW Pump On November 29, the Unit 2 TDAFW turbine tripped on mechanical overspeed during routine performance of surveillance procedure 14810-2, TDAFW Pump and Check Valve IST.
Shortly before the surveillance test, maintenance personnel had performed a routine PM task (MWO 29302246) that included cleaning, lubrication, and verification of free movement of trip linkages and governor valve linkages. Operations supervision believing that the overspeed trip was related to the linkage PM attempted a second TDAFW pump start after resetting the mechanical overspeed trip mechanism. The turbine again tripped on mechanical overspeed.
Neither of the two mechanical overspeed trips was preceded by an electrical overspeed trip which should have occurred first. The setpoint for an electrical overspeed trip is 110% (4620 rpm) of the turbine normal speed of 4200 rpm, while. the mechanical overspeed trip setpoint is 115% (4830 rpm) of 4200 rpm.
Troubleshooting identified the cause of both overspeed trips as a failed EG-M module in the governor circuitry and the module was replaced.
This module provides speed input to the turbine governor. The licensee also determined that the electrical overspeed trip setpoint was set too high, at approximately 5042 rpm, explaining why the mechanical overspeed trip occurred first.
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The electrical overspeed setpoint was subsequently recalibrated to its correct value.
Following recalibration of the electrical trip and EG-M module
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replacement, a third turbine start was attempted. The turbine tripped, but this trip resuli.ed from an electrical overspeed trip signal. The licensee determined that this trip was caused by binding of the governor valve linkage which caused the governor valve to remain in the full open position. The governor' valve linkage was realigned and the piston servo on the governor. valve-linkage was replaced as a precautionary measure.- On November 30, the TDAFW successfully passed its surveillance test and the LCO was exited.
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The inspectors were concerned with the multiple failures identified by this surveillance test and that a problem with the electrical overspeed device occurred (see NRC IR 50-424,425/93-23),
The inspectors reviewed each of the problems that occurred.
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The licensee concluded that an inadequate precalibration warmup of the electrical overspeed device following the recent Unit 2 outage caused the electrical trip setpoint to drift high. The inspector reviewed the data from the post-outage calibration and the "as found" data after the November 29 trip, and determined that the data supports this conclusion of instrument drift. The inspector i
also reviewed procedure 24060-2, Auxiliary Feedwater Pump Turbine
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Speed Indication And Control 2S-15109 Channel Calibration, and the turbine vendor manual and noted that no limitations were stated in either document regarding appropriate warm-up times prior to calibration for electrical overspeed instrumentation.
Discussions with the system engineer and the I&C Superintendent revealed that one to one and a half hours are necessary as a minimum warm-up
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period prior to calibration of this type of instrumentation.
MWO records related to the electrical overspeed instrumentation calibration following the Unit 2 outage do not indicate the length of the warm-up period used prior to calibration )f the electrical overspeed instrumentation.
The licensee also determined, during the root cause evaluation of the TDAFW pump trips, that the EG-M module did not fail during this event.
Bench testing of the suspected failed module verified that it was working properly. Since the failure indication which the I&C technicians observed during their troubleshooting efforts-on November 29 could be recreated during bench testing of the EG-M module, the licensee concluded that the technicians had apparently used the test equipment incorrectly. The licensee concluded and-the inspectors agreed that the cause of the overspeed events was binding of the governor valve trip linkage which was probably related to the PM that was performed prior to the TDAFW pump surveillance.
The inspectors reviewed the MWO related to the PM and did not identify any discrepancies.
The inspectors witnessed portions of the maintenance activities related to repair of the Unit 2 TDAFW pump as well as the performance of surveillance tests. The inspectors concluded that, although the TDAFW was returned to service approximately 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> into the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO, the recovery process appeared to have been unnecessarily delayed due to the improper use of test equipment by technicians while troub1 shooting the EG-M module. The licensee subsequently resolved the troubleshooting error and the error related to the electrical overspeed calibration.
The inspectors concluded that these maintenance related errors were isolated events and do not reflect a breakdown in the maintenance program.
The inspectors also concluded that it was unwise to run the surveillance the second time on November 29, before examining the causes of the first overspeed trip and consulting with management.
The inspectors discussed the. issues associated with.this event with plant management and _will continue to monitor activities related to the TDAFW pump.
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c.
Unit 1 Diesel Generator 1B Exhaust Leak The inspectors reviewed the maintenance history of an exhaust leak on the IB DG. A review of this issue with the DG system engineer and maintenance personnel identified that a minor exhaust leak was discovered on the IB DG during refueling outage IR4.
