IR 05000219/1988023
| ML20245D942 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 09/27/1988 |
| From: | Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245D941 | List: |
| References | |
| 50-219-88-23, NUDOCS 8810070319 | |
| Download: ML20245D942 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report N /88-23 Docket N .
License N DpR-16 Priority -- Category C e
Licensee: GPU Nuclear Corporation 1 Upper pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station'
Inspection Conducted: July 31, 1988 - September 10, 1988 Participat.ing Inspectors: W. Baunack E. Collins D. Lew J. Wechselberger Approved By: #d4d 1.L! N77kf Date C. t@gil{, hief, Reactor Projects Section 1A
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Inspection Summary:
Areas Inspected: Routine inspections were conducted by the resident inspectors and one region-based inspector (372 hours0.00431 days <br />0.103 hours <br />6.150794e-4 weeks <br />1.41546e-4 months <br />) of activities in progress includin plant operations and startup, radiation control, physical security, maintenance and forced shutdown work activities. In addition, inspectors reviewed isolation condenser system operability issues, Emergency Service Water (ESW) system In-Service Test (IST) results and baselining methodology, MSIV 5% closure tests, re-work procedure requirements and drywell air lock testing. The inspectors also cbserved portions of the quarterly emergency drill, witnessed MOVATS testing and reviewed operational experience during hot weathe Results: One apparent violation was addressed involving isolation condenser sys-tem operability. Concerns were developed during review of isolatien conderser system operability, including adequate Local Leak Rate Test (LLRT) procedural steps to return valves to the proper lineup and operator adherence to valve lineup veri-fications. Review of "B" isolation condenser activities resulted in concerns re-garding leak tightness of the isolation valves, continued thermal binding of the isolation condenser condensate return valve (V-14-35) and the licensee's ability to solve this problem, proper control room log keeping, recognition and reporting of events, and the temperature anomaly associated with the isolation condenser steamlines. Several licensee improvements in ESW baselining were mad ! .
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SUMMARY AND OVERVIEW Tne plant shut down on July 9 to repair a Main Steam Isolation Valve (MSIV). On completion of the repairs, a plant startup on August 11, 1988 was performed from unplanned outage 11-U-7, and the plant reached power operation on August 12, 198 On August 23, the "B" Emergency Condenser steam inlet valve was placed on its back-
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seat for a packing adjustment. Subsequent post maintenance testing showed that the valve operator. motor had failed. The motor was replaced, post maintenance testing was performed, and the Emergency Condenser was declared operable on August 2 During the surveillance testing performed on August 28, an operator valving error caused a brief initiation of the Emergency Condenser. This resulted in a minor plant transient, and it became apparent that the condensate return valve was now leaking as indicated by Emergency Condenser shell side temperature increasing to 212 degrees and.by observing water vapor at the shell vent. Operator action to continually add water was necessary to maintain shell water level above the low level alar On August 29, the licensee closed the redundant condensate return isolation valve in order to trouble shoot the leaking valve. With both condensate return valves closed, the shell side temperature remained at 212 degrees, and the makeup rate of water to the condenser shell remained essentially the same at about 15 gallons per minute, indicating both condensate return valves are leaking. The system was returned to service with these valves leaking, following analysis of potential consequences of a tube laa During additional licensee evaluations associated with the isolation condensers, it was determined that the "A" isolation condenser had not been properly aligned for service following maintenance during an August shutdow This report also describes other activities and test occurring during the inspec-tion period. Those are listed in the Table of Content ,
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TABLE OF CONTENTS PAGE l 1.0 ' Inadvertent "B" Isolation Condenser Initiation.(71707, 62703, 62705,93702)...................................................... 1
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1.1 Event Description............................................... 1
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1.2 -Valve B1nding..................................................... 2 1.3 Valve' Isolation Operability..................................... 2 !
l 1.4 Emergency Condenser Valve Testing............................... 3 1.5 Emergency Condenser Steam Line Temperatures.................'.... 4 i "A" Isolation Condenser Inoperable (71707, 71710, 42700, 93702). ... . . 4 ! Event........................................................... 4 2.2 Event Rev1ew....... ............................................ .3 Conclusions..................................................... 7
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3.0. Emergency Service Water System In Service Test (IST) Rebaselining !
(71707)............................................................ 1 4.0 Di esel Generator Control Ci rcuitry (62702) . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
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I 5.0 Core Bore Or1111 ng ( 93702, 71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 fs..~ . l 6.0 Drywell Ai rlock Local Leak Rate Test (61720) . . . . . . . . . . . . . . . . . . . . . . . .. . 9 .
