IR 05000244/1999001
| ML17265A609 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 03/23/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17265A608 | List: |
| References | |
| 50-244-99-01, 50-244-99-1, NUDOCS 9904010246 | |
| Download: ML17265A609 (24) | |
Text
U.S. NUCLEAR REGULATORYCOMMISSION
REGION I
License No.
DPR-18 Report No.
E 50-244/99-01 Docket No.
50-244 Licensee:
Facility Name:
Location:
Inspection Period:
Inspectors:
Rochester Gas and Electric Corporation (RG&E)
R. E. Ginna Nuclear Power Plant 1503 Lake Road Ontario, New York 14519 January 11, 1999 through February 21, 1999 P. D. Drysdale, Senior Resident Inspector C. C. Osterholtz, Resident Inspector Approved by:
G. S. Barber, Acting Chief Projects Branch
Division of Reactor Projects 9904010246 990323 PDR ADQCK 05000244
EXECUTIVESUMMARY R. E. Ginna Nuclear Power Plant NRC Inspection Report 50-244/99-01 This inspection included aspects of licensee operations, engineering, and maintenance.
The report covers a 6-week period of resident inspection.
~Oerations Operator performance during planned offsite electrical distribution system reconfigurations and normal down-power operations throughout the inspection period was good.
Several operational events occurred due, in part, to ineffective coordination'and communication between operations and other organizations which were previously unidentified, and therefore not corrected, and contributed to a reactor coolant system dilution event.
Additionally, the event investigation of the dilution event did not meet administrative requirements for timeliness, thoroughness, and for sequestering investigation personnel which led to inaccuracies in the investigation.
However, the licensee implemented corrective actions to address these deficiencies.
Receipt inspection of new fuel was thorough and well controlled.
No notable discrepancies were noted on any of the fuel assemblies or in the licensee's documentation.
Maintenance Controlled procedures were used at job sites. The procedures were up to date and were properly used by technicians involved in maintenance and surveillance work. The inspectors observed good personnel and plant safety practices.
Equipment tested met the acceptance criteria specified for operability.
The licensee was effective in reducing maintenance backlog items due, in part, to good management oversight.
Improvements in planning and scheduling, such as the incorporation of a "Fix it Now" team and the utilization of a dedicated work control center to prioritize and reduce remaining backlog items, were good initiatives.
The cable replacement for offsite power circuit 751 was successfully performed in a timely manner.
However, the licensee's analysis to determine the effect on the performance of safety functions during this activity was deficient in that no overall change in core damage frequency was identified.
The licensee effectively identified a deficiency in the synchronization selector switch for the A-emergency diesel generator.
Sending the replaced switch to a materials laboratory for analysis was a good initiative.
Individuals on the maintenance rule expert panel asked probing questions and demonstrated a
good understanding of the maintenance rule. However, no regular schedule existed for expert panel meetings, which resulted in a backlog of maintenance rule items for revie Executive Summary (cont'd)
Plant scaffolds appeared to be well designed and constructed in accordance with procedural requirements.
However, some confusion among the maintenance staff appeared to exist regarding the need for seismic scaffolding in areas of the turbine building near high energy piping.
~En ineerin The licensee's plan to remove 21 of the current 22 temporary modifications was a good initiativ TABLEOF CONTENTS EXECUTIVE SUMMARY TABLEOF CONTENTS IV I. Operations
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Conduct of Operations
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01.1 General Comments
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Operational Status of Facilities and Equipment
02.1 Summary of Plant Status..
Quality Assurance in Operations..
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~ 2 07.1 (Closed) Inspection Follow-up Item 50-244/98-03-01: Power Reduction Due to Lack of Calorimetric Correction Factor;...
(Closed) Inspection Follow-up Item 50-244/98-1 3-01: Inadvertent Dilution of the Reactor Coolant System When Placing a Mixed-Bed Demineralizer in Service;
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~ 2 (Closed) Non-Cited Violation 50-244/99-01-01: Ineffective Corrective Actions Led to an Inadvertent Dilution of the Reactor Coolant System When Placing a Mixed Bed Demineralizer in Service
07.2 Receipt Inspection of New Fuel.....
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Miscellaneous Operations Issues
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~ 4 08.1 (Closed) VIO 50-244/98-02-01: Failure To Monitor Control Room Panels and Attend to Alarms..