The leak has discolored the exterior casing of the DG turbo charger with soot.
The inspector performed a walkdown of the IB DG and observed evidence of the leak. The inspectors review of this issue did not identify any impact on engine performance or its ability to function as an onsite emergency power source.
The inspectors were also concerned that the exhaust leak could impair local operation of the IB DG. Two plant equipment operators present in the IB DG room on December 1 during a surveillance test of the DG were interviewed by the inspector.
Neither PE0 identified any significant exhaust leakage. The inspectors also have been present in the room while the IB DG is running and have not detected exhaust leakage in the room.
In addition, during DG operation the diesel building HVAC system is running which is constantly moving a large volume of air through the building.
The licensee determined that the leak is located under the jacket water shroud at the top of the engine. The licensee suspected that a flexible connection under this shroud is the source of the leak.
Since the leak did not impact operation of the DG, the licensee postponed repair because extensive disassembly of the jacket water shroud would be required to access the leaking coupling. The licensee intends to repair the leak during the ten year DG checkout, or earlier if.it worsens. The current revision of procedure 27578-C, Ten Year Diesel Generator Checkout, section 4.21, requires that the exhaust flex connection be visually inspected for evidence of cuts, holes, and dents.
Based on this review, the inspector concluded that the existing leak on the IB DG is not significant. The inspector also determined that the icensee is aware of the condition and will repair it during a future periodic DG checkout.
d.
Diesel Generator Air Flow Directional Vanes The inspectors learned that an inspection of a TDI DG at an other
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site had found that the generator air flow directional vanes were not securely attached and had the potential for coming loose and causing damage to the generator.
The air flow' directional vanes are stationary vanes tack-welded to the inside of the generator-shroud on the wire covered opening.
The vanes help direct air as the generator rotor rotates.
The inspectors brought this concern to the licensee's attention and found that a similar problem had been identified during the
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performance of an 18-month surveillance procedure on DG 2A in September 1990. Maintenance had found the tack welds holding one directional air flow vane on the 2A generator cover broken. The vane had fallen off while removing the generator cover. As a result of this finding the licensee wrote MW0s to visually inspect all the vanes on the other DGs. The inspector reviewed the MW0s and found the other inspections were completed and no defects were identified. The inspector also visually examined a sample of the air flow vanes and found that they all appeared secure. The inspector had no further ouestions.
No violations or deviations were identified.
5.
ESF System Walkdown (71710)
During this inspection period the inspector performed an ESF walkdown of the Unit 1 Control Room Emergency Filtration System. The walkdown included verification of correct valve and damper position indications in the control room and inspection of the material condition of accessible components in the plant. The inspector reviewed appropriate sections of the TSs, FSAR, system alignment procedure and P& ids to verify proper system alignment. No discrepancies were observed during the walkdown.
The inspector noted, for those items inspected, that breaker cubicle component description labels exactly matched the written description in the system line-up Procedure 11301-1, CBCR Normal HVAC
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and Emergency Filtration System Alignment.
This is an improvement over previous ESF system walkdowns which have routinely identified labelling
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inconsistencies.
Based on this review the inspector did not have any operability concerns with the system.
No violations or deviations were identified.
6.
Licensee Resolution Of Unpinned Residual Heat System Strut (40500)
On November 25, 1993 the licensee identified an unpinned seismic strut in the Unit 2 B-train RHR pump room on the pump discharge line. The strut was found unpinned from its wall mounted clevis and resting on the clevis pin, which was pinned through the clevis. The licensee-1 immediately entered the RHR system 72-hour LC0 Action Statement until operability of the RHR system could be established. The inspector reviewed this issue to evaluate the licensee's actions for resolution of degraded and non-conforming conditions.
The licensee promptly secured the strut in place.
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l engineering support also promptly evaluated the effect of the unpinned strut and found the support was installed to dampen dynamic loads from a seismic event and not relied on to provide support for other loads.
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Engineering also found, using dynamic seismic loading calculations, the system would not have been degraded in a seismic event.
Based on these engineering findings it was determined that RHR system operability was not affected and the system would have performed its intended safety function.
The licensee exited the 72-hour LCO Action Statement about
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The licensee is also performing a root cause evaluation to determine how the strut was unpinned.
The inspector found that the licensee was conservative in declaring the RHR B-train inoperable until an engineering evaluation supporting operability was complete. Restoration of the strut was prompt and verified to be adequate by onsite engineering.