7.0 -Quarterly Emergency Drill (82301).................................... 10 8.0 Fuel Rod Defects (71707,36100)...................................... 11 l l
9.0 MSIV Closure-Test (71707,61726)..................................... 11 l
10.0 Radiation Protection (71709, 83724, 83726)........................... 11 10.1 High Radiation Area Door Unlocked............................... 11 10.2 Augmented Offgas Doors 0 pen..................................... 12 10.3 Disposal of Radioactive Materia 1.. ............................. 12 10.4 kaciolog1 cal Control Area Entry................................. 12 10.5 Genera 1......................................................... 13
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TABLE OF CONTENTS-
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L PAGE 11.0 Plant Operational Review (71707, 61726, 62702, 71715). . . . . . . . . . . . . . . . 13 y
11.1 Reactor Startup..................... ............................ 13 11.2 Operational Events.............................................. 14 11. Hot Weather Operation................................. 14 11. Equipment Rework...................................... 15-11. ESW Pumps............................................... 17 11. Hydraulic Control Units............................... 17 11. K31V Surveillance Testing........ .................... 18 11. Reactor High Pressure Scram Survei11ar.ce.............. 18 11. Acoustic Monitors...................................... 18 11.3 Control Room.................................................... 19 11.4 Facility Tours.................................................. 19 12.0 Monthly Surveill ance Observations (61726) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
- 13.0 Observation of Physical Security (71881)................. ........... 21 13.1 Accidental Fi rearm Di scha rge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 13.2 Genera 1......................................................... 21 14.0 Backshift Inspections................................................ 21 15.0 Exit Interview and Management Meetings (30703, 30702). . . . . . . . . . . . . . . . 21 ATTACHMENT ATTACHMENT I - Valve V-14-6 Activity Summary (
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DETAILS l
1.0 Inadvertent "B" Isolation Condenser Initiation 1.1 Event Description During a valve operability test of the "B" isolation condenser on August 28, 1988, at approximately 12:30 p.m., a licensed operator incorrectly performed a sequence of condensate return valve manipulations (V-14-35 and V-14-37), resulting in an initiation of the "B" isolation condenser for a few seconds. The operator immediately recognized the mistake and took appropriate action to close the valves. The licensee noted a 1 inch reactor vessel level increase and a l*s increase in reactor power as a result of this system actuation. The inspector reviewed this transient with the licensee and did not note any abnormal conditions other than those indicated below. The licensee subsequently made a four hour report via the Emergency Notification System, but was approximately an hour and ten minutes late in reporting the even In addition, the control room log entries for this event were made approximately six hours af ter the isolation condenser initiation. The inspector discussed both the late event reporting and log entries with the licensee, who stated that these were a result of shift management not immediately recognizing the signi-ficance of the isolation condenser initiation. Operations management was informed of the event shortly after its occurrence. The inspector expressed concerns regarding the late log entries and noted implementa-
'(' tion in timely logging of events should be emphasized. The licensee has already taken steps in providing guidance to operators on proper log entries. With regard to the untimely reporting of the event, the NRC will exercise its discretion and not issue a Notice of Violation for the licensee-identified vilation since all five conditions required by 10 CFR Part 2, Appendix C had been me The operability test on the "B" isolation condenser was conducted on August 28, 1988, to return the condenser to service after completion of maintenance on V-14-33, "B" isolation condenser steam line inlet isola-tion valve. This Maintenance was planned to repair a packing leak on V-14-33 with the valve on its backseat. In attempting to place the motor operated valve on its backseat, licensee personnel incorrectly used an A.C. amp probe. Af ter several unsuccauful attempts to obtain the proper current reading while backseating the valve, a D.C. amp probe was used. It appears that this error in backseating may have damaged the valve operator motor, The licensee performed MOVATS testing of V-14-33, and determined that the valve motor should be replaced. The inspector witnessed portions of this testing. These maintenance activities in-cluding motor replacement and subsequent testing occurred from August 23-28, 1988, rendering the "B" isolation condenser inoperable during this tim f
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1.2' Valve Binding The misoperation of. valves V-14-35 and V-14-37 on August 28, 1988, ap-pears to have caused a V-14-35 valve problem. V-14-35 has a history of L thermal binding problems. In reviewing V-14-35 maintenance history the inspector determined that valve binding occurred in February, .1985 (in-spector open item 219/85-06-02), and again in May, 1987. In response to the occurrence in February,1985, the licensee disassembled the valve for a detailed internal inspectio This inspection was performed in October,1985, for the purpose of identifying the root cause of the failure. Blue checks were performed on both seats and indicated 360 degrees contact. Nondestructive examinations (NDE) were performed on the inner and outer valve body, valve bonnet, valve body seats, valve discs, stem, guide rails, stuffing box and stuffing gland. The only deficiencies identified were linear indications in the valve stem, and the stem was replaced. Extensive valve internal measurements were made, but no deficiencies were identified. A manufacturer representative ob-
. served valve reassembly. The licensee. concluded from this inspection that the root cause of valve failure was excessive binding from live loaded packing in comb'ination with packing drying between valve opera-tions. To address this, a bushing was fabricated to reduce stuffing box depth, thus reducing the amount of packing installed. The subsequent recurrence of valve binding in May,1987, indicates that the root cause
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has not yet been identified and corrected. Open item 219/85-06-02 will ic remain cpe On August 23, 1988, the "B" isolation condenser was removed from service for V-14-33 maintenance activities. This action resulted in isolation of steam to the isolation condenser and subsequent cooldown of the iso-lation condenser. Normally, during a plant 'cooldown, operators would cycle V-14-35 every 100 degrees F to ensure the valve does not become thermally bound. In this situation, however, the licensee did not recognize that cycling valve V-14-35 would also be required as the isolation condenser cooled down separately. This coupled with the in-advertent initiation of the isolation condenser may have contributed to the mechanical binding of the valv .3 Valve Isolation Operability
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The initial inspector concern involved the constant water makeup to the
"B" isolation condenser needed af ter the inedvert?nt initiation. The inspector was concerned that the significant makeup rate indicated sub-stantial valve leakage or flow through V-14-35. In performing a simple thermal energy balance acrcss the isolation condenser both the licensee and inspectors independently determined that approximately 18 gpm were flowing through the valve with approximately a 20 psi differential pres-sure. The main inspector concern centered eround an isolation condenser pipe or tube break and the facility's ability to satisfy 10 CFR 100
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limits when the valve would be required to isolate against a 1000 psi differential pressure. This would result in a much higher flow rate
