IR 05000277/1990010
| ML20055C879 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 06/15/1990 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20055C877 | List: |
| References | |
| 50-277-90-10, 50-278-90-10, NUDOCS 9006250319 | |
| Download: ML20055C879 (34) | |
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U. S. NUCLEAR REGULATORY COMMISSION ;
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REGION'I ,
n Docket / Report N /90-10 License Nos. DPR-44 -
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. 50-278/90-10 DPR-56 1 Licensee: Philadelphia Electric Company Peach Bottom Atomic Power Station *
P. 0.! Box 195 '.
Wayne, PA 19087-0195 .
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Facility Name:- _ Peach Bottom Atomic Power Station Units 2 and 3'
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Dates: April 3 - May 15, 1990 '
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Inspectors: J. J. Lyash, Senior Resident Inspector ,
R. J. Urban, Resident Inspector- t L. E. Myers, Resident Inspector-G. Y. Suh, Project Manager,.NRR V.- D. Thomas, Senior Technical Engineer, NRR 1
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Approved By: Ai -6/id'10 L. T. Doerfleinlj Chief "Dats Reactor Projects Section 2B ;
Division of Reactor. Projects
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Areas Inspected:
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Routine, on-site _ regular, backshif t and deep backshift inspection of accessible-portions of Units 2 and 3. The inspectors' reviewed operational safety,
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-radiation protection, physical security, control room activities. licensee events,: surveillance testing, engineering and technical support activities, and maintenanc !
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Executive Summary Peach Bottom Atomic Power Station Inspection Report 90-10 Plant Operations: Difficulty with establishing and maintaining the_ correct degree of alterrex exciter enclosure air cooling, the inoperability of a control room annunciator, and less than effective control. room communications contributed to exciter bearing damage, resulting in the need to initiate ;
a plant-shutdown (Section 2.1). ;
2 .- Licensee operability, reportability and emergency classification decisions and actions in response to a series of inoperable Rosemount transmitters, and loss of a Unit- 3 battery and charger displayed a safety. conscious-approach-(Sections 2.2 and 2.7).
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Maintenance and Surveillance: Inadequate pre-job maintenance planning and evaluation in support of !'
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replacement of a voltmeter associated with a safety-related Unit 3 battery charger led to the inoperability of the charger and battery, and !
declaration of an Unusual Event (Section 2.5, UNR 90-10-01). ;
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- During the inspection period the licensee identified 3 instances of missed f surveillance tests (ST). During the past year 11 other Licensee Event i
.% ports have been issued due to failure to. perform STs when required, !
This may be indicative of a continuing _ program weakness (Section 4.2, UNR j 90-10-02).
"i Engineering and Technical Support: !
t 1.- Licensee-installation and post-modification acceptance testing for '
Rosemount transmitters did not contain adequate provisions to ensure ,
maintenance of the instrument environmental qualification (EQ). '
Additionally, the engineering process for updating the EQ equipment list and calibration documents following some plant modifications did not j ensure-that changes were incorporated in a timely manner (Section 2.2). ,
i Although the Technical Specification limf ts for minimum acceptable battery i voltages were identified as inadequat during 1989, analysis and o establishment of appropriate limits, a.id communication of these limits to i the operating shif ts, was not completed in _ a timely manner. This resulted '
, in delays- in the control room staff's assessment of battery operability
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i during the loss-of-charger incident of May 11 (Section 2.5, UNR 90-10-01). *
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Assurance of Quality The licensee's QA organization identified the inadequate battery voltage limits discussed above and issued a Corrective Action Request (CAR).
However, the CAR was closed without verification that actions needed to resolve the issue had been completed (Section 2.7, UNR 90-10-01). The licensee has implemented an independent safety-related fastener testing program to ensure that procured fasteners meet the appropriate specifications (Section 3.1).
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TABLE OF CONTENTS Page 1.0 Plant Operations Review (71707)................................... 1 2.0 Follow-up of Plant Events (93702, 40500)............................ 1 2.1 Unit 2 Manual Reactor Scram Due to High Main Generator Exciter Vibration.............................................. 1 2.2 Initiation of a Unit 3 Shutdown Due to Improper EQ Maintenance of Rosemount Transmitters......................... 3 2.3 Control Room Emergency Ventilation System Actuations.......... 5 2.4 Unit 2 Reactor Water Cle?nup System Isolation During Surveillance Testing.......................................... 6 2.5 Unit 3 Declaration of an Unusual Event Due to the Inoperability of One Division of DC Power..................... 6 2.6 NRC Notification of Degraded Emergency Service Water Capability for Unit 2......................................... 9 3.0 Engineering and Technical Support Activities (37828, 25027, 92702, 37700,37701)....................................................... 9 3.1 Licensee Response to NRC Bulletin 90-02, " Loss of Thermal Margin Caused by Channel Box Bow"............................. 9 3.2 NRC Temporary Instruction 2500/27, " Fastener Testing to Determine Conformance With Applicable Material Specs"......... 10 3.3 NRC Temporary Instruction 2500/20, " Inspection to Determine Compliance With ATWS Rule, 10 CFR 50.62"...................... 11 4.0 Surveillance Testing Activities (61726, 71707). . . . . . . . . . . . . . . . . . . . . . 12 4.1 Routine Observations.......................................... 12 4.2 Licensee Identified Surveillance Test Completion Deficiencies.................................................. 12 5.0 Maintenance Activities (62703,71707).............................,.. 14 5.1 Routine Observations.......................................... 14 5.2 Unit 2 HPCI Turbine Reversing Chamber Hold-down Bolts......... 15 6.0 Radiological Controls (71707,83750)................................ 16 7.0 Physical Security (71707)........................................... 16 7.1 Routine Observations......... ... ............................ 16
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7.2 Discharge of a Firearm in the Owner Controlled Area. . . . . . . . . . . 17 8.0 Licensee Management Changes......................................... 17 l
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TABLE OF CONTENTS (continued)
Page 9.0 Review of Licensee Reports (90712, 90713, 92700).................... 18 10.0 Previous Inspection Item Update (93702),............................ 20 ,
11. 0 Ma na g eme n t Me e ti n v. [ i'si'03, 30702 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 11.1 NRC Inspector General Plant Tour............................... 21 11.2 Preliminary Inspection Findings................................ 21 11.3 Management Meetings Conducted by Region Based Inspectors....... 2 ,
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DETAILS 1.0 Plant Operations Review The licensee completed a scheduled Unit 2 mid-cycle maintenance outage on March 29, 1990; however, emergency service water system testing delayed placing.the mode switch to refuel for completion of outage testing until April 1 Reactor startup began on April 17. On April 21 a manual reactor scram was initiated in response to high main generator exciter vibratio Startup was begun on April 28 and 100% reactor power attained on May The reactor remained at 100% power through the end of the report perio !'
Unit 3 began the period at 100% power. Due to high copper concentration in the reactor feedwater and problems with maintaining acceptable condenser vacuum, power was reduced on May 1 and held at 85% power for the remainder of the perio A detailed chronology of plant events occurring during the inspection 'l period is included in Attachment j i
The inspector completed NRC Inspection Procedure 71707, " Operational l Safety Verification," by direct observation of activities and equipment, -l tours of t.he-facility, interviews and discussions with licensee personnel, j independent verification of safety system status and limiting conditions for operation, corrective actions, and review of facility records and logs. The inspectors performed 124 total hours of on site backshift time, including 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of deep backshift and weekend tours of the facility, i
2.0 Follow-up Of Plant Events l I
The inspector evaluated licensee response to plant events to ensure that !