08.2 (Update) LER 1998-003, Revision 1: Radon Buildup During Temperature Inversion Results in Actuations of Control Room Emergency AirTreatment System
II. Maintenance M1 Conduct of Maintenance
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M1.1 General Maintenance Activities M1.2 General Surveillance Activities M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Maintenance Backlog
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M2.2 Cable Replacement for Offsite Power Circuit 751 M2.3 Safeguards Bus 14 Supply Breaker from the A-Emergency Diesel Generator Failure to Close During Post-Maintenance Testing...
M7 Quality Assurance in Maintenance Activities M7.1 Maintenance Rule Expert Panel Meeting
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.12 E2 Engineering Support of Facilities and Equipment...............
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C Table of Contents (cont'd)
V. Management Meetings X1 Exit Meeting Summary..
ATI'ACHMENTS Attachment 1 - Partial List of Persons Contacted
- Inspection Procedures Used
- Items Opened, Closed, and Discussed
- List of Acronyms Used
I Re ort Details
Conduct of Operations'1.1 General Comments Ins ection Procedure IP 71707 The inspectors periodically observed plant operations to verify that the facilitywas operated safely and in accordance with licensee procedures and regulatory requirements.
These reviews included tours of the accessible areas of the facility. The inspectors also conducted periodic verifications of engineered safeguard feature (ESF)
system operability, verifications of proper control room and shift staffing, verification that the plant was operated in conformance with the improved technical specifications (ITS)
and appropriate action statements were implemented for out-of-service equipment, and verification that logs and records accurately identified equipment status or deficiencies.
Operational Status of Facilities and Equipment 02.1 Summa of Plant Status The inspectors periodically observed operator performance and reviewed operations status throughout the inspection period.
b.
Observations and Findin s The plant was'at approximately 100% power at the beginning of the inspection period.
On February 2, 1999, a minimum boron concentration of 2% was obtained in the reactor coolant system, and "coastdown" operations commenced in preparation for the refueling outage which started on March 1, 1999.
On February 8, 1999, control room operators established a 100%/0% offsite power lineup on circuit 767 for an underground cable replacement on circuit 751 (see section M2.2). The replacement was completed and a 50%/50% offsite power lineup on both offsite circuits was restored on February 11, 1999. The plant continued in a coastdown operation and was at approximately 76% power at the end of the inspection period.
C.
Conclusions Operator performance during planned offsite electrical distribution system reconfigurations and normal down-power operations throughout the inspection'period was good.
Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic Quality Assurance in Operations
07.1 Closed Ins ection Follow-u Item 50-244/98-03-01: Power Reduction Due to Lack of Calorimetric Correction Factor Closed Ins ection Follow-u Item 50-244/98-13-01:
Inadvertent Dilution of the Reactor Coolant S stem When Placin a Mixed-Bed Demineralizer in Service Closed Non-Cited Violation 50-244/99-01-01: Ineffective Corrective Actions Led to an Inadvertent Dilution of the Reactor Coolant S stem When Placin a Mixed Bed Demineralizer in Service a.
The inspectors reviewed the adequacy of the licensee's corrective actions to three previous operational events and the event investigation following an inadvertent reactor coolant system (RCS) dilution event.
b.
Observations and Findin s On March 17, 1998, an unanticipated power reduction of approximately 1.5% was required due to the unavailability of data for steam generator blowdown flow during the performance of a calorimetric calculation (see IR 50-244/98-03).
The inspectors concluded that ineffective coordination between maintenance and operations personnel directly contributed to the event. The licensee generated an ACTION Report (98-0425)
in response to the event, but its resolution was delayed for approximately three months.
Its disposition described the related course of events and identified the need for personnel counseling, but did not identify a specific root cause or corrective actions to prevent recurrence.
Consequently, the inspectors opened IFI 50-244/98-03-01 to further inspect licensee analysis of root causes and corrective actions following plant events.