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through valve V-14-35. The inspector expressed his concerns to the lic-ensee who immediately closed V-14-37, the redundant condensate return valve for V-14-35. The licensee had already begun plans to remove the isolation condenser from service and trouble shoot V-14-35 when the in-spector discussed the concern with the licensee. Subsequent MOVATS testing of V-14-35 by the licensee determined that the torque switch setting was lower than required. During the MOVATS testing, the licensee found that the motor operator developed approximately 18,000 lbs of thrust in the closing directio The minimum recommended closing thrust value is 21,302 lbs. The torque switch was increased to correspond to the requirements of Station Procedure 700.2.010, " Motor Operated Valve Removal, Installation, or Inspection (Elect)" and the required thrust values. This action, however, had no observable effect on the valves'
leak rat The licensee performed 10 CFR 100 calculations for present and technical specification limits for reactor coolant iodine activity levels. These calculations satisfied 10 rFR 100 limits. In addition, the inspector obtained independent reg' 1 office calculations which corroborated the licensee's result .4 Emergency Condenser Valve Testing Technical Specification 3.8, Isolation Condenser, defines operability ( specifications for the isolation condenser steam inlet valves (V-14-30, V-14-31, V-14-32 and V-14-33) and the A.C. motor operated isolation con-denser outlet (condensate) valves (V-14-36 and V-14-37), but does not address the D.C. motor operated isolation condenser outlet valves (V-14-34 and V-14-35)- The basis for Technical Specification 3.8 refers to
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V-14-34 and V-14-35 stating that it ;s not necessary to test the redund-ant D.C. motor operated valves as these valves are normally in the closed position. Other than this reference to the D.C. motor operated conden-sate isolation valves, they are not specifically discussed. Since the intent of the specification is to address the isolation function of the valves, the specification should also address the isolation functions of V-14-34 and V-14-3 This warrants clarification to avoid operator and licensee confusion with regard to one of the design functions of the valve Operability testing on these valves only involves valve stroking and does not require any determination of leak tightness. In a letter to Director of NRR from Jersey Central Power end Light Company dated November 22, 1978, a request for partial exemption from the requirement tf 10 CFR 50 Appendix J was forwarded including isolation condenser valves V-14-30 through V-14-37. In a reply letter dated March 4, 1982, the exemption l
for Appendix J testing was accepted as these valves do not provide an isolation function for a line break occurring inside the containmen These valves do, hcwever, provide a reactor coolant pressure boundary isolation in the event of an isolation condenser tube rupture or an
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isolation condenser line break, both of which occur outside the primary
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containment. -The allowable leakage for the emergency condenser isolation valves should be quantified to ensure. valve integrity', and thus the iso-1ation valves ability- to. perform their intended pressure isolation func-tio In addition, other valves performing a similar function exist in the plant that are not leak checked. One. set of valves in particular, the scram discharge volume (SDV) drain valves (V-15-121 and V-15-134) caused significant radioactive steam release in the reactor building when the licensee was unable to reset a scram on June 12,1985 (see Inspection Reports 85-19 and 85-23). Unresolved item 85-23-05 questions why the SDV vent- and drain valves are not part of the containment pressure
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boundary and, therefore tested in accordance with the requirements of 10 CFR 50 Appendix J. Management attention is required in addressing these issue .
1.5 Emergency Condenser Steam Line' Temperatures Emergency Condenser steam line temperatures are about 540 degrees.F fol '
lowing startup and then gradually decline as condensate accumulates in the steam'line. After the "B" isolation condenser initiation, the two steam line temperatures dropped from the 540 degrees F they were at, to 100 degrees F when removed from service, and then one recovered to about n 300 degrees F and the other to about 200 degrees F following return to ,
service. It would be expected that the -
ratures would have returned L to a higher value with the condensate ret en valves leaking. This con-dition has not been explained to date. .The licensee should assure them-selves that this is not indicative of. a potential degradation of isola-tion condenser performanc .0 "A" Isolation Condenser Inoperable 2.1 Event In preparation to return the "B" isolation condenser to service on Sep-tember 2,1988, after testing of the condensate return valve, V-14-35, the licensee was evaluating the steam line temperature indications (see paragraph 1,5). As part of this evaluation, it was decided to verify
.that the isolation condenser vent valves were correctly positioned. The licensee cnose to verity the vent valves for both the "A" and "B" isola-tion condensers as a matter of prudence. During this verification, it was determined by the licensee that while the manual vent valve for the
"B" isolation condenser (V-14-2) was correctly positioned ("open"), the manual vent valve for the "A" isolation condenser (V-14-6) was no V-14-6 was found in the " closed" positio With the condenser vent path isolated, this would prevent the " venting off" of noncondensible gas fro'n the isolation condenser steam supply
's piping and condenser tube Noncondensable gases adversely affect the ( ~l ability of the isolation condenser to perform its intended function and
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i o Upon discovery, the licensee declared the "A" isolation condenser in-operable. Since the "B" isolation condenser was already inoperable 'for maintenance and evaluation, the plant was below the minimum functional capability for safe operation of the facility as defined.in the plant technical specifications. A plant shutaown was initiated, reducing powe': r at the rate of 25 megawatts electric per hour. Plant technical specifi-
-cations require that both "A" and "B" isolation condensers be operable,
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with one condenser permitted to be out of service with the plant in the
'run' mode for a period not to exceed seven days. With both condensers out of service, plant technical specifications require the plant to be placed in " cold shutdown" within 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> The licensee opened the manual vent valve, V-14-6, to establish a vent path for the "A" isolation condenser, performed complete valve lineup verifications on both isolation condenser subsystems, and initiated cal-culations to determine the length of time required to vent the noncon-densable gases prior to "A" isolation condenser being capable of per-
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forming its intended functio The licensee notified the NRC duty officer at 12:26 p.m. on September 2,1988 that both isolation condensers were not operable via the Emer-gency Notification Syste .At 8:17 p.m'. on September 2,1988, both "A" and "B" isolation condenser (',
-subsystems were returned to service, and the plant shutdown was termin-ated at 82.5% powe .2 Event Review The licensee reviewed the documentation concerning the isolation conden-ser vent valves in order to determine how valve V-14-6 was left in the wrong position. On August 10, 1988, the plant was started up following an unplanned outage. During this outage, maintenance was performed on the isolation condenser air operated valves and also on the main steam isolation valves. As part of post maintenance testing, the valves were tested for leakage per local leak rate test procedure 665.5.003, " Main Steam Isolation Valve Leak Rate Test".
From documentation on these work activities, the licens** concluded that misinterpretation of a procedural step led to valve V-14-6 being left in the " closed" positio Since a complete valve lineup was not planned for this system, the licensee had to rely on procedures such as this and administrative controls to return valves to their required position The licensee noted that this error on V-14-6 should have also resulted in V-14-2 (manual vent valve on "B" isolation condenser) being left in the closed position. This was not the case, as, V-14-2 was found "open" on September 2, 1988. The licensee, has to date, offered no explanation
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i The inspecter independently reviewed the documentation available on activities' associated with valve V-14-6. This documentation included tagouts and test documentation from Procedure 665.5.003, " Main Steam Isolation Valve Leak Rate Test".