prompt analysis was performed, reasonable root causes were identified, an l appropriate corrective actions were implemented. In each case, the j inspector reviewed applicable administrative and technical procedures, /
interviewed personnel and examined the affected systems and equipmen ;
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2.1 Unit 2 Manual Scram Due to High Main Generator Exciter Vibration On April 21, 1990, at 1:52 p.m. Unit 2 was manually scrammed from 21%
power in preparation for breaking condenser vacuum to inspect the main turbine bearings. Following the scram reactor water level dropped to 0 inches (172 inches above the top of the fuel) due to shrink caused by the ,
- void collaps A primary containment isolation system (PCIS) group II l L and III actuation resulted. All systems performed as expected and the l PCIS group 11 and III isolations were rese The licensee informed the NRC via ENS at 5:24 l
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Unit 2 startup from the mid-cycle maintenance outage began on April 17, 1990. At 2:00 a.m. on April 21 the main turbine generator was synchronized to-the grid and reactor power was increased to 30%. At 6:00 a.m. the chief operator (CO) observed that the alterrex exciter stator and air temperatures were increasing as recorded on temperature recorder TR-2411. He attempted to increase cooling to the stator, but no cooling water supply valve response to the change on the controller was noted. Annunciator " Generator Stator Coolant or Hydrogen Seal Oil Trouble" subsequently alarmed. At 6:50 a.m. a plant operator (PO) was dispatched to local panel DO C08 The local panel alarm for "Alterrex Air Temperature High" was alarmin The PO was directed by the chief operator to check the alterrex cooling water inlet and outlet valves to the alterrex air coolers. The P0 discovered the "B" alterrex air cooler service water valve, HV-2-30-21015, apparently closed. Operating procedures list these valves as locked open; howeve the outlet valves had a locked valve request tag attached with the instruc-tions that the valve position was to be five turns closed from the open position. The PO was instructed by the C0 to match the mispositioned "B" outlet valve to the correctly positioned "A" outlet valve. The alterrex air temperature rapidly decreased to 60 degrees Fahrenheit (F). The Unit 2 reactor operator was not made aware of the changes made by the chief operator to the alterrex exciter air cooler temperatures and the temperature trend was not closely monitore At 7:30 a.m. the annunciator for " Turbine High Vibration" alarmed and reset several times. Vibration recorder VR 2402 bearing No.12 (outboard altertex) and No. 11 (inboard alterrex) were observed by the operator to be about 9.5 and 7.5 mils vibration respectively, and appeared to be decreasing. Alterrex air temperature had been decreasing since the cooling water adjustment. In fact vibration was substantially higher ano reading
'tf scale. The recorder data was misinterpreted by the operator, lc 4
'nutes turbine high vibration and turbine bearing metal high temperawre annunciators alarmed and bearing temperatures for bearing Nos. 11 and 12 increased above the 175 degrees F alarm setpoint. At 7:35 a.m. the Shift Manager directed that the main turbine be tripped. House loads were transferred and the main turbine tripped at 7:42 Reactor power was decreased to 21%.
The licensee reviewed the information and decided that an inspection of the main turbine bearings was necessary, which would require breaking condenser vacuum. Therefore, a shutdown of the reactor was needed and was
' accomplished by manual scram. Main turbine bearings Nos. 11 and 12 were dissembled to. inspect for damag Each bearing showed wipe of the bearing material. The bearings were replaced, and the turbine lube oil system was flushed. Alignment of the main turbine shaft required replacing shims in the alterrex excitor bed. Alignment was successfully completed and the unit restarted on April 2 __ _______._______ _ _ _ _._ -. - _ _ ___-..----- .
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Control room recorders indicate that the exciter air temperature had been elevated for an extended period of time peaking at about 130'F. An annunciator specific to this air temperature on the reactor operator's board should have alarmed at 113 degrees F. However, this alarm was not functional. The alarm response card directs the operator to investigate and to trip the generator if temperature exceeds 122 degrees F. The alarm
.which was received by the C0 should also have been set at 113 degrees F but was found to have been set at about 128 degrees F. The licensee recalibrated the alar Follow-up evaluation by the licensee indicated that the valve in question had been partially open. Additional opening by the P0 resulted in rapid overcooling of the alterrex air space. This rapid and uneven cooldown of the exciter shaft and bearings caused increased vibration and bearing clearance and resulted in bearing failur In summary, the event initiator appears to have been inadequate control of the alterrex exciter air cooler' outlet valve The event was complicated by an inoperable annunciator, a miscalibrated annunciator and poor control room communication. The licensee initiated a root cause analysis which will identify contributing factors and corrective action .2 Initiation of a Unit 3 Shutdown-Due to Improper EQ Maintenance of Rosemount Transmitters
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During a routine tour of the Unit 3 reactor building a member of the licensee's Independent Safety Engineering Group noted an excessive gap between the body and side cover of a Rosemount dif ferential pressure (dp)
transmitter. The condition was brought to the attention of Shif t Management and an investigation initiated. The 2 transmitters in question, LT3-2-73A and C, provide the reactor water level initiation signal for the ECCS and were found with their electronics side covers finger tight. To maintain the environmental v alification (EQ) for these instrun,ents each of the 2 side covers, elecurf .ics and terminal, must be torqued to 200 in-lb The instruments were declared inoperable on-May 3, 1990. Technical Specification (TS) Table 3.2.B requires that with less than the minimum number of operable channels per trip system, the trip system shall be placed in the tripped condition or the reactor shall be placed in the cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee subsequently torqued the covers to the appropriate value and exited the Action Statemen In response-to the identification of the deficient condition the licensee inspected all 116 EQ Rosemount transmitters during the period of May 3 -to May 4, 1990. Seven additional Unit 3 transmitters were found to have covers that were inadequately torqued. All Unit 2 transmitters were acceptable. The loose covers were torqued to 200 in-lbs upon identifi-cation. One transmitter, PT 3-10-100A, Drywell Pressure, could not
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initially be torqued because the installed configuration wouldn't allow placement.of the wrench. The licensee declared this transmitter inoperabl Shift Management again reviewed the' action specified in TS Table 3. As a conservative meacure TS for the systems receiving an initiation signal from the instrument were also reviewed and found to require similar action However, the individual system Action Statements indicated that a shutdown should be initiated and the reactor placed in the cold condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Based on this, the control room staff began a plant shutdown on May 4 and informed the NRC via ENS of the initiation of a shutdown required by TS. The transmitter cover was tightened prior to any significant power reduction and the Action Statement was exite The licensee's maintenance organization initiated an evaluation of the cause for the loose covers. The inspector reviewed the preliminary results of this evaluation and discussed them with the cognizant licensee staff and management just prior to the end of. the inspection period. The Rosemount transmitters have been affected by 3 major modification Modification 1419 initially installed the EQ model 1153 instruments, Modification 5069 replaced the instrument electron k ; package in the 1153 to resolve problems with oversensitivity, and Msdificatnn 1891 upgraded unqualified instruments required to be EQ by Regulatory Gaide 1.97 by replacing them with 1153 models. Modifications 1419 and 5069 are ;
complete; Modification 1891 is not complet F During modifications, craftsmen would be required to remove the instrument terminal side cover during installation and, following the vendor manual instructions, torque the cover on reinstallatio The electronics cover ;
would not be disturbed during installation. Post-modification testing for-instruments installed under the 3 modifications discussed above was accomplished by performance of the associated routine calibration procedure The procedures originally included steps to torque both covers. The Unit 2 instruments were tested using this version of the procedures. As a result all covers were properly torqued on Unit 2. Prior to inlementing '
the modifications for Unit 3 the procedures were revised to torque the covers only if they were disturbed during the calibration. Generally, neither cover would be removed during a routine calibration, so no baseline configuration was established for the Unit 3 instrument electronics side covers. This same deficiency would affect instruments installed as replacements due to inservice failur The licensee believes that the high percentage of Unit 3 covers with
. proper torques is likely due to shipment of the instruments from Rosemount in that condition. Of the 8 instruments found with loose electronics side covers 4 were installed by modification and 3 were installed as replacements for failed instrument None had their electronics side cover torque verified. The remaining instrument with a loose electronics side cover could not-be checked with a standard wrench, and may not have
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been verified because of its inaccessibility. The licensee stated that the -
applicable instrument calibration procedures will be revised to require torquing both covers if the procedure is being performed following initial installation or replacemen The single instrument found with the terminal side cover loose had been installed under modification 1891. Following installation, additional work was performed under MRF 8910173 which disturbed the terminal side cover. The instrument, although upgraded to EQ via the modification, was not listed in the site EQ report and the calibration sheet did not indicate that it was EQ. The MRF also stated that the instrument was not EQ-(designation on the MRF would be based on review of the EQ 'ist and calibration sheet). Since the MRF did not reflect the EQ status no verification of the side cover torque was require The inspector met with the licensee's lead EQ engineer and the site EQ coordinator to discuss this problem. Nuclear Engineering Department Procedure (NEDP) 3.1, " procedure For Handling of Modifications," initiates revision of controlled documents to reflect changes in EQ status and-requirements upon issuance of the Modification Closure Notic Modification 1891, however, is being implemented on both units over an extended period, and no closure notice has been issued. Although the modification has not been closed, affected instruments have been turned over to the station without update of the appropriate site document The inspector questioned if other equipment could also have been affected by this weakness. The licensee committed to revise the involved site EQ documents, to revise NEDP 3.1 to ensure timely future document revisions for equipment turned over prior to modification closure and to evaluate the possibility that other similar situations exis Several previous -incidents of inadequate design and maintenance of EQ equipment were discussed in Inspection Reports 89-22 and 89-23. The licensee also submitted' Licensee Event Reports addressing these problem As corrective action the licensee committed to complete a self-assessment of the EQ program. This self assessment will include a review of the maintenance of the EQ program on site. Licensee actions to evaluate and correct these weaknesses, including those discussed above, will be reviewed under existing unresolved item 89-23-0 .3 Control Rcom Emergency Ventilation System Actuation On May 2, 1990 at 8:46 a.m., 9:45 a.m., and 11:35 a.m. the control room emergency vent,lation system (CREV) was activated when one of the radiation-monitor on the intake duct spiked. The high radiation isolation results in a fresh air supply fan trip and start of the emergency ventilation; drawing fresh air through high efficiency particulate (HEPA) and charcoal filter In each case the actuation was reset and normal ventilation restore ENS calls were made to report the actuations at 10:21 a.m. and 2:10 .