The inspectors also noted that two subsequent investigations were not completed in a timely manner, i.e., one for a March 11, 1998 event concerning an inadequate hold request for the B-containment hydrogen monitor with a report date of August 25, 1998; and one for an event involving inadvertent control rod motion on August 17, 1998 with a report issue date of September 23, 1998 (see IR 50-244/98-11).
On November 17,'1998, an RCS dilution event occurred when a mixed bed demineralizer with new resin was prematurely placed into service prior to equalizing boron concentration with the RCS (see IR 50-244/98-12).
The licensee initiated an event investigation to determine the root cause of the incident. However, prior to completion of the Investigation, the inspectors met with cognizant managers to discuss the delay in completing the evaluation because several months had elapsed, since it'
initiation. The inspectors noted that the licensee's corrective action program contained an administrative procedure (IP-CAP-3, "Investigation Teams" ) that required the licensee to conduct timely, thorough, and systematic investigations.
Additionally, the procedure'equired plant management to ensure that investigation team members were separated from outside influences, and to ensure that team members were relieved of all other assignments, as needed, while serving as a team member.
However, several team members had been unavailable to work on the evaluation for periods of time after
the event due to other work obligations.
On January 20, 1999, the licensee generated an ACTION Report (99-0059) indicating that the dilution event evaluation was not completed in a timely manner.
The dilution investigation and evaluation report were eventually completed on February 16, 1999.
The inspectors reviewed the investigation final report and noted a discrepancy in its description of operator response to the event. The report stated that control room operators took action to reduce main turbine load 0.7% by driving control rods in a total of nine steps.
The inspectors noted that this was incorrect, and that control room operators actually reduced turbine load to prevent exceeding 100% power, which subsequently raised the RCS average temperature and caused control rods to step in automatically.
The inspectors noted that the investigation report concluded that the exact root cause could not be determined, but that it was likelyto be a "skill based error" related to taking and analyzing the demineralizer sample, and was also related to a trainee taking the sample without a senior technician being present.
To address these issues, the report recommended that the licensee generate a work order when placing new resin beds in service and to ensure adequate pre-job briefings between operations and chemistry include discussions on any changes or differences in plant status that have occurred since the evolution was last performed.
However, the inspectors noted that the report did not specifically address broader communication and coordination deficiencies between operations and other departments as noted in previous operational events.
The licensee indicated that a Nuclear Directive was being drafted to act as a "stand alone" procedure for conducting event investigations.
The licensee also stated that all future event investigations would be performed in accordance with the requirements of IP.-CAP-3 until the Nuclear Directive is complete.
Conclusions Several operational events occurred due in part to ineffective coordination and communication between operations and other organizations that were previously unidentified, and therefore not corrected, and which contributed to a reactor coolant system dilution event. Additionally, the dilution event investigation did not meet administrative requirements for timeliness, thoroughness, or sequestering of investigation personnel which contributed to inaccuracies in the investigation and the lack of an exact root cause.
However, the licensee initiated corrective actions to address deficiencies in the investigation, and in coordination and communications between operations and other departments.
Therefore, this willbe a non-cited violation of 10 CFR 50, Appendix B, Cri/erion XVI,"Corrective Actions," consistent with Appendix C of the NRC Enforcement Policy. IFI 50-244/98-03-01 and IFI 50-244/98-13-01 are closed (NCV 50-244/99-01-01, IFI 50-244/98-03-01, IFI 50-244/98-13-01).
Recei t Ins ection of New Fuel
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1B)
The inspector observed receipt inspection activities for the new fuel assemblies that were delivered to the site for the next operating cycle.
b.
Observations and Findin s The licensee received four separate shipments of new reactor fuel on January 22 and 29, and February 5 and 12, 1999. On January 22 and February 5, 1999, the inspector observed the licensee unpack the assemblies, place them into temporary storage in the new fuel preparation area (NFPA), perform a detailed visual examination of each assembly, and then transfer each assembly into the spent fuel pool (SFP).