L A summary of the documented activities on valve V-14-6 is provided in Attachment The inspector concluded that incomplete execution of step 7.72 of Pro-cedure 665.5.003, resulted in valve V-14-6 being left in the closed position. The fact that valve V-14-6 was closed was documented during the August 4-5 performance of Procedure 665.5.003. The inspector deter-mined that this. step was inadequate in the direction it provided to the operator It provided general rather than specific direction to " return all valves to their as found' positions".
The inspector concluded that this procedure did not provide adequate control of valve positions in that valves were operated with no valve lineup to restore and verify their positions. The licensee review of this event came to similar conclusion From the available documentation, the inspector could not identify how valve V-14-2 was returned to the open positio ( The licensee has stated that they will review all local leak rate test
'- procedures for ambiguous steps and provide detailed valve lineups to restore valve position The inspector also reviewed isolation condenser temperatures to determine what indications would be available to indicate that the vent paths were secured. Historical data for the steam line temperatures on the "A" isolation condenser showed no change after September 2,-when the manual vent valve was opened. The inspector concluded that the vent status of the isolation condensers could not definitive?/ be determined from steam line temperature The licensee performed calculations to determine the length of time re-quired for the "A" isolation condenser to be operable after openirg the isolation condenser manual vent valve. These calculations we reviewW oy tne resident inspecto The licensee calculations determined that a vent time of approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> was required to reduce noncondens-able gases to less than 0.003% for restoration of heat transfer capabil-ity and elimination of water hammer potential. In addition, the calcu-lations determined that 1% air by volume reduces the condensing coeffi-cient by a factor of about 2 and that approximately 3.3 cubic feet of gas accumulated in the 22 days the "A" isolation condenser vent valve was closed. This represents approximately 3% of the steam supply line volume. The licensee is performing additional calculations to determine what the heat transfer capability would have been in this situatio In addition, the inspector questioned the bounding assumptions of these
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[ e nu calculations and is awaiting the licensee's response. Specifically, a bounding condition stated that noncondensible gases in the steam line would be removed by a steam purging mechanism that assumed complete mix-ing of the steam and gases. Steam piping downstream of the isolation condenser vent, however, is no in the steam purging flow path. The in-spector questioned if the mechanism for that portion of steam piping is
,more accurately described by a diffusion modeB; and, if' the time for this gas diffusion to be completed would be bounded by the vent time calcula-tion .3 Conclusions As a result'of the valving error on V-14-6, the "A" isolation condenser was performed by the licensee to be inoperable from startup on August 10s 1988, until September. 2,1988, when the condenser was vented. In addition, the "B" isolation condenser was inoperable for valve mainten-ance.from August 23, 1988, until August 28, 1988; and from August 29, 1988, until September 2, 1988. These combinations result in a total period of time when both isolation condensers were inoperable, during the run mode, of approximately 10 days. This is an apparent violation of Technical Specification Upon discovery, the licensee took prompt and effective steps to return the isolation condensers to an operable status, performed required ac-d' tions delineated in the plant technical specifications and made the required notification .0 Emergency Service Water System In Service Test (IST) Rebaselining During this report period, the licensee determined that the baseline data for the Emergency Service Water (ESW) pumps' 52A and 52B differential pressure (dp) were Incorrectly determined in May 1988. ESW pump dp baseline data were used in Surveillance Procedure 607.4.003, " Containment Spray and Emergency Service Water Pump Operability and In Service Test". These baseline data were performed in May as a result of a change in the IST surveillance to establish a new baseline at 3200 gp The licensee became aware of this problem in early August when the IST sur-veil' ries re-fe- ed or +F9 ESW pu,ps exceeded the high action licitt #e* .c T '
dp. In review of this discrepancy, the licensee hypothesized that the pumo discharge pressure was taken in May with the discharge gaugs was isolate As a result of this review and the conclusion that the May baseline data was incorrect, the licensee established a corrected baseline on August During the followup of this event by the resident inspector, the methodology of how the May baseline data was obtained was questioned. The baseline was l- obtained by measuring discharge pressure at both full flow and at a flowrate of 3200 gpm. The engineer in analyzing the discharge pressure at full flow
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neer concluded ~that the discharge pressure observed at 3200 gpm was accurat ~Since the engineer did not compare this observed discharge pressure to the ESW pump curve, he did not realize the value was inaccurate.
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Af ter reviewing _ the methodology of obtaining baseline data, the licensee in-tends to implement the following changes in Administrative Procedure 125, Conduct of: Plant Engineering: 'The basis for all IST baselining shall be documented on Form 125.1 of
' Administrative Procedure ~12 . When establishing a new baseline, the data obtained shall be compared to the pump curve to ensure that the pump's performance has not be de-grade . An. independent verification shall always be require In addition, the licensee had previously identified a weakness in the ESW pump IST surveillance which may potentially result in the isolation of the dis-
. charge pressure gauge when taking data. The licensee intends to incorporate changes in this procec'ere to minimize any error or confusio The inspector had no further questions on the licensee's baselining methodolog *
The inspector, however, is still following up on other aspects of this issu ,0 Diesel Generator Control Circuitry On August.1, a relay contact failure occurred in #1 Diesel Generator during the performance of a load test surveillance. Another contact-related failure
. had occur red five days earlier on July 27. As a result of the relatively short time period in which.these two failures occurred and in light of the fact that many of the contacts in the Diesel Generators are over twenty years old, the inspector raised the question of whether or not these recent failures were indicative of an aging concer The first failure occurred while performing Surveillance Procedure 636.4.003,
" Diesel Generator Load Test", on #1 Diesel Generator. The licensee postulated that a sequence fault associated with the peaking load control circuitry occurred when the "ST" contact had remained temporarily closed. This contact, nowever, woula not have been in the control circuit if an actual emergency start had occurred and therefore would not have prevented the diesel from performing its design functio The second failure occurred while also performing the diesel generator load test. During the normal shutdown sequence, the "UST" contact had failed to open, thereby preventing the trip of the idle speed governor. The backup trip, the "0TT" contact which opens after a longer time delay, opened to trip the diesel generator via the overspeed trip lever. This contact also would not
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have prevented the diesel generator from s.arting on an emergency actuatio t
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The licensee responded to the aging question by pointing out that the failure rate of contacts in the diesel generator were relatively low. This response was confirmed by the inspector through a review of #1 Diesel Generator's ma-terial history records. From the period May 1981, to July 1988, nine contact /