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The licensee initiated a maintenance work request to correct the radiation monitor spurious spiking. It was determined that the monitor was performing satisfactorily. Historically, spiking has occurred when dust or dirt accumulates on the circuit boards. The drawer was cleaned and no further spiking was noted with the radiation monitor. The inspector had no further question i 2.4 Unit 2, Reactor Water Cleanup (RWCU) System Isolation During Surveillance On May 7, 1990, an isolation of RWCU occurred when an instrument and Montrol (I&C) technician inadvertently caused a short circuit to ground phile performing a surveillance on a RWCU high flow instrument. Both
'nboard and outboard isolation valves automatically closed. The NRC was notified via ENS at 12:28 am on May The I&C technician was performing surveillance procedure S13F-12-124-A1CQ,
" Calibration of RWCU High Flow Instrument OP1S-3-12-124A." The technician had installed a jumper to prevent an inadvertent isolation of RWCU. He also installed a volt / ohm meter (V0M) across the terminals.of the differential pressure switch. While removing his hands from the V0M, his '
white cotton gloves snagged a test lead and pulled it out of the V0M jac '
The lead fell against a metal pipe, causing fuse 16A-17 to blow, deenergizing relay 16A-K25, and causing both the inboard and outboard isolation valves to clos All components performed as expecte The RWCU isolation was not reset for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> due ta an inabili+y to find a qualified replacement fuse. While the rvplacement fuse was being located, the
- surveillance was completed su;cessfully. The fuse was replaced and the
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- isolation reset. The licensee initiated a human performance evaluation of this event. 'The inspector nad no further question '
2.5 Unit 3 Loss of Battery Charger and Declaration of Unusual Event On May 11, 1990, Itc technicians were replacing the voltmeter on the Unit 3 "B" battery charger. Normally, battery chargers are blocked during this activity but it was determined that voltmeter change-out could be accomplished with the charger energized. While reconnecting the replacement voltmeter, the control room received the "HPCI Inverter Power Failure" alarm at 9:40 a.m. Also, the control room operator noted that a reactor pressure indicator and a reactor level indicator dropped hard downscale. Control room operators were aware that the battery charger was
- being worked and believed this activity had caused the alarm and indicator problem. A non-licensed operator (NLO) was sent to the battery charger-to investigate. At 9:50 a.m. the alarm cleared and both indicators returned ,
to normal. However, shortly thereafter, a static inverter trouble alarm and the battery charger trouble alarm were received in the control roo ,
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Voltage indicated on the battery charger voltmeter was 114 VDC, voltage measured on the battery terminals was 118 VDC, and the battery charger was declared inoperable at 10:15 Abnormal operating procedure A0~578.1-3, " Loss of a 125/250 VDC Battery Charger," was-consulted. Technical Specifications were also consulted and stated that the battery system is operable as long as 105 VDC is maintaine The static inverter was swapped to its alternate feed to conserve batteW/ !
power. Upon investigation the I&C technicians found the 250 amp output .,
fuse for the battery charger blown, interrupting current to the batterie i Several control room operators recalled that the 105 VDC Technical Specification limit was no longer valid based on as the result of a PECo internal safety inspection conducted in 1989. The control room eventually contacted the Power Generation Engineer and it was determined that 12 VDC was the low voltage operability limit. The battery system was declared inoperable at 11:40 a.m. The licensee also conservatively declared all loads fed by the battery inoperable. Equipment affected included the high pressure coolant injection system, "B" core spray subsystem, "B" low pressure coolant injection subsystem and the E-2 and E-4 diesel generators for Unit 3 only. As a result, Technical Specification 3.0.C was invoked which requires hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, The Shift Manager (SM) reviewed the Emergency Action Levels (EAL), and at 12:00 p.m. an Unusual Event (UE) was declared due to a " situation that l threatens normal level of plant safety." Declaration of the UE was a conservative judgement by the SM. At about the same time a replacement fuse was located but it could not be determined if it was "Q" It was
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decided to use the fuse, the battery charger was returned to service and the UE was terminated at 12:05 p.m. However, the shutdown was not
. terminated due to the unknown quality designation of the fuse and the need-to ensure full battery recharge. At 4:05 p.m., the fuse was determined to be "Q" and the Technical Specification required shutdown was terminate Follow-up by the licensee determined that the I&C technicians re-terminated the negative leads (black) before the positive leads (red),
causing battery charger output to increase to maximum voltage and curren Voltage reached 302 VDC and the fuse blew. The licensee instituted DC equipment testing after the voltage transient. All energized equipment fed from the 3 "B" 125 VDC system and the 3 "B/D" 250 VOC system was inspected and tested for damage. The only problem found was a blown fuse in the HPCI alternative shutdown panel. This fuse was replaced. The licensee concluded that based on the momentary 35 VDC surge on the system, all equipment fed by the suspect battery charger was continuing to operate i correctly and no operability concerns exist.