'hile unpacking the new bundles, the inspectors observed an RG&E quality control (QC) inspector verified that accelerometers in the shipping containers had not been tripped, and that the containers and assemblies had not been damaged during shipment.
The QC inspector conducted detailed visual examinations to verify each assembly's identification numbers, lack of physical damage or distortion of all fuel pins, cleanliness and lack of foreign material, and overall physical condition, The inspectors reviewed the licensee's documentation records that accounted for the proper identification and location of each assembly, and found no discrepancies.
Conclusions Receipt inspection of new fuel was thorough and well controlled.
No notable discrepancies were noted on any of the fuel assemblies or in the licensee's documentation.
Miscellaneous Operations Issues 08.1 Closed VIO 50-244/98-02-01: Failure To Monitor Control Room Panels and Attend to Alarms Ins ection Sco e (71707)
The inspectors reviewed the licensee's actions taken in response to a violation of NRC requirements for failure to followprocedures.
b.
Observations and Findin s The NRC issued Notice of Violation (NOV) 50-244/98-02-01 to RG&E on March 31, 1998, in response to an event on March 3, 1998, in which a pressurizer power-operated relief valve (PORV) inadvertently opened during pressurizer pressure control calibrations.
Control room operators did not respond to plant process computer system (PPCS) alarms in a timely manner, nor did they monitor main control board indication
" adequately as required by administrative procedure In their May 6, 1998, response letter to the NOV, the licensee committed to improve operator awareness of control board indications and PPCS alarms by taking the following corrective actions:
Perform a human performance e'valuation of the event and conduct operator training on a case study of the event
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Review, monitor, and evaluate administrative duties and procedures to formalize management expectations regarding monitoring of the main control board and the PPCS
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Evaluate main control board annunciator, circuitryfor pressurizer pressure control to ensure they remain capable of alarming with one channel out of service
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Perform a replacement of the pressurizer pressure defeat switch and evaluate the replaced switch to determine the root cause of its intermittent failure The inspectors reviewed the licensee's human performance evaluation completed on April20, 1998, and determined that the investigation was comprehensive and detailed (see IR 50-244/98-07).
Operator training on the case study associated with the human performance analysis was conducted for all crews during the course of their normal training cycle. The inspectors noted that administrative procedure A-52.11, "Conduct of Activities in the Control Room," was revised on May 5, 1998, and added new instructions for conduct of operations shift personnel in the control room. The revision also included requirements to ensure that if one control room operator was absent from the "at the controls" area, the remaining operator would maintain focus on plant status and not be involved in any administrative activities. Additional requirements designed to minimize distractions in the control room were also included.
The inspectors regularly observed control room operators during daily activities since the event occurred and have noted a heightened awareness among the operators regarding PPCS alarms and the "at the controls" area.
Within all crews observed, operators were aware of potential distractions, and halted administrative duties when one operator was temporarily absent from the main control board.
The licensee performed an evaluation of the annunciator circuitry for the pressurizer pressure defeat switch and initiated a plant change record (PCR) to install an additional bistable in each channel to ensure that both pressurizer high and low pressure alarms would be active with either pressurizer pressure control channel defeated.
The PCR was scheduled to be performed during the next refueling outage in March, 1999.
The licensee replaced the failed pressurizer pressure defeat switch, performed a performed a root cause analysis to identify a failure mechanism, and discovered three areas within the switch that were contaminated with cellulose material that was non-conductive and could have contributed to intermittent failures. The licensee concluded that the cellulose may have been acquired by packing storage materials used during the manufacturing process.
The licensee scheduled the replacement of all switches of the same vintage in the plant by the end of March 199 c.
Conclusions Based on the licensee's corrective actions to address operator awareness in the control room, and to correct deficiencies in the mechanism for defeating primary pressure control channels, the inspectors concluded that the licensee had adequately resolved the violation. This violation is closed (NOV 50-244/98-02-01).
08.2 U date LER 1998-003 Revision 1: Radon Buildu Durin Tem erature Inversion Results in Actuations of Control Room Emer enc AirTreatment S stem LER 1998-003 was originally issued on October 5, 1998 after multiple actuations of the control room emergency air treatment system (GREATS) by control room radiation monitors to isolate the control room ventilation system from outside air. Revision 1 was issued November 24, 1998 after two additional actuations occurred on October 20 and October 27, 1998.