relay replacements in #1 Diesel Generator were identified. The licensee fur-ther pointed out that a preventative maintenance plan had already been ap-proved for the 12R outage. The licensee intends to check the resistances on all contacts in _the diesel generators and compare them with an established threshold value. This check is intended to be an early identification of con-tacts which have a potential for failur The inspector has no further safety concerns on this issu .0 Core Bore Drilling On August 8, the' licensee confirmed through radiography that the drywell shell was damaged by core bore drilling. This damage was incurred while performing work to install a drywell cathodic protection system. The purpose of the drywell cathodic protection system modification is to arrest the drywell cor-rosion rate believed to be caused by water leakage.from the reactor cavity seal area. The installation of this system involved the use of a 4-3/8" core bore tool to gain access to the sandpocket adjacent to the drywell by drilling through'several feet of the concrete drywell shield wall. It is necessary to gain acce.ss to the sandpocket for placement of the anode portion of the
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. system. During the drilling of the second hole, hole #6 in bay #11, the dry-wall was accidentally drilled a total of 2-1/2" at a 45 degree angle to the (~ drywell surface. This distance corresponds to a maximum penetration of 1.81" normal to -the drywell surf ace. The drywell shell thickness in this area is 2.9 inches. This resulted in questions regarding drywell integrit As an immediate corrective action, the licensee stopped all further core bore drilling in the drywell shield wall. A safety evaluation, including calcula-tions was performed to demonstrate adequate drywell integrity to meet design requirements. The safety evaluation was reviewed by NRC Region I Specialists and found to be acceptabl At the end of this report period, the core bore drilling remaired suspende The licensee is continuing to review this event to determine proper corrective actions necessary to recommence core bore drilling and to identify the root cause of this event. The resident inspectors will continue to follow the i1censee's activities in snis are .0 Drywell Airlock Local Leak Rate Test On August 8,1988, the inspector became aware that a leak rate test of the drywell airlock had failed, troubleshooting / corrective actions were being taken, and the test was being conducted at a test pressure of 10 psig. This test was being performed in order to demonstrate primary containment integrity prior to pressurizing the reactor during plant heatup. Subsequently, a suc-cessful test was conducted using a test pressure of 10 psi m
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The.same day the inspector reviewed Procedure 665.5.005, "Drywell Airlock Leak Test",'for the required test pressur This procedure allows the test to be performed at either 10 psig or 35 psig (corresponds to accident pressure of J 10 CFR 50 Appendix J), and directs that the local leak rate test engineer I should be contacted to determine which test pressure was required. The in- {
spector also reviewed plant technical specifications which specify that the drywell airlock be tested at a pressure of 10 psig. Since plant technical specifications indicate a test pressure of 10 psig, and since this was the test pressure being used in the field, the inspector concluded that this was the test to be used to demonstrate primary containment integrity. The in-spector was concerned that primary containment integrity would not be shown per the requirements of 10 CFR 50, Appendix J.
l The inspector contacted the local leak rate test engineer and indicated to him that in order to conform to the requirements of 10 CFR 50, Appendix J, a 35 psig test would be required. The local leak rate test engineer subse-quently directed that a test be performed at 35 psig, and this test was satisf actorily completed before reactor startup and heatup to norma? operating-pressure. Once the test was performed at 35 psig, the inspector concerns were satisfie After the plant was pressurized to normal operating pressure, the licensee performed a drywell entry and inspection. After the inspection and use of
,' the drywell airlock, it was again tested at a pressure of 35 psig. The in-spector noted that a Technical Specification Change Request had previously been submitted by the licensee in order to more clearly specify the testing requirements on the drywell air loc The inspector had no further questions regarding this tes .0 Quarterly Emergency Drill The inspector witnessed portions of the quarterly emergency drill conducted on August 23, 1988, and attended the licensee's criticue following the dril During the drill which involved two separate release points from two different elevations of the facility, the technical support center offsite dose computer was unable to perform the calculations. The release calculations were appro-priately performed Ly the En:ergency Offsite Facility by performing a separate q calculation for each release point and adding the results. This was discussed witn tne Raciolt.gical Control Director who stated that they were contemplating increasing the computer's capacity so that separate release calculations could be conducted simultaneously. Presently no requirement exists to have the capability to perform a simultaneous computer calculation for sepmte release points, but the licensee considers this an improvement to their c m t111 tie The drill critique seemed to be beneficial for the participants anc was con-structive in determining problem areas. The inspector had no concern { l
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8.0 Fuel Rod Defects 1 The licensee was informed by the new fuel fuel rod vendor that approximately "
69 of the 220 new fuel assemblies for the upcoming 12R refueling outage could'
have manufacturing defects in one or nore rods of each assembly. The defects have been characterized preliminarily as cracks forming on the outside wall of the fuel rods and propagating towards the inner wall. Presently the lic-ensee plans to reconstitute fuel bundles to support the refueling effort and send the remaining bundles to the vendor for further examination. The vendor currently has determined that the potential defects do not represent a safety concern and does not plan a 10 CFR 21 report. The inspector will continue to follow the licensee action .0 MSIV Closure Test On August 18, 1988, the inspector noted that during the conduct of a 5% Main Steam Isolation Valve (MSIV) closure test on NSO4A, the annunciator, main steam valves off normal, was received indicating that the valve is less than 90% full open. The inspector discussed this with the control room and later operations management to determine if the significance of this alarm was ap-propriately considered. The inspector's concern was that potentially a reac-tor protection system (RPS) input could be malfunctioning. If the annunciator was valid and the valve had traveled 10% then a half scram should have been received. The operators were also concerned about this and attempted to find (-' an electrical print depicting the circuitry coming from the MSIV limit switch but could not find the appropriate drawing in the control room. The following morning operations management and electrical maintenance personnel reviewed the circuitry drawing obtained from the electricians and determined that the microswitch for the annunciator contact was dirty and required burnishin This was performed later that day and the RPS input verified to be operabl During the' time from the initial valve testing to the subsequent determination the following day, the control room had not clearly determined that the MSIV RPS input was functional. The licensee stated that shift management had de-termined that the problem was only associated with the anriunciator and not the RPS input, but without having performtd a test to verify operability, it is difficult to clearly determine RPS input operability. The inspector had nc other concerns other than the technical pursuit and resolution of the problem by the operating shif :u.0 Haalation Protection 10.1 H(ch Radiation Area Door Unlocked On August 30, the licensee discovered that a locked high radiation area door was left opened and unattended. The fill aisle door, HR 38, which is located on the 23' elevation of the new radioactive waste building was left opened approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />. The licensee's initial correc-tive actions were to verify the fill aisle unoccupied and to close and lock the fill aisle doo (
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f The radiological-investigative report on this occurrence ascertained that a contractor was responsible for leaving the fill aisle door unlocke The licensee _ intends to conduct a critique of this occurrence. The in-spector is satisfied with the immediate corrective action. A future in-spection has been scheduled to review this and othar events to determine if further NRC action is appropriat This item is unresolved (50-219/
88-23-01).