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i The_ inspector reported to the control room during the event and letermined I that actions taken by the operating shift were acceptable. Decla,ation of the UE was considered to be conservative. The inspector expressed concern that adequate guidance was not available to the operators to determine the operability of the battery system. As a result, about 1 1/2 hours elapsed before control room operators determined that the battery should have been declared inoperable. Plant staff concerns regarding the adequacy of existing battery operability guidance were raised during 1989 and forwarded to engineering via an Engineering Work Request (EWR) dated May 16, 1989. During December 1989 the licensee's QA organization performed ~;
an inspection of the DC system. Corrective Action Request (CAR) SFIP89-10 issued on January 17, 1990 by QA identified the deficient TS. The response stated that a change request will be initiated to revise the minimum battery voltage, and a letter will be sent to Peach Bottom recommending A0 578.1-3 be revised to include the new voltage limit. A letter dated March 19, 1990 i was issued from Nuclear Engineering to the Power Generation Engineer recommending affected procedures be updated to reflect the minimum battery voltage of 123.5 VDC and 247 VDC. Site personnel were questioned concerning the amount of time that had elapsed since initial identification of the problem, issuance of the CAR, and the UE. The delay was attributed to disagreement between the site and engineering concerning the minimum battery voltage, and subsequent de/elopment of a PORC approved position. The ;
inspector questioned why interim guidance had not been provided to the i operating shif t during t'ae past several months. The CAR was closed on March 29, 1980, statine that corrective action was complete and verified uffective. The inspe:. tor believed that the CAR was closed prematurely since personnel wbs need to be knowledgeable of the new requirement (operators) had no guidance. Ten days after the event, guidance was still not available in the control room. The licensee indicated that they believed the PORC position would be issued shortly after the event, but had been delayed. In response to the inspector's concern interim guidance was provided in the operations night orders on May 2 l i
Based on review of battery voltage curves plotted by the new process '
computer system, the inspector believed that the voltage transient could have lasted for approximately 4 to 5 minutes rather than momentary as believed by licensee engineers. Use of data points and knowledge of the computer's limitations in plotting curves, along with alarm typer printouts and the sequence of events derived from personnel interviews led to this determination. This conclusion was also supported by the time vs. current characteristic curve for the blown fuse. The DC system apparently experienced the additional 35 VDC for 4 to 5 minute The licensee agreed and considering this information still concluded that inspections and testing performed to date were adequat The inspector's final area of concern was the apparent lack of proper plann ng for the voltmeter replacement. Connection drawings were not used dcring preplanning phases of the maintenance task and were not
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included in the maintenance package. The licensee was not aware that
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having the black leads of the voltmeter connected while the red leads were disconnected would cause the battery charger to charge at its maximum level, .Since this was apparently the first time a battery charger was 3
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worked without being blocked, better pre planning would have been prudan !
This event will remain unresolved (UNR 90-10-01) pending resolution of the following items:
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review of licensee corrective action to ensure better job preplanning,
- - review of precedure revisions regarding minimum acceptable battery voltages, and
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evaluation of ootential premature closure of the CA I 2 . t, NRC Notification of Degraded Emergency Service Water Capability for i Unit 2 !
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During. August, 1989, with Unit 2 at power the licensee operated the plant for about 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> with the emergency service water (ESW) system in a I degraded condition. -The emergency cooling water pump was out of service for maintenance. The E-2 emergency diesel generator (EDG), which supplies standby power to the "A" ESW pump, was also inoperable. A valving error during restoration from maintenance activities would have prevented the
"B" ESW pump from supplying Unit 2 loads during a design basis acciden l The.EDGs would have received cooling water flow, On May 16, 1990, the licensee informed the NRC via ENS of this incident. The delay in reporting was a result of an inadequate initial licensee review of the even This issue was discussed in inspection report 90-06 and is the subject of ;
existing item NV 90-06-01, ;
3,0 Engineering and Technical Support Activities 3,1 Licensee Response to NRC Bulletin 90-02, " Loss of Thermal Mar _ gini Caused by Channel Box Bow" !
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Information Notice 89-69 and Bulletin No. 90-02, " Loss of Thermal iiargin Caused by Channel Box Bow," requested the licensee determine if any ,
channel boxes are being reused after their first full bundle lifetime, and j ensure that the effects of the channel box bow on critical power ratic i (CPR) are properly taken into account. The licensee determined that n-) '
reused channel boxes are-being used in Unit 3. On Unit 2, 59 channel boxes are being reused in their second full bundle lifetime, A study was initiated to determine the effects of channel box bow on critica! power ratio (CPR) and average planer linear heat generation rate (APLHGR) to i assure compliance with the TS,
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The' licensee determined that to preclude violation of the thermal limits for all four-bundle control blade cells containing reused channel boxes,.
the maximum fraction of limiting critical power (MFLCPR) will be established at less than or equal to 0.91 by administrative contro MFLCPR is the ratio of the TS MCPR limit to the actual operating value of MCP In addition, maximum average planer linear heat generation rate ratio (MAPRAT) will be established by administrative control to less than or equal to 0.9 MAPRAT is the ratio of the operating MAPLHGR valve to the TS MAPLHGR operating limit. The MFLCPR and MAPRAT adjustments will be incorporated into the process computer data bank for fuel bundles in cells containing reused channel boxes at a later tim The inspector had no further questions at this tim .2 NRC Temporary Instruction 2500/27, " Fastener Testing to Determine Conformance With Applicable Material Specifications" The purpose of TI 2500/27 is to determine the adequacy of licensee root cause analyses and the implementation of corrective actions in response to NRC Bulletin 87-02. The inspection requirements of TI 2500/27 that.are applicable to Peach Bottom are Sections 4.01, 4.02, and 4.0 Section 4.01 applies to safety-related fasteners with substantial deviations warranting follow-up action. Sample PB-10, an SA 194 grade B6 7/8" - 9 nut, was tested and found to exceed the maximum hardness of RC2 The licensee wrote nonconformance report (NCR) CDP-1510 to investigate the circumstances surrounding the out of specification nut. Purchase records indicate that 16 nuts were obtained from Westinghouse Electric Corporatio Warehouse records indicated that one nut was issued on December 10, 1987'
(for IEB 87-02 testing). No others were issued for installation in the plant. The remaining nuts were issued on September 26, 1988 to be scrapped as part of the corrective action for the NCR. The material used to manufacture the nuts was obtained from A1 Tech Speciality Steel and was produced to a QC Program which conformed to NCA-3800 as audited and ,
approved by Vitco Nuclear Products, Inc. Apparently, during the manu-facturing process, Vitco did not heat treat the nuts properly to reduce the hardness from RC44 (as purchased from A1 Tech) to RC20-2 PECo relied on Vitco's Certified Material Test Report submitted to Westinghouse which stated that the hardness was RC2 PECo's new fastener testing program instituted in response to IEB 87-02 now tests a sample of fasteners from t each purchase order received. The likelihood of allowing substandard fasteners onsite should be significantly reduce Section 4.02 requires assessment of the adequacy of root cau.se analysis and corrective action taken for cases in which 20*4 or greater failure rates were experienced for safety or non-safety related fr.stener Section 4.06 requires assessment of root cause, analysis and corrective action regarding potential use of non-safety related fr.stener.: that failed significantly out of specification The only high 'ncidence af failures occurred in non-safety related fastener Five of 21 samples hiled
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(PB-26,38,39,40,41) due to chemical deficiemies. These were the same fasteners that failed significantly out of specification; therefore the corrective action and root cause analysis for 4.02 and 4.06 are the sam The licensee's Nuclear Engineering Department had an analysis performed by'
Bechtel which determined that the nonconformances do not impact plant safety. Sample PB-26, A193 grade B16 5/8" - 11 stud, contained molybdenum and vanadium lower than required. (0.2 vs. 0.47 min; 0.005 vs. 0.22 min, respectively) and manganese higher than required (0.92 vs. 0,73 max).
These values indicate that the stud is grade B7 instead of B16. However, acceptable hardness and tensile test results confirm the adequacy of the stud to accommodate mechanical property requirements for a B16 stud in non-Q applications. The chemical differences would only be critical in high temperature applications (greater than 900 degrees F) which is not a concern at Peach Bottom. In addition, QC requested that this msterial be removed from stoc Samples PB-38 & 39, A393 grade B8 9/16'? - 12 cap screws, contained sulfur higher than required (0.132 and 0.142 respectively vs 0.035 max). These values indicate that type 303 stainless steel was used to manufacture the cap screws instead of type 304. However, accep-table hardness and tensile test results confirmed the adequacy of the cap screws to accommodate the mechanical requirements for B8 cap screws in non-Q applications. The chemical differences would only be critical in highly corrosive fluid applications, which is not a concern at Peach Botto Samples PB-40 & 41, A194 grade 2 5/8" - 11 nuts, contained carbon lower than required (0.089 and 0,092 vs. 0.4 min). A lower carbon content may indicate a lower mechanical strength. However, acceptable hardness and tensile test results confirm the adequacy of the nuts to accommodate the mechanical requirements for A194 grade 2 nuts in non-Q application The inspector noted that while adequate information was available to complete.the required review,.information has not been assembled in an auditable form. This delayed resolution of inspector questions. This observation was discussed with licensee management at the exit meetin Nonetheless, the inspector concluded the recently implemented independent fastener testing program described earlier should significantly reduce the likelihood of allowing substandard fasteners onsite in the futur .3 Performance of NRC Temporary Instruction 2500/20, " Inspection to Determine Compliance With ATWS Rule, 10 CFR 50.62" On March 13 and 14, 1990, a representative of the NRC Office of Nuclear Reactor Regulation, supported by one contract engineer, performed an inspection of the licensee's alternate rod insertion, standby liquid
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control and recirculating pump trip systems. Temporary Instruction 2500/20 was used as an inspection guideline, The inspectors did not identify any concerns, and confirmed the information contained in the NRC Safety Evaluation addressing the licensee's design, dated December 21, 1988. Attachment 11 contains a detailed account of the inspectors'
review.
