IR 05000440/1993022
| ML20059F837 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 01/07/1994 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20059F820 | List: |
| References | |
| 50-440-93-22, NUDOCS 9401140164 | |
| Download: ML20059F837 (18) | |
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f U. S. NUCLEAR REGULATORY COMMISSION ;
REGION 111 Report No. 50-440/93022(DRP)
Docket No. 50-440 License No. NPF-58 Licensee: Cleveland Electric Illuminating Company Post Office Box 5000 Clevel and, OH 44101 Facility Name: Perry Nuclear Power Plant Inspection At: Perry Site, Perry, Ohio ,
Inspection Conducted: October 29 through December 18, 1993 Inspectors: D. Kosloff A. Vegel R. Langstaff '
J. Gavula Approved By: > _
i M R. D. LanRsbury,ctfief __ Llate i Reactor Projects Section 3B i Inspection Summary Jnspection on October 29 throuah December 18. 1993 (Report N i 50-440/93022(DRPil (
Areas Inspected: Routine unannounced safety inspection by resident and l regional inspectors of licensee action on previous inspection findings, l licensee event report followup, surveillance observations, maintenance I observations, operational safety verification, event followup, engineering, and plant suppor Results: In the eight areas inspected, one violation and one unresolved item I were identified. The violation resulted from multiple personnel errors by licensed operators during a surveillance activity. No response to the violation was required. The unresolved item was opened to track evaluation of a personnel error by a licensed operator during a surveillance test. In -
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addition, a non-cited violation (NCV) of Technical Specification (TS) 4.3.7.8, I Loose-Part Detection System Surveillance Requirements was identified and reviewe The following is a summary of the licensee's performance during this inspection period:
Plant Operations On November 16, 1993, the generator was synchronized with the grid ending a 44-day maintenance outage. The plant was operated at or near full power until December 2,1993, when the plant was shut down, due to' !
degradation of the "A" recirculation pump shaft seals. The seal was j i
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i replaced and plant startup commenced on December 10. The startup was delayed to repair a steam leak and the main generator was synchronized with the grid on December 14, 1993. Power was increased and the plant was at full power at the end of the inspection perio Operator ,
control of the plant startups and outage activities was good. Operator control of the shut down was excellent and overcame challenges caused by ,
equipment problems. However several personnel errors were made by .
licensed operators during surveillance activitie Maintenance '
The quality of observed maintenance activities was generally good. A ;
violation, an NCV, and an unresolved item were identified during review of surveillance activities. All involved personnel error Housekeeping related to maintenance activity still needed attentio .
Enaineerina Engineering support of daily plant activities was good. Engineering evaluation of Agastat relay performance and diesel lubricating oil lead concentration was goo Increase emphasis had been placed on the flow ,
accelerated corrosion inspection progra ;
Plant Support
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The quality of observed activities involving radiation protection and security was generally good. Earlier improvements in plant housekeeping were maintained. Management oversight of outage activities and
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management's response to increasing lead concentrations in diesel lubricating oil and degrading recirculation pump shaft seal performance were good. The licensee identified.a personnel error during a fire watch patrol and several personnel errors in radiation protection activities, administration of physical examinations, and fitness for ;
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DETAILS . Persons Contacted Cleveland Electric Illuminatina company R. Stratman, Vice President - Nuclear - Perry
- K. Pech, Director, Perry Nuclear Assurance Department (PNAD) i D. Igyarto, General Manager, Perry Nuclear Power Plant (PNPP) !
- M. Bezilla, Operations Manager, PNPP
- N. Bonner, Director, Perry Nuclear Engineering i Department (PNED)
- V. Higaki, Manager, Quality Assurance Department, (PNAD)
- R. Schrauder, Director, Perry Nuclear Services Department (PNSD)
- H. Hegrat, Acting Manager, Regulatory Affairs, PNSD .