10.2 Augmented Offgas Door Ooen During a tour of the facility, the inspector found a double equipment access door open in the augmented offgas building (A0G). The inspector discussed this with a contract supervisor and worker and was informed that they had.obtained permission from the radwaste operations supervisor to open the door. The inspector concern was the potential for a ground level release from the A0G building. The A0G building operates at a slightly negative pressure, but the inspector was concerned for the-
, potential for a release considering recent operational experience with the A0G building. This concern was discussed with radiological control (RADCON) management who agreed with the inspector's concern and felt that !
they should have been consulted on opening the doors. The licensee reviewed this and could not determine that anyone had given permission to the contractors to open the door. The licensee plans to exercise
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10.3 Disposal of Radioactive Material l
'On August 26, 1988, the inspector found wet trash from the reactor building spread in the sun to dry outside the radwaste shipping area, but inside the fenced in aret of the radiological control area (RCA). !
In discussion with RADCON the inspector learned that the wet trash from cleaning a seawater side of a heat exchanger had not been frisked out of the RCA prior to drying it in the sun. RADCON stated that it was their policy to frist out any trash before it is reinoved from the turbine building or any part of the RCA. RADCON management discussed this with the personnel involved, gathered the trssh from the RCA yard and properly ftisked it. The trash was found to be within acceptable limits for re-lease outside the RC The inspector had no further concern ]
10.4 Radioactive Control Area Entry During this period, company personnel were found to be using the reactor i building 23' elevation as a passageway to oMain self-reading dosimetry (SRD) prior to entering the RCA. The reactm building comprises a por-tion of the RCA where general radiation levels are about 1-E mrem /h The licensee had recently relocated the dosimetry issue facility and as a result company personnel were unaccustomed to the new location, but this does not provide justification for entering the RCA prior to SRD issue. The licensee promptly posted personnel, including a senior member I
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of the' management staff, to stop this unauthorized passage through the RCA and clearly marked the proper path to access the dosimetry issue facility.- Further NRC review of this occurrence has been schedule .5 General During entry to and exit from the RCA, the inspectors verified that pro- ,
per warning signs were posted, personnel entering were wearing proper l dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional- l and in calibratio Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate. The inspector observed activities in the RCA to verify that personnel complied with the requirements of applicable RWPs and that-workers were aware of the radiological conditions in the area. No un-acceptable conditions were identifie .0 Plant Operational Review i
11.1 Reactor Start Up Facility-startup activities during the period August 9 through August 11, 1988, were reviewed by a region-based inspector. Plant startup ;
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activities on August 9 were delayed pending the completion of a safety evaluation (SE) for the damage done to the drywell during the work as-
.N sociated with the installation of a cathodic protection system. The SE l was completed at approximately 1:00 p.m. and sent to Region I for revie Region I completed its review of the SE at approximately 3:00 p.m. The remaining holdup for plant startup was then the SE for operation with the d.c. motor associated with the rotary inverter which powers instru-ment panel No. 3 being inoperable. Part of the rotary inverter evalu-ation was the performance of several tests to verify power to the in-strument panel would successfully swap to alternate power from a trand-former should the a.c. power to the rotary inverter be lost. The in- ,
spector observed portions of this testing, teoth at the ir,verter and in !
the control roo The testing was performed in accordance with an approved procedure, dis-cussed prior to being performed and had compensatory measu-es established in the event unacceptable conditions developed. The initial testing was unsatisfactory and 3 temporary variation had to be initiated in order to achieve acceptable results. The licensee's actions in determining acceptability of operation with the d.c. motor of the rotary inverter inoperable were found to be acceptabl Startup was commenced at 2:17 a.m. on August 10, 1988. Criticality was !
achieved at 3:47 a.m. The criticality occurred more than 1% delta K sooner than expected by the estimated critical position which had been calculated prior to startup. The reactor was made subcritical and a ( review of the potential reactivity anomaly was reviewed by the Onsite !
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Core Group, the Onsite -Independent Review Grcup and by Systems Engineer-ing in Parsippany. The error in the estimated critical position (ECP)
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was. determined'to have been due to the use of an incorrect reactivity bias in the calculation of the ECP.
1 Following the resolution of the ECP problem the reactor was again made I critical at 5:02 p.m. on August 10, and the 1000 psi inspection started at 4:50 p.m. on August 11. Some additional difficulties were experienced during the startup. These included IRM problems, a condenser vacuumL breaker problem, and Rod 22-03 position indication problem and subsequent inability to withdraw 22-03. The operators' actions in resolving these issues, as they occurred, were acceptable. The inspectors will review licensee long term corrective actions'in a future inspectio Control room observations were made to veri.fy:
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Proper manning,
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Operator adherence to procedures,
-- Acceptable status of annunciators for the plant condition and operators' response to annunciators, c
-- Ad5arence to technical specification requirements, (. .
-- Shift turnovers,
-- Overall control of activities in progress,
-- And, control rod withdrawal in accordance with technical specifica-tion requirements for an inoperable rod worth minimize No unacceptable canditions wers identifie .2 Operational Events The inspector reviewed details associated wf th key operational events that occurred during the repcrt period. A summary of these inspection activities follow . Hot Weather Operation As a result of a regional request the inspectors reviewed the effects on plant operations which resulted from this summer's prolonged heat wav For a portion of the heat wave, July 11, 1988, to August 12, 1988, the plant was shut down and unaffected by the hot weathe .
