IR 05000440/1997009
| ML20202D008 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 11/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20202C981 | List: |
| References | |
| 50-440-97-09, 50-440-97-9, NUDOCS 9712040117 | |
| Download: ML20202D008 (21) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION lil
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Docket No:
50-440 License No:
NPF-58 Report No:
50-440/97009(DRP)
Licenwe:
Centerior Servios Company Facility:
Perry Nuclear Power Plant Location:
P. O. Box 97, A200 Perry, OH 44081 Dates:
June 24 - August 8,1997 l
Inspectors:
D. Kosloff, Senior Resident inspector J. Clark, Resident inspector G. Harris, Senior Resident Inspector, Fermi Plant I
Approved by:
T. J. Kozak, Chief Reactor Projects Branch 4 9712040117 971126 PDR ADOCK 05000440
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EXECUTIVE SUMMARY Perry Nuclear Power Plant, Unit 1 NRC Inspectior. Report No. 50-440/97009(DRP)
This inspection included aspects of licensee operations, maintenance and surveillance, engineering, and plant support. The report covers a 7-week period of resident inspection.
Operations The operators responded appropriately to a partialloss of reactor protection system
power and received prompt support from maintenance and engineering. Short tenn corrective actions and planned corrective actions were appropriate (Section 01.1).
During observations of the receipt, inspection, and storage of new fuel, the inspectors
observed that personnel were aware of their responsibilities and procedursl requirements, procedures were properly used, and records were cerectly maintained. Proper reactivity centrols were emphasized and maintained during fuel movements. Preparations,for refueling were also well controlled (Section 03.2).
Plant operations were conducted in a safe and efficient manner with appropriate attention
to overall plant nsk and control of,eactivity. Control of the July 20,1997 power changes was effective with appropriate oversight of reactivity manipulations. Operators later identified that planned electrical work increased the probability that reactor core isolation cooling could be unavailable; the work schedule was modified to reduce risk (Section
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04.1).
Tumover and evolution briefings were clear and effective. Crew members actively
contributed to the successful completion of operations activities by displaying strong questioning attitudes during briefings and plant evolutions (Section 04.2).
A reactor feedwater pump turbine trip was caused by a combination of procedural and
operator performance weaknesses. The licensee's sh7rt term corrective actions were appropriate. However, the inspectors identified that ths licensee had not evaluated the potential for similar procedural deficiencies in other annanciator response procedures (Section 08.1).
Maintenance and Surveillance The inspectors identified that the licensee's procedure on control of surveillance tests did
not include guidance on how to evaluate test results versus post test changes to acceptance criteria (Section 03.1).
Generally, work p!anning and conduct of maintenance and testing was appropriate. The
overall maintenance backlog was reduced. However, some instances were noted where the control of emergent work was not fuity effective, there were delays in restoring safety-related equir' ment to service, and there were cases where planning was not fully effective (Section M1.6).
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The inspectors identified a weakness in engineering communications with operations on
post modification testing of an ECCS power supply replacement. The inspectors identified a violation for maintenance technicians failing to use a maintenance instruction and the licensee identified inadequate use of a post maintenance test procedure (Section M1.6).
The inspectors observed that maintenance, engineering, and health physics personnel
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quickly developed a plan for repair of a hydraulic fluid leak. Communications between the different departments were clear and timely, and the operators were promptly updated as new information became available (Section M1.5).
Enoineering The inspectors identified poor communications between engineering and operations that
increased plant risk due to a delay in responding to a missing fuse. NRC intervention was required for appropriate resolution of the issue. Licensee personnel responded appropriately once they understood the significance of the issue (Section E2.1).
The inspectors concluded that the licensee's initial evaluation of previously unidentified
reactor pressure vessel cooldowns was appropriate. An LER is planned (Section E2.2).
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Ruort Details Summerv of Plant Status The plant operated at full power for most of the inspection period. On July 6 reactor power was reduced to about 90 t ercent for tetting, and the plant was restored to full power the same day.
On July,:0 reactor power was reduced to about 76 percent for valve testing and control rod adjustments, and the plant was restored to full power the same day.