V. Concel, Manager, Mechanical Design Section, PNED l V. Sodd, Manager, Maintenance Section, PNPP
- P. Volza, ManPger, Radiation Protection Section, PNPP D. Cobb, Superintendent, Plant Operations, PNPP
- P. Roberts, Manager, Instrument & Control Section, PNPP +
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- F. Von Ahn, Manager, Technical Section, PNED
- D. Conran, Compliance Engineer, PNSD 1 W. Coleman, Manager, Engineering Project Support, PNED i W. Kanda, Manager, Integrated Scheduling and Controls, PNPP J. Wilcox, Superintendent, Maintenance, PNPP :
- J. Schrott, Alternate for Manager, Training Section, (PNSD) l
- Denotes those attending the exit meeting held on December 17, 199 ) Licensee Action on Previous Inspection Findings (40500. 71707, 9270 '
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92702)
(Closed) Open Item 440/91013-04 (DRSl: During an August 1991 emergency operating procedures inspection there was no evidence that the licensee had modified applicable plant procedures to meet the intent of the !
Boiling Water Reactor Owner's Group (BWROG) Emergency Precedure Guidelines (EPGs) for secondary containment control. In response to a May 1993 inspection (Inspection Report 50-440/93007), the licensee revised plant procedures to meet the intent of the guidelines for secondary containment control as discussed in Inspection Report 50-
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l 440/93018(DRS). By letter dated October 18, 1993, the licensee also- R updated docketed information to reflect its current position on i secondary containment control. This item is close No deviations or violations were identifie . Licensee Event Report (LER) Followuo (90712. 92700)
Through review of records, the following LERs were reviewed to determine if reportability requirements were fulfilled, immediate corrective actions were accomplished in accordance with technical specifications i (TS), and corrective action to prevent recurrence had been established:
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l a. (Closed) LER 50-440/91020-00: and -01: Cable tray raceways found to be impaired as a fire barrier, adversely affecting safe ,
shutdown requirements. The licensee determined that Thermolag 1 fire barriers had not been installed in accordance with the !
vendor's (Thermal Science, Inc.) installation criteri The !
maximum allowed spacing of mechanical fasteners was exceeded a because incorrect information, provided by a contractor, was used i for design, installation, and inspection instructions and l drawings. This LER was also a 10 CFR Part 21 report. Hourly fire watch patrols were initiated as compensatory action. Later generic problems with Thermolag were identified and NRC Bulletin 92-01 and Supplement 1, " Failure of Thermolag 330 Fire Barrier l System," were issued. Followup of this LER will be accomplished I by resolution of the issues identified in Bulletin 92-0 l Therefore, this LER is close j b. (Closed) LER 50-440/93019-00 : Failure to-Identify failed Channel Checks Due to Personnel Error Results in Technical Specification Violation. The "A" train high delta flow instrument for the reactor water cleanup (RWCU) system was inoperable for two shifts before being identified as such. This resulted in a violation of TS 3.3.2. The violation is discussed in Paragraph 4 (Monthly Surveillance Observations). ;
r Licensee's Investiaation of Root Cause and Corrective Actions l Root Cause lhe licensee determined that the root cause for this event was multiple personnel errors. The operator who first noticed the i problem on day shift failed to follow through on verifying the '
discrepant condition. That operator's supervisor also did not :
perform an adequate log review. On the afternoon shift the next two operators to notice the problem made a cognitive error in '
evaluating the condition. They concluded that the instruments i passed the channel check, although the channel check had failed i because the "A" train instrument was inoperable. A poorly worded i note in " Plant Round Instruction Operational Condition 1, 2 & 3 .
Technical Specification Rounds" (PRI-TSR-0C1, 2 & 3) contributed )
to the cognitive erro '
Corrective Actions Licensee corrective actions to prevent recurrence included ;
counseling of the involved operators and supervisors and revision of PRI-TSR-0Cl, 2 & 3. The licensee also committed to revise the administrative program for TS rounds to enhance the review process and to provide training on the event to other licensed operators.
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Inspector Review The inspectors reviewed the revised PRI-TSR-0C1, 2 & 3 and observed that the note for the RWCU instrument channel check had i been clarified. The inspectors assessed the licensee's j investigation as thorough and accurate in determining that the i root cause was multiple personnel errors. Additional licensee efforts to reduce personnel errors are currently in progres The effectiveness of these will be reviewed during continued ,
assessment of this area. This item is close l No violations or deviations were identifie . Monthly Surveillance Observations (61726. 92701)
l General Observations For the surveillance activities listed below, the inspectors l verified one or more of the following: testing was performed in i accordance with procedures; test instrumentation was calibrated; I limiting conditions for operation were met; removal and ,
restoration of the affected components were properly accomplished- I test results conformed with technical specifications, procedure i requirements, and were reviewed by personnel other than the j individual directing the test; and any deficiencies identified ;
during the testing were properly reviewed and resolved by appropriate management personne Surveillance Activity Title !