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4.0 Surveillance Testing l
4.1. Routine Observations :
The inspectors' observed surveillance tists to verify that testing had been r
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properly scheduled, approved by shift sipervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as l required, test instrumentation was calibrated, work was performed by "
qualified personnel, and test acceptance criteria were met. Daily surveillances including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performe Surveillance tests observed are listed in Attachment II ;
4.2 Licensee Identified Surveillance Test Completion Deficiencies During the. inspection period the licensee identified four instances in which surveillance testing (ST) required or intended to be completed was not performed within the established interva These tests are discussed j individually belo <
1) ST 3.4.1, LPRM Gain Calibration Technical Specification (TS) 4.1.A requires performance of this l calibration once every six weeks. If the 25 ?; grace period allowed i for late performance of testing is utilized, the interval could be !
extended to seven and one half weeks. The licensee's Surveillance l Test and Records System (STARS) is capable only of scheduling testing ;
on a me, 11y or quarterly frequency. As a result, the system did not !
properly track this testing and the required interval was exceede The . licensee instituted manual tracking of the test requirement to 1 ensure completion, and initiated a Reportability Evaluation / Event !
Investigation Form (RE/EIF). Disposition of the RE/EIF will result-in $ssuance of a Licensee Event Report (LER) and performance of a y f
root cause analysis. Weaknesses in the capability of the STARS to properly track test requirement intervals is.the subject of existing unresolved item 90-01-02, i
2) ST 6.4, MSIV Closure Timing
TS require completion of this testing every three months. The test !
late grace period (specified test interval + 25?;) expired on April 29, 1990, without completion of the test. ST 6.4 was successfully performed several days later when it was identified as overdu Scheduled STs which cannot be performed because of plant or equipment status can be placed on the omitted test list. Preliminary review indicates that the cognizant engineer had deleted the test from the i
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schedule and added it to the omitted test lis The procedure states that the test is required "every three months when Rx power is < 75%
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The cognizant engineer believed that this meant that the test was not required with the unit at greater than 75% power. In fact, .
it means that power must be reduced to 75% power to support !
completion of the test. A RE/EIF was initiated to ensure follow-u '
3) SI2N-60B-RBM-AIFM (and B1FM), RBM Functional Check TS require that the rod block monitor (RBM) be operable with the reactor at > 30% power. The RBM functional test is required to be performed monthly, During the recent unit 2 mid-cycle maintenance l outage the monthly test expired. The test was not performed prior to exceeding 30% power during the plant restart, It appears that the ,
two RBM channels were tested at about 34 and 39% power. The ST is '
scheduled monthly by STARS, but is not included in General Procedure (GP) 2, " Plant Startup." The licensee initiated an ER/EIF, and plans to revise GP-2 to included the test as a prerequisite to exceeding 30% powe '
4) ST 6.18.1-2, IST Normally Closed Valves The licensee identified that this ST had exceeded its late grace period, Additional research indicated the test is not relied upon to
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l satisfy any TS surveillance requirement, but is needed to meet the provisions of the Inservice Test Program (IST). The inspector noted i
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that no RE/EIF had been initiated. The RE/EIF -is needed to track the performance of a root cause analysis, and to ensure incorporation of A the information into the trending program maintained by the Event Investigation Coordinator as described in Nuclear Group Administrative Procedure (NGAP) NA-02A002, " Investigation of In-House ;
Events." An Operations Department engineer had investigated the "
missed test to the extent needed to determine that no TS violation had occurred. However, the root cause for missing the scheduled test hadn't been evaluated. In response to the inspector's concern the licensee stated that a RE/EIF would be initiate During discussions with various licensee staff the inspector noted '
that many personnel weren't familiar with the provisions of the NGA Individuals will be relied upon to identify and raise issues requiring evaluation under this process, however, familiarization training for the plant staff hasn't been complete The inspector reviewed LERs issued for Peach Bottom during the past year s and noted that 11 are related to failure to perform surveillance testing at the frequency required by TS, or when required due to changes in plant mode or operating condition. The relevant LERs are:
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2-90-008, TS Violation Caused oy Personnel Error Results in Missed Low Pressure Core Cooling System Surve111ances, 4/14/90; ,
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2-90-005, Untimely Performance of TS Surveillance Due to a Personnel ;
i Error, 3/26/90;
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2-89-032, Untimely Performance of a TS Surveillance Due to a Failure to Follow an Administrative Procedure, 12/11/89;.
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2-89-014, Scheduling Error Causes TS Surveillance Test to Exceed Grace Period, 5/17/89;
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2-89-013, less Than Effective Communications Causes a TS Surveillance Test to be Missed, 4/11/89; -
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2-89-011, Failure to Perform TS Surveillance Due to a Procedural Deficiency, 4/26/89;
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2-89-010, TS not Satisfied Due to a Personnel Error While Reviewing a ,
Plant Procedure, 5/14/89;
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3-90-003, Reactor Scram Due to Stator Water Cooling Pump Trip and Improper Generator Runback Timer Setting, and Failure to Perform TS Surveillance, 3/6/90;
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3-89-011, Missed Surveillances Resulting in TS Violation Due to ,
Incorrect Standard Practice of Surveillance Timing, 12/13/89;
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3-89-10, Late Performance of TS Surveillance Due to Programmatic Deficiencies, 12/11/89;
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3-89-007, TS Actions not Performed as Required Due to Deficient Procedure, 10/26/8 There appears to have been a group of missed tests in March - May, 1989, again in October - Decemoer, 1989, and once more recently. This may be related to the increased pace of activities in support of plant startups during these periods. Apparently, corrective actions taken in response to previous incidents have not been effective, as demonstrated by the recently identified group of missed tests. The recurrent failure to complete TS surveillance tests in the time frame required warrants a broad review and lasting corrective action. The inspector discussed this issue with plant management and the licensee. committed to review these failures collectively, in addition to the case by case review, to identify common contributors and root causes. This item will remain unresolved pending review of the licensee actions (UNR 90-10-02).
5.0 Maintenance Activities Routine Observations-The inspectors reviewed administrative controls and associated documenta-tion, and observed portions of ongoing work.
l Administrative controls checked included blocking permits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post-maintenance testing and reportability.
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Documents reviewed included maintenance procedures (M), maintenance ,
request forms (MRF), item handling reports, radiation work permits (RWP), I material certifications, and receipt inspection .2 Unit 2 HPCI Turbine Reversing Chamber Hold-down Bolt Inspection i The Unit 2 High Pressure Coolant Injection (HPCI) system turbine was dissembled for inspection during the mid-cycle outage af ter bolts, parts of a bolt and part of a locking tab were found in a turbine steam exhaust drain valv i
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During the performance of local leak rate test (LLRT) surveillance l procedure, ST 20.118 "LLRT - HPCI Turbine Exhaust Drain," on valves A0- !