1. Operations
Conduct of Opetations Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant sperations.
01.1 Sourious Onenina of Electrical Protective Assembly Breaker a.
Insoection Scope (71707)
The inspectors reviewed the licensee's response to a partial loss of power to the reactor protection system (RPS). The inspectors reviewed logs and reports, observed operator control of the plant, cbserved equipment troubleshooting, and discussed the event with operators, engineers, and maintenance personnel.
b.
Qhservahons and Findinan On July 13,1997, loss of normal power to RPS Bus 'B' caused a partial containment isolation that uffected several systems. The inspectors verified that plant equipment had responded property to the loss of power and that the operators were using the appropriate instructions to restore equipment to its normal configuration.
The licensee determined that the RPS Bus "B" power loss had been caused by an electrical protective assembly (EPA) breaker (1C71-S003D) trip. There were two EPAs in series for each power supply. Normalty, the operators would have transferred RPS Bus *B' to its altemate power supply, which was available. However, recovery from the event was delayed because RPS Bus 'A' was on its attemate power supply; only one RPS bus can be on attemate power at a time. The licensee verified that there were no indications of problems with the normal power supply for RPS Bus 'B' and re-energized RPS Bus "B" from its normal power supply so that RPS Bus 'A' could be retumed to its normal power supoly. The licensee considered 1C71 S003D inoperable, rernalned in Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.8.2, Required Action A.1, and monitored power supply electrical parameters. On July 14, RPS Bus 'A' was retumed to its normal power supply, RPS Bus *B' wat powered from its attemate supply, and the licensee exited the TS LCO required action. The licensee installed a newer design electronic logic board in EPAs 1C71-S003D and 1C71-S003B, the redundant EPAs for the RPS Bus 'B' normal supply.
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The i. designed logic boards had been purchased an a result of an eariier spurious EPA trip that had been ieported in licensee event report (LER) 97-03. The inspectors will complete their evaluation of corrective actions for this iswe wnen LER 97-03 is reviewed for closure. Sufficient logic beards had been ordered to replace all eight EPA logic boards, but the other six logic boards had not been received. The licensee also installed a new molded case circuit treaker in 1C718003D, and began monitoring the RPS Bus "B" normal power supply while it supplied an electrical load bank. The inspector reviewed portions of the data recorded during the monitoring; neither the inspectors nor the licensee observed any power supply anomalies,
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a Conclusions Ybe inspectors concluded that the eperators had responded appropriately to the event anc received prompt support from maintenance and engineering. The inspectors also concluded that the licensee's short term corrective actions and planned corrective actions were appropriate.
01.2 Unexpected Hiah 2ft1Egp Core Sorgy Suction Switch dilanal a.
In}pection Scope (71707. 92901)
The inspectors reviewed the licensee's evaluabun of an unexpected engineered safety g
features (ESF) logic signal that requirsd the high pressure core spray (HPCS) system
pump suction to switch from th6 condensate storage tank (CS'i) to the suppression pool.
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The inspectors also reviewed logs and discussed the event with the operators who were
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on shift at the time.
b.
Observations and Findinas On July 15,1097, during containment ventilation operations, an expected reduction in containment pressure caused a small increase (from 18.17 feet to 18.27 feet) in suppression poo! level and gonerated a HPCS suction switch (from CST to suppression poal) ESF logic signal. No actv91 vabe movement occurrod because HPCS was already lined up to the suppression pool. Although the operators knew a sappression poollevel increase would occur and had considered the possibility of receiving the ESF logic signal, they concluded that there was M.ient margin between the expected ESF logic set point (18.40 feet) and the Indicated p >ollevel (18.17 feet) to avoid an ESF logic signal. The anticipate;d transient levcl was also expected to be belor the restoration level (18.35 feet)
in the associated alarm response instruction (ARI). Thei sfore, the operators did not log their anticipation of a possible ESF actuWon. One of the operators also !nformed the inspectors that !f they had thought they wer6 Goint,'c get an ECF logic signal, they would have lowered poolleve; befwe ventilating the contaircnent. The operators were unaware that set point dri't, within allowable tolerance, had caused the actual ESF logic set point to drop below the ARI restoration level. Upon receipt of the ESF logic signal, the Lperators recognized the cause of the signal and reported it via the NRC emergency notification system (ENS).