! 1 SV1 - P42-T2001 Emergency Closed Cooling System Pump I and Valve Operability Test l
SVI - L32-T0396 MSIV Leakage Control Heater j Continuity Test ;
SVI - E22-T1319 Diesel Generator Start and Load i Division III l
SV1 - M17-T2002 Containment Vacuum Breaker and l Isolation Valve Operability Test ;
l PRI-TSR-0Cl, 2 & 3 Plant Round Instruction Condition 1, :
2 & 3 Technical Specification Rounds Personnel Errors. PRI-TSR-0C1. 2 & 3 (1) On November 14, 1993, during the day shift, the Supervising Operator (S0) taking readings for PRI-TSR-0C1, 2 & 3, " Plant Round Instruction Operational Condition 1, 2 & 3 Technical Specification Rounds" noted out-of-specification (00S)
readings for the channel check for the reactor water cleanup
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i (RWCU) system high delta flow instruments. The 50 took no +
additional action to resolve the 005 readings. During the ;
afternoon shift a second S0 taking readings for PRI-TSR-0Cl, .i 2, & 3 recorded 00S readings for the same instruments. The second 50 then used an alternate method of making the_ !
channel check. Based on data from the alternate channel check the second 50 discussed the data with the Unit Supervisor and they incorrectly concluded that both instruments were operabl ,
At 3:00 a.m. on November 15, 1993, the midnight shift 50 l taking readings for PRI-TSR-0Cl, 2, & 3, recorded 00S '
readings for the same instruments and notified the Unit Supervisor. The "A" train instrument was declared inoperable and the licensee closed the isolation valves as required by the Technical Specification (TS) Limiting :
Condition for Operation Action statement. However, TS Table 3.3.2-1 required that the isolation valves be closed within-I hour of the associated instrument inoperabilit Since the instrument was observed to be inoperable during day :
shift on November 14 and the associated isolation valves ,
were not closed until after 3:00 a.m. on November 15, more !
than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the instrument was first observed to be inoperable, this was a violation (50-440/93022-01 (DRP)) of TS 3.3.2. The licensee's corrective actions for this event are discussed in paragraph 3.b (LER Followup, LER 93019).
The inspectors' review of the licensee's corrective actions ,
for this violation indicated-that the corrective actions !
were adequate and this violation is close (2) On December 1,1993, with the plant at full power, the afternoon Shift Technical Advisor (STA) did not perform a l channel check on the loose parts monitor as required by TS '
4.3.7.8.a. The afternoon shift Supervising Operator (50) in charge of recording the channel check readings for PRI-TSR-OCl, 2 & 3, " Plant Round Instruction Operational Condition 1, 2 & 3 Technical Specification Rounds," did not note that the required loose-part monitor readings had not been provided to him by the STA. The licensee identified the
, missed surveillance when a midnight shift 50 noted that the ~
! loose-part monitor channel check readings were not recorded i in PRI-TSR-0C1, 2 & 3.
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i- The TS required performance of the channel check every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with a 25 percent grace period (30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> total). When -- ;
the channel check was successfully performed on the midnight !
shift, more'than 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> had elapsed since the previous .)
channel check. This was a violation of TS 4.3.7.8, Loose-Part Detection System Surveillance Requirements. The licensee determined'that the root cause of the violation was personnel errors. The licensee prepared Condition Report 3
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(CR)93-434 to document the violatien and track evaluation 6 .
and corrective actions. The licensee comitted to complete eight corrective actions listed in CR 93-43 The inspectors assessed the licensee's corrective actions as adequate to prevent recurrence of the violation. This ;
violation was not subject to enforcement action because the licensee's efforts in identifying and correcting the !
violation met the criteria specified in VII.B of the
" General Statement of Policy and Procedure for NRC Enforcement Actions." Personnel Error. SV1 - H17-T2002 On November 19, 1993, with the plant at 30 percent power, SVI -
M17-T2002, " Containment Vacuum Breaker and Isolation Valve !