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The mostLsignificant effects on plant operation resulted from high intake canal temperatures. High intake temperatures made it necessary to operate 3 vs. 2 turbine building closed cooling water heat exchangers and 2 vs. I turbine lube oil coolers for some period of tim ; The high circulating water intake temperatures caused certain State Environmental, Discharge Permit (EDP) limits to be reached on several occasions. There are EDP temperature limits placed on both the discharge canal temperature (97 degrees F) and on the circulating water discharge (106 degrees F). On three days these temperature limits were reached which either halted power increases or forced power reductions to be taken in order to preclude exceeding EDP. temperature limits. On August 13, the power increase. from the startup of August 10 was temporarily halted due to circulating water discharge. temperature. During the day on August 14,-power was reduced approximately 18% and on August 15, power was reduced by.approximately 13%. The reductions were taken to keep temperatures within the limits of the ED The discharge canal temperature did exceed its limit of 97 degrees on August 15 when a dilution pump tripped. Before f
the dilution pump was restarted temperature reached 97.9 de-grees and remained above the limit for approximately 15 minute (' The licensee notified the state of New Jersey of this conditio Under certain emergency load conditions these EDP limits can be increased, but these conditions were not exceeded this summe Inspectors reviewed the station Final Safety Analysis Report and noted that the design cooling water temperature for the containment spray / emergency service water heat exchangers is 85 degrees. During the summer canal temperature did exceed 85 degrees. The licensee is reviewing this condition for deportability.
I Overall, no significant operational problems were experienced as a result or tne nign temperature The ability of the heat
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exchangers to perform their design function with injection tem-perature greater than 85 degrees is unresolved pending comple-tion of licensee evaluation and inspector review (50-215/88-23-02).
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11.2.2 Operational Events As an result of the startup problems incurred with some equip-ment,' the inspector reviewed the' licensee's program to identify rework problems and implement corrective action. During the startup from 11-U-7, the inspector identified the following equipment that had been worked on by the licensee:
- Safety relief valve thermocouple on safety valves NR28M and.NR28 * Interm * ate range monitors 12 and 1 * Hydraulic control accumulator 22-0 * Recirculation pump "C" controlle * Reactor feed pump "B" motor bearin The licensee identified these equipments and others as examples of rework. In addition the licensee held a critique of the 11-U-7 outage including rework problems, which the inspectors attended. The critique recommended invoking the rework proce-
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dure to determine root cause. The inspectors will review
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.( results of the licensee's root cause determination .
The licensee has a Maintenance Construction and Facilitie (MCF) procedure in place to identify rework and recurring maintenanc This procedure A000-ADM-7000.01, Control of Rework and Recurring Maintenance, has as its purpose to estab-lish a process for identifying rework and recurring maintenance and taking steps to reduce it. This procedure specifies that when rework or recurring maintenance is identified it is docu-mented on either a Rework Identification and Corrective Action Report or on a Recurring Maintenance Repor Discussions with the licensee and a review of records shows that since the procedure was issued on March 1, 1987, six Pework ard Corrective Actient Dero *+: and one R?cu*r4n: Mt4n-tenance Report have been prepared. Of these six reports only one has been completed to where the corrective action completed section has been signed of Additionally, the procedure requires an annual review of rework activities and the preparation of a report to the MCF Site Director addressing rework, trend, evaluation of rework as it impacts plant availability, etc. This annual review has never I been performed.
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A number of people having responsibilities associated with the 'l Control of Rework and Recurring Maintenance Procedure indicated that in general the procedure was not being fully utilized and was not doing an adequate jo The licensee indicated there are redundant methods which:in-
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directly address rework, recurring maintenance, and correctiv actions. These are LER's,, the extensive use of critiques, and varinus computer sort Recurring maintenance activities and the use of A000-ADM-7100.01 was audited by QA in October, 1987. This audit indicated that the~ procedure is not frequently implemented. At that tim maintenance had initiated five Rework Reports and one Recurring Maintenance Report. The Audit Report concluded "MCF is cog-nizant of the problems with the implementation of this program and is taking steps to resolve.the problems." This assessment
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still appears to be accurat During the exit meeting the licensee indicated that a Mainten-ance, Construction and Facilities self assessment had come to the same conclusions as the inspectors and stated that action
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items had been issued to correct identified deficiencie ,
j 11.2.3 Emergency Service Water pumps During testing of the ' Containment Spray / Emergency Service Water (ESW) System II on August 16, 1988, ESW pump 52C had excessive seal leakage. The pump was declared inoperable. Subsequently, during inservice testing (IST) of ESW oump 520, pump differen-tial pressure was in the high " required action-range". The licensee also declared this pump inoperable, placing the facility in a 7-day limiting conditions for operation Licensee review of the test data on ESW pump 520 indicated that the pump differential pressure obtained during the test was significantly displaced from.the recorded pump performance curve. Because of this, the licensee performed a calibration chack on tha cump discharge gauce and the instrumer.t s esire lines on the flow indicator were "back flushed" into the pro-cess pip The IST on ESW pump 520 was performed again on August 18, 1988, with acceptable test result Subsequently, the pump was de-clared operable. The licensee disassembled and inspected ESW pump 52C and concluded that the pump should be replaced. This was accomplished, ar.d ESW pump 52C was returned to service on
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August 19, 1988. The inspector noted the ESW pump 52C had j l-(-
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+ previously been replaced in 1984. The inspector will review ESW pump maintenance history and performance'in a future in-spectio . 11. Hydraulic Control Units
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Inspectors noted that'three hydraulic control units were oper--
ated for a period of time-greater than one hour with a'ccumula-tor pressures below the low pressure alarm. This' condition-
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was annunciated in the control room and developed when the
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nitrogen charging hose malfunctioned., The-licensee subsequently-repaired the nitrogen charging' hose and recharged the accumu-lators. The_ licensee will be. reporting this event-via th licensee event reporting syste .2.5- MSIV Surveillance Testing While the licensee was concerned about the MSIV limit switch problem discussed in paragraph 9.0, the daily.5% MSIV closure- q test _ surveillance was not performed at the . scheduled tim The test was subsequently performed af ter completion of. elec- '
trical maintenance approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the scheduled time. The licensee currently has no written definition of ,
, " daily" surveillance requirement. Operations has in the pasti 3~
interpreted " daily" as anytime within a 24-hour day. This~
potentially could allow dailies to be conducted _almost'48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> apar In practice though this'has not been the case and.the licensee is timely in conducting daily surveillences. In the past a missed weekly surveillance led to a licensee effort _to clarify periodic surveillance requirements. This had not been-accomplished when this surveillance was performed late. Pre-sently the licensee intends to specffy in writing the length of periodic surveillance requirement . Reactor High Pressure Scram Surveillance "
The inspector reviewed the results of recent rurveillances on RE03A, high pressure-scram instrument and RE15's, isolation condenser initiation and recirculation pump trip on high pres .