The licensee replaced the "mother" circuit board for R-36 (control room noble gas monitor) on January 27, 1999.
On February 12, 1999, the control room ventilation system was briefly returned to its normal configuration.
However, the detector tube for R-36 procured from stock could not hold its calibration, and the ventilation system was returned to a recirculation lineup the same day. The licensee generated an ACTION Report (99-0175) to address the issue.
Additionally, R-36 momentarily spiked high on February 13, 1999, and the licensee generated another ACTION Report (99-0171) to address that issue.
CREATS was still out of service and the control room ventilation system was still in recirculation at the end of the inspection period.
This LER remains open until correct root causes and corrective actions are identified, and completed, and satisfactorily reviewed. The licensee indicated that a second revision to this LER was planned, but a completion date was not yet identified (LER 1998-003, Revision 1).
Ii. Maintenance M1 Conduct of Maintenance M1.1 General Maintenance Activities a.
The inspectors observed portions of plant maintenance activities to verify that the correct parts were utilized; the applicable industry codes and technical specification requirements were satisfied; adequate measures were in place to ensure personnel safety and prevent damage to plant structures, systems, and components; and to ensure that equipment operability was verified upon completion of post maintenance testin b.
Observations and Findin s Due to recent circuit breaker failures at the Ginna Station, the inspectors focused on the licensee's preventive maintenance (PM) program for Westinghouse Type DB breakers.
The licensee had implemented major improvements in their periodic breaker PM activities, and had identified deficient conditions in installed breakers that required repairs.
The inspectors observed all or portions of the following work activities:
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W.O. 19801450, PM Inspection of pressurizer proportional heater circuit breaker, Westinghouse DB-50 (observed on January 19, 20, 1999)
W.O. 19801443, Receipt Inspection of spare circuit breaker (52/EG1B1),
Westinghouse DB-75 for EDGs (observed on January 22, 1999)
W.O. 19801444, PM Inspection of B-EDG output circuit breaker (52/EG1B2) to safeguards bus 17, Westinghouse DB-50 (observed on January 25, 1999)
W.O. 19803449, GME-50-02-DB50, inspection and PM of Westinghouse DB-50 circuit breaker for the B-safety injection pump (observed on February 2, 1999)
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W.O. 19803716, CPI-MON-R29/R30, calibration, of containment area high radiation monitor (observed on January 26, 1999)
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W.O. 19803625, CPI-TRIP-TEST-5.10, and -5.20, reactor protection system trip test calibrations for channel one and channel two bistables (observed February
and 2, 1999)
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W.O. 19803612, CPI-BISTABLES-N41, calibration of nuclear instrument power range channel N-41 (observed on February 1, 1999)
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W.O. 19803613, CPI-BISTABLES-N42, calibration of nuclear instrument power range channel N-42 (observed on February 2, 1999)
c.
Conclusions The inspectors observed that the licensee exercised systematic work practices and achieved good quality repairs during preventive maintenance inspections of plant circuit breakers.
Controlled procedures were in use at maintenance job sites, were up to date and were properly utilized by technicians involved in the work. The inspectors observed good personnel and plant safety practices during the maintenance work.
M1.2 General Surveillance Activities a.
Ins ection Sco e(61726)
The inspectors observed selected surveillance tests to verify that approved procedures were in use, procedure details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by
knowledgeable personnel, and test results satisfied acceptance criteria or were properly dispositioned.
b.
Observations and Findin s The inspectors observed portions of the following surveillance activities:
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PT-12.1, "Emergency Diesel Generator A," monthly surveillance test (observed January 19, and February 16, 1999)
c.
Conclusions The inspectors confirmed that procedures used during surveillance tests were current and properly followed. The equipment tested met the acceptance criteria specified in the procedures for operability.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Maintenance Backlo The inspectors reviewed the licensee's progress in reducing the maintenance work backlog.
b.