Operability Test," was being performed by a Supervising Operator
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(50) in the control room and a nonlicensed operator in the containment. The 50 erroneously instructed the nonlicensed operator to open and then close a vacuum breaker valve in containment that did not have its motor operated isolation valve closed. The isolatica valve for each vacuum breaker was normally open and was closed from the control room just prior to testing its associated vacuum breaker valve. During the 19 seconds that the vacuum breaker valve was open there was a flow path from containment to the outside atmosphere. This will remain an Unresolved Item (50-440/93022-02 (DRP)) until the inspectors complete their review of the licensee's evaluation of this error and its corrective action One violation, one noncited violation, and one unresolved item were identified. No deviations were identifie . Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and other components listed below were observed and/or reviewed to ascertain that activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance ,
with technical specification ,
The following items were considered during this review: the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the .
work; activities were accomplished using approved procedures and were '
inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality ,
control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemente m_ . _ . .
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Work requests were reviewed to determine statJs of outstanding jobs and ,
to assure that priority was assigned to safetf-related equipment maintenance which may affect system performanc Specific Maintenance Activities Observed or Reviewed
. Division III Diesel Generator Bearing Inspection
. Valve Nll F020 Repairs '
. Off-Gas Brine Unit Repairs
. Suppression Pool Makeup Valve Troubleshooting !
. Recirculation Pump Seal Replacement
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. Agastat relay replacement and testing Post Maintenance Restoration Following completion of work activities in the steam tunnel during the fall maintenance outage an inspector toured the steam tunne The inspector observed work-related materials in the steam tunnel that had not been cleaned up. This poor housekeeping was brought to the attention of maintenance management. The condition of the steam tunnel indicated that some individual workers and supervisors still do not recognize plant housekeeping as their personal responsibilit No violations or deviations were identifie . Operational Safety Verification (40500. 71707. 92701)
The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during this inspection period. The inspectors verified the operability of selected .
emergency systems, reviewed tagout records, and verified tracking of l limiting conditions for operation associated with affected component j Tours of the pump houses, control complex, the intermediate, auxiliary, '
reactor, radwaste, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for certain pieces of equipment in need of maintenance. The inspectors by observation and direct interview verified that the physical security plan was being implemented in accordance with the station security plan. The inspectors observed plant housekeeping, general plant cleanliness conditions, and verified implementation of radiation protection control i
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i a. prywell and Containment Insoection. Maintenance Outagg On November 9 and 11, 1993, respectively, the inspectors conducted i inspections of the drywell and containment. The inspectors
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conducted a walkdown of the areas to assess the material condition of equipment and the adequacy of post-maintenance cleanup. Based ,
on previous concerns with cleanliness in the drywell and l containment, due to the potential for debris to plug emergency '
core cooling system suppression pool suction strainers, the :
licensee expended substantial efforts to maintain the areas clea !
As a result of the inspectors' walkdown of the drywell, the ,
following unaccounted for items were identified:
. Tools (pliers, knife, sandpaper, and a putty knife)
. Scaffolding components
. Washers, nuts, bolts, screws
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. Nylon rigging strap
. Yellow plastic bag
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. Paper and plastic tags !
. Wooden spacer block The above items were identified to the licensee and remove Though the drywell appeared clean, with respect to dust and dirt, the identification of the above items is of concern. The fact that the inspectors identified the debris, though the licensee had previously conducted a drywell closecut tour, still indicates a need for additional attention to detail on the part of the licensee's staff conducting the closecut inspections. Though the items identified by the inspectors did not appear substantial
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enough to cause strainer fouling, the presence of the items demonstrated that further licensee efforts are needed to ensure that material accountability is improve I With respect to the inspectors walkdown of the containment, the ;
results were more positive. Based on the inspectors observations, the containment cleanliness appeared adequate, without any major !
accumulation ef debris being identified. Licensee personnel 4 performed well in identifying and removing debris that had I accumulated during the current and past outages. Though i housekeeping was adequate, several equipment material deficiencies were identified, including:
. Two valves in the mixed-bed demineralizer system were leaking (valves IP22-F598 and IP22-F617).