sure. One of four RE03A had drif ted high and was found at '1070 psig while the technial specification limit is $1060 psi Three of the four RE15's had drifted high out of specificatio ,
The licensee currently plans on replacing these pressure '
switches with an analog trip upgrade system in the 12R refuel- .
ing outag RE03A previously was the cause of concern due to l
.microswitch contact resistance coupled with vibration problems (see Inspection Report 88-04). The inspector will continue to follow the performance of these pressure switche ;
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11. Acoustic Monitor During this report period the acoustic monitor for NR28M and the thermocouple for NR28H and M were declared inoperable
.The inspector verified that appropriate actions were taken in
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on adjacent acoustic moniters NR28J and N.accorda NR28M acoustic was bypassed by the licensee to eliminate the constant alarm in the control room. The NR28M acoustic monitor may be indi-
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cating a minor. steam leak associated with the safety relief valv The licensee has not detected any other containment parameter increase that would be indicative of a steam lea Prior to. shutdown for the MSIV repair outage in July,1988, '
the NR28A acoustic monitor had exhibited similar chara tic insulation and steam cutting of the NR28A flange .
licensee repaired prior to startu to closely monitor the' acoustic systems.The licensee continues 11.3 Control Room I i
which time the following documents were reviewed: Routin
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Reactor Building and Turoine Building Tour Sheets;
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Standing Orders; and,
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Operational Memos and Directive .4 Facility Teurs Reutir.e tours of the facility were conducted by the insporters to mcke an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirements. The following areas are among those inspected:
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12.0 Monthly Surveillance Observations On August 5, 1988, the inspector' observed the complete performance of Sur-veillance Procedure 609.4.001, " Isolation Condenser Valve Operability and In Service Test". This surveillance tests the opening and closing times of isolation condenser isolation valves. The inspector verified the surveillance-met technical specification requirements, the test results were within the acceptance. criteria, the test instrumentation were within their calibrated periodicity, approval granted to conduct the test and review of surveillance-by the Group Shift supervisor, surveillance prerequisites were completed and
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appropriate electrical safety precautions were taken. Further management review of the surveillance was not verified because the procedure as of Sep-tember 16, 1988, was still in routing. The inspector witnessed Surveillance Procedure 609.4.001 for both the "A" and "B" isolation condensers on September 2, 1988. This surveillance was conducted to verify isolation condenser operability after entering the limiting conditions for operations discussed in paragraphs 1.0 and 2.0. No unacceptable conditions were identifie .0' Observation of Physical- Security 13.1 On August 4, 1988, after cleaning and loading a firearm, a security guard inadvertently discharged the firearm. This event occurred in the lunch
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room of the' main guardhouse, outside the site protected area. No per-sonnel injuries occurre The inspector discussed this event with re-k<' gional security inspectors, including a review of the sequence of event The inspector concluded that licensee actions were timely and effective in response to this event. No concerns were identifie .2 During daily tours, the inspectors verified that access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded and that isolation zones were free of obstructions. The insoertors e/amined vital area access points tc verify thtt they were properly locked or guarded and that access con-trol was in accordance with the security pla s0 Backshift Inspection NRC inspections of licensee activities on backshifts were conducted on the
' ell;wiac 4++-c caturday. Aunust 6,199P and r f rf sv. Ser.tember 2. 193E 15.0 Exit Interview A summary of the results of the inspection activities performed during this report period were made at meetings with senior licensee management at the end of this inspection. The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was include .
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- SUMMARY OF ACTIVITIES VALVE V-14-6 DATE- ACTIVITY July 13 Valve V-14-6 tagged in the " closed" position for maintenance acti-vities. -No "as found" position is recorded for tagout July 22 ' Tagout cleared, V-14-6 returned to the "open" positio July 31 Performed 665.5.003,. Section.10:
-- Step 10.2: Documented V-14-6 pretest position as "open".
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Step 10.5: Directed V-14-6 to be opened. Valve was not
. repositione Step 10.18: Directed valves to be returned to " pretest posi-
tion". This would be "open" for V-14-6. Valve .
V-14-6 not repositioned during this tes August 2 Performed 665.5.003, Section 10:
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Step 10.2: Documented V-14-6 pretest position as "open".
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- Directed V-14-6 to te opened. Valve was not
.( , repositione Step 10.18: Directed valves to be' returned to " pretest.posi-tion". This'would be "open" for V-14-6. Valve V-14-6 was not repositioned'during this tes August 3 Performed 665.5.003, Section 7:
Step 7.12: Documented the pretest position of V-14-6 as "open".
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Step 7.13: Closed V-14- Step 7.37: Opened V-14- '
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Step 7.52: Closed V-14- Step 7.72: Directed valves to be returned to their as-found positions. This would be "open" for V-14- A.rgust 4-5 Performed 665.5.003, Section 10:
-- Step 10.2 Documented V-14-6 pretest position as "closad"
-- Step 10.o: Directed V-14-6 to be opened. Valve repositioned to the open positio Step 10.18: Directed valves to be returned to pretest positio This would be " closed" as documented in Step 1 September 2 Valve V-14-6 found " closed".
Valve V-14-6 repositioned to "open".
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