Observations and Findin s The inspectors noted that the licensee had reduced the total maintenance backlog in recent months through Saturday work and overtime, with all maintenance departments and areas indicating a reduction.
Open corrective maintenance items had dropped from 726 in August 1998, to 526 in December 1998. The backlog of items greater than 2 yrs old had been reduced from 67 to 46 in the same time period. Two preventive maintenance (PM) activities were overdue in January 1999, and the licensee indicated that their goal for overdue PM activities was zero.
Licensee management indicated that their incorporation of a 12-week rotating maintenance schedule, their initiation of a new "fixit now" (FIN) team to address equipment repairs on a daily basis, and their utilization of a new work control center (staffed by two additional licensed operators) improved planning and scheduling efforts by helping to prioritize and reduce lower priority maintenance items.
Licensee management also indicated that a new tracking system for backlog items was being implemented to prioritize items based on corrective maintenance (broken equipment),
material condition (deteriorating equipment), and miscellaneous shop work (equipment that does not affect plant operation).
Conclusions The licensee was effective in reducing maintenance backlog items, due in part to good management oversight.
Improvements in planning and scheduling, such as the incorporation of a "Fix it Now" team and the utilization of a dedicated work control center to prioritize and reduce remaining backlog items, were good initiatives.
M2.2 Cable Re Iacement for Offsite Power Circuit 751 aO Ins ection Sco e (62707)
The inspectors reviewed, the licensee's activities to replace underground cabling for offsite power circuit 751.
b.
'Observations and Findin s The licensee decided to replace the underground cabling for both offsite power circuits 767 and 751 after an age-related splice failure occurred in circuit 751 on November 20, 1998 (see IF 50-244/98-1 2). The cable replacement for circuit 751 was performed from February 8-11, 1999. The licensee maintained an offsite power lineup in a 100%/0%
configuration respectively on offsite circuits 767/751 during the activity. The cable replacement was completed one day ahead of schedule and the offsite power lineup was returned to a 50%/50% lineup on both offsite circuits on February 11, 1999. The licensee indicated that the cable replacement for offsite circuit 767 would be scheduled after the upcoming refueling outage.
The inspectors noted that the electronic risk monitor for determining the overall increase in the baseline core damage frequency (CDF) did not indicate that CDF had increased at all during the time offsite power circuit 751 was out of service. The licensee normally used the risk monitor's color codes to identify the severity of changes in risk, i.e., green for CDF values between 1.0 - 3.0, yellow for values between 3.0 - 10.0, orange for values between 10.0 - 25.0, and red for any value over 25.0. However, operations and scheduling personnel both indicated that the loss of either source of offsite power had
"no effect" on CDF because the other circuit was available to provide power. The inspectors also questioned the licensee on their anticipated change to CDF if the remaining offsite power circuit failed while the other was out of service for maintenance.
The inspectors noted that the risk monitor could not be used to determine a change in CDF if both offsite power circuits were unavailable.
The inspectors questioned Nuclear Safety and Licensing (NS&L) personnel concerning changes in overall CDF when one or both offsite power circuits was out of service. The licensee subsequently determined that the electronic risk monitor was not modeled properly for the offsite power circuits. The licensee performed a detailed risk calculation and determined that the actual CDF would increase from a baseline value of 1.0 to a value of 1.25 with offsite power circuit 751 out of service and circuit 767 supplying all offsite loads.
Also, the CDF would increase by a factor of 1.5 with offsite circuit 767 out of service and circuit 751 supplying all offsite loads. The CDF would increase from the baseline value by a factor of 12.0 should the remaining circuit fail while the other was
C.
out of service. The licensee indicated that the electronic risk monitor would be properly modeled prior to performing the cable replacement on offsite power circuit 767.
Conclusions The cable replacement for offsite power circuit 751 was successfully performed in a timely manner.
However, the licensee's initial risk assessment to determine the effect of a loss of the other offsite power source on the performance of safety functions during the replacement was deficient in that no overall change in core damage frequency was identified.