Support engineering promptly evaluated the condition and determined its significance.
Action to identify the root cause is still in progress. The inspector concluded that the licensee's response to this degraded condition was adequate, timely and conservative, and focussed on safety of the plant.
No violations or deviations were identified.
7.
Follow-up (90712) (92700)
The Licensee Event Reports listed below were reviewed to determine if the information provided met NRC requirements.
The determination included:
adequacy of description, verification of TS compliance and regulatory requirements, corrective action taken, existence of potential generic problems, reporting requirements satisfied, and relative safety
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significance of each event.
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(Closed) LER 50-425/93-001, Cold Overpressurization Protection Setpoints Found To Be Outside Of Technical Specifications
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This LER addressed a finding by the licensee that identified that the low temperature lift settings of the Unit 2 PORVs were incorrect, and that these values, on several occasions, had been relied on to meet TS requirements for the COPS. The licensee's analysis determined that although the setpoints were nonconservative this condition would not have caused a' challenge to the integrity of the reactor vessel had a cold overpresswization event occurred. The inspectors agreed with the licensee's conclusions.
The licensee completed the proper scaling calculations and revised two procedures to reflect the corrected setpoints. The inspector reviewed the revised scaling calculations with Engineering, and verified that the data sheets were revised in procedures 24518-2, Reactor Coolant Pressure (Wide Range) Protection II 2P-403 Analog Channel Operational Test and Channel Calibration, and 24519-2, Reactor Coolant Pressure (Wide Range) Protection I 2P-405 Analog Channel Operational Test and Channel Calibration.
The inspector also reviewed the MWO performed to recalibrated the pressure instruments. The licensee's review of the precautions, limitations and setpoints document identified no similar conditions.
Based on this review of the licensee's actions, this LER is closed.
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(Closed) LER 50-424/93-004, Engineered Safety Feature Actuation System Sequence Operation Is Initiated During Testing This LER addressed an ESF actuation caused by a design flaw in a circuit card in the ESFAS sequencer. The sequencer flaw and the ESF actuation were discussed in NRC Inspection Report 50-424, l
425/93-07. This sequencer flaw would not have affected sequencer I
operation during normal use.
The licensee promptly modified the circuit cards in both Unit 1 sequencers and during the recent Unit 2 refueling outage (October 1993) replaced the flawed cards with modified cards.
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inspector reviewed the MWO's to verify the work was completed.
Based on this review of the licensee's actions this LER is closed.
No violations or deviations were identified.
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Exit Meeting The inspection scope and findings were summarized on December 21, 1993, with those persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection
findings listed below.
No dissenting comments were received from the
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licensee. The licensee did not identify as proprietary any of the
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material provided to or reviewed by the inspectors during the inspection.
Item No.
Description and Reference
NCV 424/93-27-01 Failure to Document Verification of Alignment Status Prior to Unit 1 Startup 9.
Abbreviations AFW
- Auxiliary feedwater System CBCR
- Control Building Control Room CFR
- Code of Federal Regulations CR
- Control Room DC
- Deficiency Card DG
- Diesel Generator ESF
- Engineered Safety Feature ESFAS
- Engineered Safety Features Actuation System FSAR
- Final Safety Analysis Report HP
- Health Physics HVAC
- Heating, Ventilating and. Air Conditioning I&C
- Instrumentation and Controls IR
- Inspection Report ISEG
- Independent Safety Engineering Group IST
- Inservice Test
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- Limiting Condition for Operation LER
- Licensee Event Report MWO
- Maintenance Work Order NCV
- Non-Cited Violation NPF
- Nuclear Power-Facility NRC
- Nuclear Regulatory Commission NSCW
- Nuclear Service Cooling Water System PA
- Protected Area PE0
- Plant Equipment Operator PM
- Preventive Maintenance PORV
- Power-0perated Relief Valve RHR
- Residual Heat Removal System rpm
- Rotations Per Minute RTD
- Resistance Temperature Detector
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SAER
- Safety Audit And Engineering Review TDAFW
- Turbine Driven Auxiliary Feedwater TDI
- Transamerica Delaval Incorporated TS
- Technical Specifications UOP
- Unit Operating Procedure IR3
- Unit 1 Third Refueling Outage IR4
- Unit 1 Fourth Refueling Outage 2R2
- Unit 2 Second Refueling Outage 2R3
- Unit 2 Third Refueling Outage
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