2-23-137 and A0-2-23-138, the test failed in the as-found conditio Each ;
valve was dissembled for repair. Valve A0-2-23-138 was refurbished 4 showing only deposits on the seat. Valve A0-2-23-137 when dissembled was I found to have two 3/8 x 1 inch hex head cap screws (bolts), the head of a 3/8 inch allen head cap screw, and a thin sheet of metal in the seat. The !
valve was rebuilt with a new seat and inner valve assembly. Both valves passed the LLRT after repai l The_ licensee reviewed maintenance and modification records, performed a !
metallurgical analysis of the loose parts, and visually examining portions of the turbine exhaust drains with a fiber optic probe. The fiber optic probe was limited to a small portion of the exhaust system by <
the diameter of the piping and the length of the probe. Within the scope !
-of the examination, no additional parts were found, i
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Until_1980 allen head cap screws were used to hold down the steam reversing' chambers in the turbine. They were changed by modification in 1980 according to General Electric FID 217/71067. The allen head cap screws were found to be subject to fatigue cracking and were replaced with ;
hex head cap screws of material ASTM A193, grade 6, with a hardness limit of RC = 28 or less. It could not be determined if the head of the allen _ !
head cap screw had been dropped into the exhaust during the modification or was from a broken cap screw prior to the modification. Metallurgical analysis indicated it had been in the exhaust drain for some tim The thin sheet of metal was determined by dimension and fit to be a portion of the locking tab from the outer rail hold-down of the reversing chamber During the inspection of the turbine in 1987 it was noted that portions of 2 locking tabs were missing. Metallurgical analysis indicated that the lock tab piece had undergone ductile failure from bending and unbending on the irregular edge. It could not be determined if the locking tab piece originated from missing portions of the locking tabs noted in 1987 or was of recent origi .
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a Both of the hex head cap screws were the type used in the outer rail hold-down. It was noted during the 1987 turbine inspection that one cap screw was missing from the hold-down of a reversing chamber, although it was not noted whether the missing cap screws were from the inner or outer rail. Metallurgical analysis indicated that both of the bolts had been tightened, as evidenced by score marks on the pressure flank of the threads and the underside of the head. It could not be determined if they had been used more than once; if they had been inadvertently dropped into the _ turbine during inspection activities; or if they were of recent origi The licensee concluded that to assure operability of the HPCI system an inspection of the turbine was necessary, since the origin of the hex head cap screws could not be determined. The turbine was dissembled. All the hold-down bolts and locking tabs were found to be in place. The bolts were retorqued and the turbine reassembled. The inspector reviewed the MRFs associated with the activity and witnessed portions of the inspection and reassembly. The inspector found the licensee actions to ensure HPCI operability to be thorough and conservative. The inspector had no further question .0 Radiological Controls During the report period, the inspector examined work in progress in both units and included health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instrument use, and handling of potentially contaminated equipment and material The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation area doors was verified to be locked as required. Compliance with RWP requirements was verified during each tour. RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable conditions were identifie .0 Physical Security 7,1 Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including:
security staffing, operations of the CAS and SAS, checks of vehicles to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of detection and assessment aids, and compensatory measure No inadequacies were identifie c
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7,2 Discharge of a Firearm in 'the Owner Controlled Area On April 24, 1990, at 9:30 p.m. an individual entered an office trailer located in the parking lot area outside the protected area. The individual ;
opened his overcoat and pulled a rifle, believed to be a .22 caliber. A '
licensee corporate investigator was present, The individual fired a shot .i away from the investigator and lef t the trailer. The facility security I organization and the Pennsylvania State Police were notified. When the - [~
investigator was leaving the facility to go home, he discovered that his company provided vehicle had also been vandalized. The rear window was broken and a tire was punctured. The investigator is assigned to the facility full tim '
The licensee made an ENS phone call to the NRC within one hour. The licensee's guard force was placed on alert, and additional compensatory measures were implemented. The licensee is currently investigating the l incident. The inspectors found the licensee's actions in response to this incident to be appropriate and in accordance with approved plans and ,
procedure !
8.0 Management Changes On April 12, 1990, the licensee announced that the Board of Directors approved a number of top management changes following Philadelphia Electric ;
Company's Annual- Meeting of Shareholders, Mr. Corbin A. McNeill, Jr,, was elected President and Chief Operating Officer, and a Director of the company. Mr. Dickinson M. Smith was promoted to Senior Vice President-Nuclear,_ the position Corbin McNeill formerly held. Mr. Donald B. Miller was elected as Vice President, Peach Bottom Atomic Power Station. Mr. Miller j is currently the Station Manager of the Connecticut Yankee Nuclear Station '
for Northeast Utilities. It was also announced that Mr. David R,- Helwig would move to the newly created position of Vice President, Nuclear ,
Engineering and Services. The changes will become effective April 16, !
1990. Mr. Joseph F. Paquette will continue as the Chairman and Chief l Extcutive Officer of the compan '
On May 8, 1990, several other management changes were announced. Mr. Gerald R. Rainey will assume the Plant Manager position at the Eddystone Station (fossil). Mr. James P. Wilson will replace Rainey as Superintendent, Maintenance /I&C. Mr. Eugene P. Fogarty will transfer from Nuclear Engineering and Services to replace Wilson as the Project Manage y' . . ' ,
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9.0 Review of Licensee Reports 9.1- Licensee Event Reports The inspector reviewed LERs submitted to the NRC and verified that the licensee took appropriate corrective action and assigned responsibility, and that continued operation of the facility was conducted according to Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe LER N LER Date Event Date Subject'
02-89-07, Rev. 1 Excessive grease on emergency 4ky switchgear 02/07/90 fuse clip contact /11/89 02-89-15, Rev. 1 Unit 2 automatic scram from 79% power due to EHC 01/16/90 malfunctio /21/89 02-89-24, Rev. 1 Unit 2 reactor scram while in hot shutdown due 03/12/90 to local power range monitor spiking upscal /06/89 02-89-29, Rev. 1 Unit 2 primary containment isolation system
.03/12/90 actuation due to spiking radiation monitor 11/17/89 during surveillanc :02-89-31, Rev. 0 & Inadequate seismic support straps for Agastat 01/05/90 Rev. 1 relay /23/90 12/06/89 02-89-32 Late performance of a technical specification 01/17/90 required surveillance test for Unit /11/89 02-89-33 Unit 2 scram from 100% power during 01/19/90 surveillance testin /20/89 2-90-01, Rev. 0 & Unit 2 daily . instrument check not performed
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02/23/90 Rev. 1 as required by technical specification /07/90 01/24/90
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LER Date Event.Date Subject '
02-90-02 Unit 2 technical specification required shutdown ,
04/02/90' due to an inoperable ADS valv J t-02-90-03 Unit 2 main steam line drain valves fail as-04/09/90 found primary containment total allowable -
03/10/90' leakage rat '02-90-04' Potentially inoperable Unit-2 safety systems 04/19/90 due to inadequate emergency. service water flow 03/20/9 through room cooler t
02-90-05 Late performance of a technical specification- '
-04/27/90 ' required surveillance test for Unit '
03-26-90 >
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Two Unit-3 surveillance teste, performed after 01-16-90 the instruments were required to be operable in
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.12/13/89 .accordance with technical specification *
03-89-12 P.lant configuration outside design basis due to 12/22/8 fire protection program analysis . deficienc /22/90 .