M2.3 Safe uards Bus 14 Su I
Breaker from the A-Emer enc Diesel Generator Failure to Close Durin Post-Maintenance Testin Ins ection Sco e (62707)
The inspectors reviewed the licensee's actions after a post-maintenance test failure occurred on the bus 14 supply breaker from the A-emergency diesel generator (A-EDG).
b.
Observations and Findin s The post-maintenance test failure for the bus 14 supply breaker from the A-EDG occurred on February 15, 1999, after the licensee performed routine maintenance on the breaker.
The licensee indicated that the test failure was a control circuit problem and not a breaker malfunction since no signal was seen at the breaker (i.e. no breaker movement).
The licensee generated an ACTION Report (99-0181) to address the issue.
After troubleshooting the breaker control circuit, the licensee concluded that the synchronization selector switch for the bus 14 breaker did not properly make up during the test. The licensee could not verify that the switch had failed in the as-found condition at the main control board because an operator had inadvertently cycled the switch prior to troubleshooting, which resulted in the restoration of normal electrical continuity through the switch contacts.
However, after the switch was removed, the licensee repeated the failure during shop bench testing. The licensee indicated that the starwheel mechanism in the synchronization switch had just been replaced, and the switch had not been cycled prior to its reinstallation, causing the contacts to improperly make up on its first manipulation. The licensee replaced the synchronization selector switch and satisfactorily tested. the bus 14 supply breaker the same day, and sent the replaced switch off site for laboratory analysis.
C.
Conclusions The licensee effectively identified a deficiency in the synchronization selector switch for the A-emergency diesel generator.
Sending the replaced switch to a laboratory for analysis was a good initiativ MT M7.1
Quality Assurance in Maintenance Activities Maintenance Rule Ex ert Panel Meetin b.
The inspector attended a meeting of the maintenance rule expert panel.
Observations and Findin s A maintenance rule expert panel meeting was conducted on January 29, 1999, with representatives from operations, maintenance, and engineering present.
The previous meeting of the expert panel was on October 29, 1998. The panel held discussions on control building and battery room ventilation, nuclear instrumentation, and service water system status.
The inspectors noted that the discussions included input from all of the members present, and were focused on programmatic improvements to enhance system performance.
The inspector also noted that approximately two thirds of the agenda items were not discussed and deferred to upcoming expert panel meetings.
The licensee acknowledged that a backlog of review items had developed, and that a need existed to schedule additional meetings to ensure all agenda items are addressed.
c.
Conclusions Individuals on the maintenance rule expert panel asked probing questions and demonstrated a good understanding of the maintenance rule. However, no regular schedule exists for expert panel meetings, which resulted in a backlog of maintenance rule items for review.
M7.2 Scaffold Permits a.
Ins ection Sco e (62707)
The inspectors reviewed applicable procedures and observed the installation of scaffolding the licensee had erected in preparation for the upcoming refueling outage.
b.
Observations and Findin s The inspectors reviewed administrative procedure A-1406.1, "Installation, Removal, and Control of Scaffolding," and inspected scaffolds and permits throughout the plant. All inspected scaffolds were sturdy, and appeared to be seismically qualified. The inspectors noted that the permit for scaffolding in the turbine building adjacent to the feedwater control valves was initiallylisted as "non-seismic" and then subsequently changed to "seismic." The licensee indicated that all areas of the turbine building were considered non-seismic, as no credit for turbine building equipment is credited in current design basis accident analyses.
The inspectors noted that procedure A-1406.1 described "high energy piping" as requiring seismic qualification scaffolding and did not specify whether or not it was
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located in the turbine building. This implied that areas near high energy piping in the turbine building would require seismically qualified scaffolding. The licensee acknowledged the discrepancy and generated an ACTION Report (99-0114) to evaluate the issue.
C.
Conclusions Inspected plant scaffolds appeared to be well designed and installed in accordance with procedural requirements.
However, some confusion among the maintenance staff appeared to exist regarding the need for seismic scaffolding in areas of the turbine building near high energy piping.
III. En ineerin E2 Engineering Support of Facilities and Equipment E2.5 Tem ora Modification Status a.
Ins ection Sco e(37551)
b.