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. An abandoned 8 inch pipe clamp installed on residual heat l removal pipin i
. Instrument tubing improperly supported, compression fitting l leakin . Notes about equipment written on the walls with marker '
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corrective action was taken. Based on the inspectors' walkdown of l containment, additional attention to detail is warranted during licensee walkdowns of components in containmen b. Reactor Water level Indication Perturbations On November 15, 1993, while performing a routine walkdown of control room panels, an inspector noted that the reactor water level indicator, fuel zone, channel D (1821R0610D) was reading approximately 38 inches above the top of active fuel. Plant startup was in progress and all other reactor water level indications were reading approximately 200 inches. The inspector promptly informed the unit supervisor of the level deviatio Licensee review of other indications in the control room identified that reactor jet pump number 15 flow indication
{lB33R0611B) was reading approximately zero, with recirculation pumps running, this was an unexpected value. The licensee initiated an investigation to determine possible causes and the impact to other plant equipment. The licensee determined that the two transmitters involved (1821N044D for fuel zone level
) indication and IB33N0038B for jet pump flow) had a common instrument leg connection. Once this was determined, auxiliary operators were dispatched to the field to verify valve alignment All valves checked were found to be in their required position i Further investigation identified that the common instrument leg also communicated with the post accident sampling' system (PASS).
Chemistry was contacted and confirmed that a system purge was '
being conducted. The control room operators requested that the associated PASS valves be isolated. Once the valves were closed, indications for IB21R0610D and IB33R0611B returned to normal. The licensee initiated condition report 93-388 to document investigation of the event and track corrective actions to prevent recurrence. The inspectors will review the licensee corrective actions in a future inspection perio c. Recirculation Pumo "A" Shaft Seal Deoradation
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After the plant was started up from the fall maintenance outage the pressure in the second stage of the Recirculation Pump "A" seal was observed to be lower than the normal pressure of 550 psig. On November-24, 1993, with the second stage seal pressure i at 400 psig the licensee began increased monitoring and trending i of seal pressures and temperature. As seal pressure slowly '
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dropped the Operations Superintendent established instructions for notifications to operations and engineering management if seal parameters changed by specific margins. On November 29, 1993, with second stage seal pressure steady at 150 psig the. licensee began increased monitoring and trending of drywell gaseous radioactivity, drywell equipment sump inleakage, drywell floor sump inleakage, and drywell cooler condensation flow rate. About-8:00 a.m. on December 2,1993, the plant manager was informed that a change had been observed in the first stage seal pressure. This was an indication of possible first stage shaft seal deterioration. The plant manager promptly ordered a normal plant shutdown, which began at 8:37 a.m. The licensee and the recirculation pump manufacturer determined that the degradation of
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the pump seals was caused by foreign material on tne seals, .
possibly due to operating the seals without seal injection. Seal injection had been stopped due to evidence that it contributed to pump shaft crackin The licensee is planning to modify the pump
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shafts and the seal installation during the spring 1994 refueling i outage. The modifications will allow seal injection to be restored. On December 2, 1993, when the plant was shut down due to degradation of the "A" recirculation pump shaft seals, problems with the offgas system and loss of the only available auxiliary boiler challenged the operators. The operators performed well in -
maintaining control of the shutdown. However, better management oversight of auxiliary boiler and offgas system maintenance could have prevented the challenge to the operator d. Earthauake
On December 5, 1993, an earthquake occurred about 10 miles south of the sit The earthquake did not affect the plant. Data from the licensee's offsite seismic detectors was used to determine that the magnitude of the earthquake was about 2.7 on the Richter ;
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e. Drywell Inspection. Recirculation Pumo Seal Outaae !