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- 03-90-01 Excessive start time for Unit 3 HPCI due to 02/07/90 procedure deficienc /08/90-
'03-90-02, Rev. 0 & Unit.3. manual scram from 50% power due to j 02/23/90: Rev. 1- EHC fluid lea /30/90 01/28/90-03-90-03 Unit 3 automatic scram from 35% power due to-03/06/90 main turbine tri /05/90- ;
The ' inspector did not identify any concern , ,
9.2= Radiation Oose Assessment' Report q
'On April 27, 1990, the licensee submitted the Peach Bottom Ato;aic Power
. Station (PBAPS) Radiation Dose Assessment Report No. 5 for the period =i January 1~through December 31, 1989. This report summarizes the radiation doses due to effluent releases, liquids and gases from Units 2 and 3
.during the reporting period. The report is required in accordance with l
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Technical Specification 6.9.2, and includes a comparison with the design objectives criteria (limits) in 10 CFR 50 Appendix 1. The maximum offsite dose due to liquid releases was 0.284 mrem per year compared to a limit of 10 mrem per year. The maximum offsite dose due to gaseous releases was 0.0418 mrem / year compared to a limit of 15 mrem / year. The inspector had no further question ,
10.0 Previous Inspection Item Update (Closed) Failure to Fully Document QC Inspections (NCV 278/89-26-05)
The inspector hed identified instances of inadequate documentation of quality control inspection activitie In one case, installation reports did not list all Q-listed items for tubing installation packages for differential pressure indicator In the other case, valve installation reports lacked required information on valve serial numbers, year of manufacture and the name of the valve manufacture In response, the licensee performed field walkdowns for all 28 tubing installation packages associated with Modification 2106 and revised the installation reports to show all Q-listed items, as indicated in the. licensee's supplemental response to the NRC (Letter from O. Smith, Philadelphia Electric Company, to the NRC, dated February 1, 1990). The licensee also completed revisions to applicable installation and quality control procedures which should result in improved planning and documentation of quality control verification activities for future modifications. Modifications and QC p rsonnel received training on the new procedures which were implemented
- cior to the recently completed mid-cycle maintenance outage for Unit With regard to the failure to record appropriate valve data on the valve installation reports, the licensee initiated Nonconformance Report P89-1002 to addru s the indeterminate status of the applicable valve The rionconformance report received engineering review on December 27, 1989 and quality assurance review and closure on March 13, 1990. The nonconformance report resulted in an use-as-is disposition given the identification of the valve mark numbers on the valve installation report The valve mark numbers provided the necessary material traceability information for the installed valves. Based on a review of the above licensee actions, the inspector considers this item to be close (Closed) Inadequate Justification for Voiding a Corrective Action Request (UNR 278/89-26-06)
Corrective Action Request (CAR) PC 89027412 was voided by an internal quality assurance memorandum dated July 14, 1989. The inspector noted that the memorandum did not appear to provide adequate justification for voiding the CAR. In response, the licensee issued an internal quality assurance memorandum which addressed each of the eigh. specific concerns that were raised in CAR PC 89027412. In addition, the licensee identified CAR PA 88-513-6 which addressed similar concerns on the adequacy of
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I modification document package Corrective actions in response to CAR PA
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88-513-6 were completed as of August 5,1989. As indicated in the !
licensee's February 1,1990 supplemental response, the applicable i procedure, NQA-25, " Corrective Action," was revised on March 30, 1990 which provided guidance on revising CARS and prohibited the voiding of j CAR Based on.the described licensee actions, this item is considered ;
close '
I (Update) Evaluate Licensee Root Cause Analysis and Corrective Actions _
Related to Several Environmental Qualification Deficiencies (UNR 277/89-23-01) l The scope of this unresolved item is expanded as described in section I of this repor '
11.0 Management Meetings 11.1 NRC Inspector General Plant Tour
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On April 24, 1990 Mr. David C. Williams, NRC Inspector General, and nine 1 members of his staff visited the Peach Bottom Statian. The resident inspectors provided a brief presentation, followed by tours of the reactor and turbine buildings, and the control room. The licensee Superintendent of Operations and Training Manager provided a taur of the simulator
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facility, and the group observed shift crew performance during an anticipated transient without scram scenario, i
11.2 Preliminary Inspection Findings
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, A verbal-summary of. preliminary findings was provided to the Peach Bottom Station Plant Manager at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspectio i material was provided to the licensee during the inspection. No ;
proprietary information is included in this repor !
11.3 Attendance at Management Meetings Conducted by Region Based Inspectors The following inspector exit interviews were attended during the report period:
Dates Subject Report N Inspector 1 4/2-4/6 'onfirmatory 90-09/09 Kottan Measurements 4/30-5/4 Radiation 90-11/11 Sherbini Protection
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ATTACHMENT 1 ;
Facility and Unit States P
Unit 2 April 2 Unit shutdown. Mid-cycle outage completed March 2 Emergency service water system testing plant restart delay April 16 Mode switch to refuel April 17 Mode switch to startup April 21 Manual reactor scram from 21% power. Scram initiated to
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. inspect main turbine bearings after high nain generator erciter vibration and indication of damage due to lots of siterrex
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excitor air cooling.
April 28 Unit restarted and reactor critica April 29 Main turbine rolle .
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May 8 Unit at 100*4 powe r Unit 3 April 3 Reactor power at 100%
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April 18 Reactor power reduced to 90*4 for regeneration of condensate-demineralizers and rod pattern adjustment. Reactor power.-
, returned to 100%.
May 1 Reactor power reduced to 70'4 for MSIV closure testinL control rod exercise, and rod pattern adjustment. Reacter power raised to 95%, but due to high copper concentration, reactor power reduced to 80%.
May_4 Technical Specification required shutdown initiated when drywell
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high pressure transmitter was found not EQ. Shutdown terminated I hour late May 5: 1ecctor power at 85% for remainder of period due to possible
, -recurrence of high copper concentration and condenser vacuum performance problem May'11 Unusual Event declared due to loss of "B" battery charger and 6 subsequent inoperability of various ECCS equipmen t e l O*
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g UNITED STATES
. ! g NUCLE AR REGULATORY COMMISSION h t WASHINGTON, D. C. 20bbb
.....) ATTACHMENT 2 SUMMARY REPORT REGARDING INSPECTION OF PEACH BOTTOM ATOMIC POWTY STATION. UNITS 2 AND 3 ATW5 RELATED PLANT MODIFICATIONS REQUIRED BY THE "ATWS-RULE"(10 CFR 50.6?)
1.0 INTRODUCTION The Office of Commission Nuclear (NRC) Reactor assisted by theRegulation Idaho National (NRR) of the Nuclear Engineering Regulatory (INEL)
Laboratory conducted a post-implementation inspection of the Alternate Rod injection (ARI)
System. Standby Liquid Control System (SLCS), and the Recirculating Pump Trip ;
(RPT) System at the Peach Bottom Atomic Power Station, Units 2 & 3, en March 13 and 14, 199 The purpose of this inspection was to evaluate the Philadelphia Electric Company implementation of the AR1, SLCS, and RPT designs and installations inaccordancewiththelicensee'sPeachBottomplantspecificATWS(Anticipated Transients Without Scram) design submittals dated October 17, 1985 (Ref. 1),
June 30 1986 (Ref. 2) The NRC/NRR Safety ,
EvaluatIonReport(SER}andApril3,1987(Ref.3).
addressing the Peach Bottom ARI and RPT system designs '
was dated December 21, 1988 (Ref. 4), and the SLCS system SER was dated June 2, 1987 (Ref. 5). The NRC Inspection Manual Temporary Instruction (TI) 2500/20 Revision 1 dated March 24, 1989 (Ref. 6), was used as a guideline for the inspectors performing this post-implementation inspection of the AR1, SLCS, and RPT designs and equipment installation ,
2.0 TECHNICAL EVALUATION At the Peach Bottom Atomic Power Station (PBAPS), Units 2 & 3, the licensee has implemented AR1, SLCS, and RPT systems, which meet or exceed the design !