The inspectors reviewed the status of temporary modifications throughout the plant.
Observations and Findin s ll The inspectors reviewed the list of temporary modifications (TMs) that currently exist in the plant. As of January 1999, 22 TMs were in use and three had been in existence for greater than 18 months. The inspectors observed the installed temporary modifications and determined that they represented a minor safety significance for overall operation of the plant. The inspectors noted that the licensee had planned to remove 15 of the 22 TMs during the upcoming refueling outage and all but one TM (98-024: Temporary Nitrogen Bottles for the Waste Disposal System) by June, 1999. TM 98-024 was
'cheduled for removal in December 1999.
C.
Conclusions The licensee's plan to remove 21 of the current 22 temporary modifications by June, 1999 was a good initiative.
V. Mana ement Meetin s X1 Exit Meeting Summary After the inspection was concluded, the inspectors presented the results to members of licensee management on February 26, 1999. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identifie ATTACHMENTI PARTIALLIST OF PERSONS CONTACTED Licensee G. Graus G. Hermes J. Hotchkiss G. Joss R. Popp J. Pascher R. Ploof P. Polfleit J. Smith W. Thomson J. Widay T. White G. Wrobel I&C/Electrical Maintenance Manager Acting Primary Systems Engineering Manager Mechanical Maintenance Manager Results and Test Supervisor Production Superintendent Electrical Systems Engineering Manager Secondary Systems Engineering Manager Emergency Preparedness Manager Maintenance Superintendent Chemistry & Radiological Protection Manager Plant Manager Operations Manager Nuclear Safety 8 Licensing Manager INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 60501B:
IP 60705:
IP 61726:
IP 62707'P 71707:
IP 71750:
IP 92700:
IP 92901; IP 92902:
IP 92903:
Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Fuel Receipt and Storage Preparation for Refueling Surveillance Observation Maintenance Observation
'lant Operations Plant Support Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities Follow-up - Operations Follow-up - Maintenance Follow-up - Engineering
e Attachment I
~Oeoed NCV 50-244/99-01-01:
Closed NCV 50-244/99-01-01:
ITEMS OPENED, CLOSED, AND DISCUSSED Ineffective Corrective Actions Led to an Inadvertent Dilution of the Reactor Coolant System When Placing a Mixed Bed Demineralizer in Service Ineffective Corrective Actions Led to an Inadvertent Dilution of the Reactor Coolant System When Placing a Mixed Bed Demineralizer in Service IFI 50-244/98-03-01:
Power Reduction Due to Lack of Calorimetric Correction Factor IFI 50-244/98-12-01:
Inadvertent Dilution of the Reactor Coolant System When Placing a Mixed-Bed Demineralizer in Service VI0 50-244/98-02-01:
Discussed Failure To Monitor Control Room Panels and Attend to Alarms LER 1998-003, Revision 1:
Radon Buildup During Temperature Inversion Results in Actuations of Control Room Emergehcy AirTreatment System
Attachment I
LIST OF ACRONYMS USED CATS CDF CFR CBEATS d/p dpm EDG ESF FIN IFI IR ITS LCO LER NCV NFPA NOV NRC NRR NS&L PCR PM PORV PPCS ppm PT pslg QA QC RCS RG&E SFP Tave TM UFSAR VIO Commitment Action Tracking System Core Damage Frequency Code of Federal Regulations Control Room Emergency AirTreatment System differential pressure disintegrations per minute Emergency Diesel Generator Engineered Safety Feature Fix It Now Inspection Follow-up Item
Inspection Report
Improved Technical Specification
Limiting Condition for Operation
Licensee Event Report
Non-cited Violation
New Fuel Preparation Area
Nuclear Regulatory Commission
Nuclear Reactor Regulation
'uclear
Safety and Licensing
Plant Change Record
Preventive Maintenance
Power Operated Relief Valve
Plant Process Computer System
parts per million
Periodic Test
pounds per square inch gage
Quality Assurance
Quality Control
Rochester Gas and Electric Corporation
Spent Fuel Pool
Average Primary Coolant Temperature
Updated Final Safety Analysis Report
Violation