On December 8, 1993, the inspectors conducted an inspection of the drywell. The inspectors assessed the material condition of- i equipment and the adequacy of post-maintenance cleanu During i the inspection of the drywell, the following unaccounted for items '
were identified:
. Tywraps \
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. Unattached and loosely attached tape
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c The above items were remove Though the drywell appeared clean, with respect to dust and dirt, the identification of the above items is of concern. The fact that the inspectors identified the items, though the licensee had previously conducted drywell cleanliness inspections, indicates a need for additional attention -
to detail on the part of the licensee's staff conducting the closecut inspections. Though the items identified by the inspectors did not appear substantial enough to cause strainer '
fouling, the presence of the items demonstrated that further licensee efforts are needed to ensure that material eccountability is improve Startup Observations Preparations for the startups from the maintenance outage and the recirculation pump seal repair outage were thorough. Operator control and management oversight for both startups was goo After the maintenance outage the generator was synchronized with the grid on November 16, 199 After the recirculation pump shaft seals replacement outage, plant startup commenced on December 10. While the plant was heating up ,
a steam leak was observed on the Moisture Separator Reheater IB second stage drain tank. The startup was delayed to repair the -
steam leak and the main generator was synchronized with the grid -
on December 14, 199 No violations or deviations were identifie . Onsite Followup of Events at Operatina Power Reactors (937021
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The inspectors performed onsite followup activities for events which occurred during the inspection period. Followup inspection included one or more of the following: reviews of operating logs, procedures, and condition reports; direct observation of licensee actions; and ;
interviews of licensee personnel. For each event, the inspectors reviewed one or more of the following: the sequence of actions, the functioning of safety systems required by plant conditions, licensee .
actions to verify consistency with plant procedures and license I conditions, and verification of the nature of the event. Additionally, I in some cases, the inspectors verified that the licensee's investigation J identified root causes of equipment malfunctions or personnel errors and )
the licensee was taking or had taken appropriate corrective action i Details of the events and licensee corrective actions noted during the j inspector's followup are provided belo j Hiah Pressure Core Sorav Operability As previously documented in inspection report 50-440/93020, the licensee notified the NRC via the emergency notification system (ENS) on October 20, 1993, that the high pressure core spray (HPCS) system was inoperable due to two of the four reactor vessel water level instruments for HPCS indicating in the non-
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conservative direction. The cause for the faulty level indication ;
was a nitrogen bubble that became entrapped in the instrumentation j reference leg during restoration from the installation of a <
modification. The licensee's reportability decision for HPCS inoperability was based on the assumed loss of a single train safety functio Later review by the licensee of the notification and technical specification requirements determined that the event was not reportable. The basis for this determination was that since the plant was in Operational Condition 4, the single train function of HPCS was not applicabl Technical Specification 3.5.1, Emergency Core Cooling System (ECCS) Operating, provides limiting conditions ,
for operation (LCO) actions based on the operability of ECCS systems, classified as high or low pressure systems. Technical Specification 3.5.1 considers HPCS ts be a single train ECCS (high pressure system) in operational conditior 1, 2 or Technical Specification 3.5.2 requires at least two of the five ECCS subsysten;s/ systems (HPCS, low pressure core spray, low pressure coolant injection A, B or_ C) be operable. With one of the two required subsystems / systems inoperable, 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is allowed i to restore the two subsystems / systems to an operable statu Technical Specification 3.5.2, therefore, considers the ECCS to i consist of five trains in operational condition 4 or 5. The single train function of HPCS is not applicable in operational >
condition 4 or 5. Therefore, the licensee concluded that a single train safety system function was not lost with the plant in operational condition 4 and there was no reportable even On November 2,1993, the licensee retracted the notification made on October 20, 1993. The licensee initiated condition report 93-276 to document the event and track corrective actions to prevent recurrence. The inspectors discussed the event with the licensee staff and reviewed applicable documentation and determined- that the licensee notification retraction appeared reasonable and in compliance with reporting requirement Emeraency Closed Coolina (ECC) System Operability l As previously documented in inspection report 50-440/93020, on October 15, 1993, the licensee informed the NRC via the ENS of a i potential design problem with the ECC piping interconnection with l the Nuclear Closed Cooling (NCC) system. A break in the j nonsafety-related NCC piping could cause failure of the ECC i system. The licensee analyzed the nonsafety-related piping and i determined that it could withstand a safe shutdown earthquak '
Therefore it was not necessary to postulate a break in the {
nonsafety-related NCC piping. The licensee provided this ^
additional information to the NRC via ENS on November 9,199 l l
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4 UNUSUAL EVENT - Transportation of a Potentially Contaminated Individual Offsite On December 10, 1993, a potentially contaminated contractor _was transported to a local hospital. it 11:00 a.m. the contractor fainted and fell backwards outside the lower containment airlock in an area posted as contaminated. The contractor was exiting the containment after she felt ill while performing routine survey The Perry Township Fire Department emergency medical unit was dispatched to the site. Based on the nature of her potential injuries, the contractor could not be moved to survey her back for contamination. Consequently, she was transported, accompanied by ;
a health physics technician, to a local hospital by the Perry '
Township Fire Department with the potential that her back was contaminated. As a result, at 11:20 a.m., the licensee declared an UNUSUAL EVENT in accordance with the licensee's emergency plan, Initiating Condition N.I.1, " Transportation of a contaminated injured individual from the site to an offsite Hospital." During evaluation at the hospital, the contractor was found not to be contaminated at approximately 11:34 a.m. The UNUSUAL EVENT was
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terminated at 11:45 a.m. The licensee initiated condition report :
93-460 to document investigation of this even No violations or deviations were identifie !