requirements approved by the NRC in the SERs. Although these systems are not qualified as Class IE, the AR1, $LCS, and RPT are included in the Peach Dottom Technical Specification .1 Alternate Rod injection System The ARI is a four channel, two train system automatically initiated by either low reactor water level or high reactor pressure and performs a function redundant to the backup scram system. The ARI is required to start rod injection motion within 15 seconds of initiation and be completed within 25 seconds of initiation. However, due to pressure limitations within the Scram Discharge Volume (SDV), PBAPS 2 & 3 plant specific aralyses were performed by General Electric Company (Ref. 7) supporting 30.4 seconds for start of rod
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-2-insertion motion, and 35.4 seconds to complete the scram function. These analyses were reviewed by the staff and were approved (Ref. 8) based on the licensee's ability to provide test data to support these functional times. The licensee performed Modification Acceptance Test (MAT-865), " Alternate Rod Insertion," on November 9, 1989, and confirmed that the start of rod insertion was less than 30.4 seconds after AR1 initiation. Additional test data show the rods to be inserted in less than 5 seconds after the start of rod insertio Therefore, the total scram time for PBAPS 2 & 3 is less than the 35.4 seconds required by the plant specific analyses. The inspectors reviewed these test data and determined the ARI functional time limits to be acceptable. Reset of the ARI cannot be performed due to a built-in time delay until 40 seconds after system initiation to ensure that once initiated, the protective action goes to completio The manual controls and system annunciators for the ARI have been incorporated into the existing operator panels using good human factors engineering. The manual initiation and reset pushbuttons are located near other manual shutdown functions such as the Control Rod Drive System (CROS) and the StCS. Indicators for the ARI valve 30sitions are located next to the ARI pushbuttons. The annunciators for tle ARI are located on the panels above the control Annunciators are provided for AR1 trip and ARI armed conditions for both Channels A and B and for an inoperable ARI system. Existing signal test jacks make the ARI system testable at power from the transmitter loop up to, and including, the final actuation devices. These test jack inputs have an auto-matic disconnect to the transmitter input, and therefore a permanent bypass switch is not needed for testing. Testing also does not affect the ability of the system to respond to a valid trip signa In conformance with the ATWS Rule, the ARI is diverse, electrically independent, and physically separated from the RTS. Table 1 summarizes the differences between the ARI and the RT Table 1. ATWS: ARI - RTS COMPARISON Component AR1 System RTS Level Sensor Rosemount Rosemount (diversity not required)
Pressure Switch Rosemount Rosemount (diversity not required)
Trip Unit Foxboro Rosemount logic Foxboro(digital) GE HFA Relays
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Component AR1 System RTS Valves VAlCOR ASCO Energize-t De-energize-to-Function Function power Supply 12S VDC 120 VAC Battery Backed Motor-Generator 2.2 Standby tig % Co* col System The SLCS is a manu ' / initiatent system for injecting a boron solution into the reactor vessel. Since construction permits for PBAPS 2 & 3 were issued prior to July 26, 1984, the existing SLCS system with manual actuation is acceptable and automatic SLCS initiation is not required. The licensee has a two-pump SLCS configuration, and has modified the PBAPS 2 & 3 Technical S)ecifications to comply with the ATWS requirements as approved in the SE Tie equivalency requirements for injection flow rate, enrichment, and solution concentration for PBAPS 2 & 3 were reviewed and verified by the inspectors to meet the requirements of the ATWS Rule. The PBAPS 2 & 3 Technical Specifications (PBAPS - LCO - 3.4) have been modified to include surveillance requirements to ensure that these system parameters remain in compliance with the ATWS Rule requirements. The control switches and annunciator alarms for the SLCS are located near other shutdown functions in the main control room, such as the CRDS and the ARI using good human factors engineerin .3 Recirculating Pump Trip 1hc RPT is a two channel system and is initiated by either low reactor water level or high reactor pressure, and was implemented at Peach Bottom 2 & 3 prior to commercial operation. Under conditions indicative of an ATWS, a single coil is energized to trip each recirculation pump MG set drive breake TheRPTfunctioniscombinedwiththeARI(i.e.,ARl/RPT)andtheoriginal RPT has been modified to use the same Rosemount transmitters as the AR1, 1 replacing the pressure and level switches previously used. The RPT also uses 1 the Foxboro microprocessor system to perform the trip unit and logic function This implementation conforms to the design approved by the staff in the SE All controls and indications for the RPT trip sy.tus are located on the recirculation pump panel .0 Programs and Procedures Since the ATWS equipment at the Peach Bottom Atomic Power Station have been included in the Technical Specifications, all plant programs and procedures applicable to systems covered by the Technical Specifications have been addressed for the AR1, SLCS, and RP _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ _ _ _ _ - _ _ _ _ _
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4 Quality Assurance (0A). Operations, and Maintenance activities for the ARl, SLCS, and RPT are performed in accordance with procedures and requirements contained in the Technical Specification Training for the AR1, SLCS, and RPT have been incorporated into ne licensee's ,
program. Training was performed prior to the startup following implementation of the AR1/RPT systems using Plant Startup Procedure (PSU-0060), ' Alternate Rod Insertion," and for the SLC$ by Licensed Operator Training (LOT-0310), " Standby Liquid Control System." The plant simulator has not yet been modified to include the ATWS interfaces in the control room, but simulator training includes scenarios requiring knowledge and interactions with the ATWS systems per Simulator Exercise Guide (SEG-0215R), "ATWS Training."
4.0 LICENSEE PERSONNEL CONTACTED Personnel Function J. Brassard ReactorEngineering(RPTSystemsEngineer)
G. Budock Reactor Engineering (ARI Systems Engineer)
J. Budrynski Reactor Engineering Supervisor J. Coyle Power Distribution Engineering Supervisor R. Franssen Reactor Engineering (AR1 Systems Engineer)
8. Frisby 1 & C Engineering D. McClellan OperaterTraining(Sr. Instructor)
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5.0 RFFERENCES Letter,S.L.Daltroff(PhiladelphiaElectricCompany)to Denton (U.S. NRC), " Compliance with the Anticipated Transients Without Scram ( ATWS) Rule,10 CFR 50.62." October 17, 198 . Letter,M.J.Cooney(PhiladelphiaElectricCompany)toH.R.Denton (U.S. NRC), " Peach Bottom Atomic Power Station Units 2 & 3 Compliance with 10 CFR 50.62," June 30, 1986, Letter, J. W. Gallagher (Philadelphia Electric Company) to D. Muller (U.S.NRC),"ATWSRule(10CFR50.62)PeachBottomAtomic Power Station Modifications," April 3, 198 Letter,R.E. Martin (U.S.NRC) tog.A. Hunger (PhiladelphiaElectric Company), " Safety Evaluation Report on Compliance with ATWS Rule 10 CFR 50.62 c(3) and c(5) Relating to ARI and RPT Systems," December 21, 198 . Letter, R. J. Clark (11.S. NRC) to E. G. Bauer, Jr. (Philadelphia Electric Company), " Standby Liquid Control System," June 2,198 . U.S. NRC Inspection Manual . Temporary Instruction 2500/?0, Revision 1, " Inspection to Determine Compliance with ATWS Rule, 10 CFR 50.62."
March 24, 198 . Letter, J. W. Gallagher (Philadelphia Electric Company) to t!.S. NRC,
" Peach Bottom Atomic Power Station Units 2 & 3 Alternate Rod Insertion Modification Pursuant to ATWS Rule," April 21, 198 . Letter, G. Y. Suh (U.S. NRC) to G. A. Hunger. Jr. (Philadelphia Electric Company) " Review of Peach Bottom Units 2 & 3 ARI System Function Time," February 9,199 !
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ATTACHMENT 3 SURVEILLANCE TESTS-0BSERVED i-ST 6.5F-3, "HPCI Pump Valve, Flow, and Cooler," performed on 4/6/90 SP 253, "ESW Booster. Pump Discharge Valve Throttling Limits," performed on L 4/12/90
'ST 8.8-3A/B/C/D, " Unit 3A/B/C/D Battery Test - Yearly Inspection, performed on j 4/30/90
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[ ST.6.16, " Motor Driven Fire Pump Operability-Test,"' performed on 5/1/90 L -ST 21.3. " Adjustment of HPCI Overspeed Trip Reset Test, " performed on 5/1/90 ST 9.12 "D-2 Drywell Temperature Monitor," performed on 5/1/90 ST 12.15.3-2, "HPCI Pump Room Contaminated Piping Inspection," performed 5/1/90 SI2T-2-4805-AICS, " Calibration Check of Drywell Temperature Instruments TR
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4805," performed 5/3/90
$113N-60A-APRM-DICW, " Average Power. Range Monitor "A" Calibration / Functional
- Check," performed on 5/3/90 *
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