8. Enqineerina (40500, 71707. 92701_1 Division III Diesel Generator Lead Concentration in Lube Oil '
In September 1993, the licensee identified an upward trend in lead concentration in the Divisis. III diesel generator (DG) lube oi The DG vendor was requested t.o assist in evaluation of this condition. Based on cumulative lead concentration in the oil, the ,
vendor recommended that an inspection of the engine bearings be performed. The cumulative lead concentration was 73 ppm, with 75 +
ppm being the vendor recommended trigger value for identifying potential problems. As a result, on October 31, the DG was taken out of service for inspection and repairs. The licensee inspected and replaced the 10 connecting rod bearings, the 12 main bearings ,
and the 40 camshaft bearings. No abnormal wear of the bearing
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surfaces was identified and'the source of the lead in the lube oil 1 was not confirmed. The Division III DG was satisfactorily :
retested and restored to operation on November 4,199 ,
The inspectors observed the Division III DG maintenance ;
activities, reviewed associated documents and discussed the lead in the lube oil issue with the licensee's engineering staf Based on the above observations, licensee efforts were aggressive in investigating the source for the increase in lead ,
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concentration, once the problem was identified. The maintenance
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effort to inspect the DG was well coordinated and was performed with adequate supervision. Overall, the licensee's response to address this issue was good, b. Aaastat Relays During the previous inspection period (inspection report 50-440/93020) the licensee identified a problem with normally energized Agastat EGP and FGP general purpose relay The licensee began a special testing program and observed three relays fail. During this inspection period the licensee completed testing and replacement of the 190 relays that had been included in the special testing program. No additional failures were identified. Based on the observed failures and condition of relays that were removed the licensee concluded that the service life of the relays was between 3 and 4.5 years at Perry. This is i shorter than the previously established service life of:4.5 year .
The licensee is working with the vendor to more accurately +
determine the service life of EGP relays as used at Perry. The licensee no longer intends to use FGP relays. The inspectors periodically observed removal and testing of the relays. The inspectors will continue to monitor licensee efforts and document results in a future repor c. Flow Accelerated Corrosion Inspection Results During the maintenance outage the licensee performed inspections of numerous systems, evaluating areas for flow accelerated corrosion. The ultrasonic test (UT) examinations were conducted on various systems, including the "C" residual heat removal, reactor water cleanup, high pressure heaters and drains, extraction steam, feedwater, and condensate systems. The licensee performed 190 examinations. As a result several areas of reduced pipe wall thickness were identifie Specifically, 1-1/2 inch ,
carbon steel drain piping for moisture separator N25-B001B was below 87.5 percent of its nominal wall thickness. The minimal allowed wall thickness for the piping was determined to be .057 -
inches, the measured wall thickness was 0.166 inches, with a calculated " alert" level of 0.175 inches. Based on the measured wall thickness of 0.166 inches, and the calculated maximum actual l corrosion rate of 0.056 inches per service year, the licensee determined that the piping was acceptable for operation for up to .
1.3 additional operating cycles. The licensee plans to reinspect the piping during the fourth refueling outage scheduled for February 1994. During inspections of the direct contact heater, the licensee identified wall thinning of the heater due to erosion. The minimal wall thickness for the direct contact heater was 0.410 inches, several areas were measured at approximately 0.380 inches. The licensee postulated that the wall thinning identified was due to steam impingement erosion from a 24-inch extraction steam line which feeds the heater. The licensee performed a carbon steel weld buildup of affected areas to restore l i
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the thickness to above the minimum requirement During the fourth refueling outage, the licensee plans to apply a stainless steel cladding weld overlay to the affected areas to inhibit further erosio l The inspectors periodically observed performance of ultrasonic i examinations, reviewed licensee evaluation of examination results, and discussed implementation of the flow accelerated corrosion '
program with the responsible licensee engineer. The inspectors i observed that increased emphasis had been placed on the progra During the third refueling outage in 1992, the licensee performed 31 inspections, during the fall maintenance outage 190 inspections were. conducted, and 178 inspections are planned for the fourth refueling outage. Based on discussions with the licensee staff, efforts are currently in progress to identify additional areas ,
where flow accelerated corrosion could occur. The inspectors will -
continue to evaluate the progress of licensee efforts in this area-during routine observation of engineering and testing activitie Potential Failure of Taraet Rock Solenoid Valves i
During the fall maintenance outage the licensee identified loose ,
solenoid housing covers on Target Rock solenoid valves during an ;
equipment qualification (EQ) audit. During investigation of the !
loose solenoid covers the licensee found loose capscrews on the solenoid housing terminal / rectifier _ brackets. The licensee determined that six of the valves were inoperable. The licensee restored valve operability prior to startup from the fall outag The licensee reported the inoperable valves in Licensee Event Report (LER) 93018. The inspectors will complete evaluation of the inoperable valves during review of the LE No violations or deviations were identifie ,
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9. Plant Support !
l Trainino Observations !
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During the report period, the inspectors attended the licensee's general employee training (GET) and radiological controls training (RCT). For the training observed, the inspectors noted that-pertinent course material was available to each trainee and classrnom lectures were provided by knowledgeable licensee personnel. Of note was the practical exercise required for successful completion of RCT training which included proper donning and removal of protective clothing. Based on the observations noted above, the inspectors concluded that the training provided was well planned and useful for the attender ,_
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. Persoi.nel Error Durina Fire Watch Patr_o_1 The licensee identified a personnel error that had been made during a fire watch patrol conducted on November 25, 1993. The inspectors will complete their review of this event when the licensee submits a licensee event repor Personnel Errors Related to Administration nf Phy_s_ical Examinations and the Fitness-for-Duty Proarag The licensee identified several personne' m- , in th'
administration of required physical exv: w a >
wd operators and members of the fire brigaa 3% -co ano verified that personnel with inadequate ph. c,s a 1: ies-d of associated duties until their physical exh iinations we a :' ca erly completed. The inspectors requested assistance from re s w specialists in evaluating these personnel errors. The . l icen',ee also identified several personnel errors in administration of the
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fitness-for-duty program. The inspectors requested assistance from regional specialists in evaluating these personnel error The licensee's QA section issued a corrective action request for these personnel errors. The evaluation of these errors and the licensee's corrective actions will be completed based on the results of the reviews of the regional specialist Events Related to Radiological Protection The licensee identified several events related to radiological protection practices, some of these events involved personnel errors. The inspactors requested that regional inspectors review these events during a planned January inspection. The events included inadequate locking of locked high radiation areas, evacuation of the offgas building during maintenance, problems with charcoal sampling, and personnel locked in the drywel . Unresolved Items An Unresolved Item is a matter about which more information is required in order to ascertain whether it is an acceptable item, a violation, or a deviation. An resolved item disclosed during this inspection is discussed in paragraph . Items for Which a " Notice of Violation " Will Not Be Issued During this inspection period, certain licensee activities, as described in paragraph 4.b, appeared to be in violation of NRC requirement However, the licensee identified this violations and it is not being cited because the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy),10 CFR Part 2, Appendix C were satisfie . .
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.12. Exit Interview l .'
l The inspectors met with the licensee representatives denoted.in
, paragraph 1 throughout the. inspection period and on December 17,.1993.
I' The inspectors summarized the scope and results of the inspection and
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discussed the likely content of the inspection report. The licensee did-
!- not indicate that any of the information disclosed during the inspection
[' could be considered proprietary in nature.
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