When the licensee reviewed the reportsbility decision, they concluded that the event was not reportable, the operators retracted the teport via the ENS on August 6, and the licensee did not plan to subrnit an LER. The decision to retract the ENS report was
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based on the discussion of 10 CFR 50.73(a)(2)(iv)in NUREG-1022, * Licensee Event Repor1 System," which included the statement " Operation of an ESF as part of a planned operational procedure or test need not be reported? The licensee stated that the containment venting was a planned ope ational procedure and that there was expectation of a possible ESF actuation. While the inspectors agreed '. hat the activity was planned, the operators who performed tho evolu'Jon had concluded that the logic actuation was unlikely and therefore they did not expect the actuation. The licensee further stated that the operators should have made a log entry that the ESF actuation was a possibility. The licensee therefore concluded that ine issue related to the event was a log keeping weakness, not a reportabiltiy issue. The inspectors observed that the opr.1stors later began making " potential ESF actuation" log entries before planned operational procedures that could cause a HPCS suction shift.
10 CFR 50.73(a)(2)(iv), requires that the licensee shall submit a licensee event report (LER) within 30 days of the discovery of any event or condition that resulted in a manual
or automatic actuation of any engineered safety feature (ESF). Automatic actuation of
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the electronic logic that was intended to switch the llPCS suction from the CST to the suppression pool was an actuation of an ESF. While the licensee has taken some
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actions which may improve proper repo 1ing of this type event, they have not submitted an 10 CFR Part 50.73 report documenting the condition. Tha failure to submit an LER is considered a Violation (50-440/97009-01(DRP)) of 10 CFR Part Sn.73.
c.
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This ESF actuation had no adual or potential safety consequences. The inspectors concluded that the ENS event notification thould not have been retracted and that an LER should be submitted. One violat!an was identified.
O3 Operations Procedures and Documentation 03.1 ElRDdbv Liould Control Pumo (SLC) Minimum Fjgg a.
Inspection Scope (61726. 92903)
The inspector evaluated the surveillance testing and minimum flow operability rietermination of SLC Pump "A."
b.
Observations and Findinas in June 1997, Perry TS Surveillance Requirement (SR) 3.1.7.7 required a minimum flow of 41.2 gpm through each SLC subloop. Surveillance instruction (SVI) C41-T2001 A,
" Standby L! quid Control A Pump and Valve Operabili+y Test," Revision 0 (October 1988),
was used to demonstrate the operability of the SLC pump by verifying the minimum flow passed through a rotometer during testing.
The inspectors reviewed the following sequence of events:
(1)
June 4,1997: Design Change Control ".0C-001 (not approved) revised Engineering Calculation C41-16 to ind..; ate that, due to rotometer inaccurarias,
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TS minimum flow of 41.2 gpm could not be assured unless greater than f2.4 gpm was read on the test rotometer.
The rotometer used for the test had scale divisions every 2 gpm, therefore, per licensee procedures, the minimum readability of the rotometer was 1 gpm (% the minimum scale division). This required a minimum readable value of 43 gpm for the SLC pump to be judged operable when using the rotometer.
(2)
June 8 ar,d 11,1997: SLC Pump *B" and 'A' SVI both recorded flow at 43 gpm.
(3)
Ju!y 20,1977: SVI-C41 T2001 A was performed with a discharge flow rate of 42 spm recorded for SLC Pump "A". This met the acceptance criterion then included in the SVI (41.2 gpm).
(4)
dy 24,1997: DCC-001 to Calculation C41-16 was approved, establishing the new minimum flow acceptance criterion. The new cmenw,vas consistent with American Society of Mechanical Engineers (ASME) Code,Section XI, Table IWP-3100-2.
(5)
July 28,1997: A licensee design engineer issued Memorandum DES-97-1172,
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indicating that the minimum required test ilows for the SLC pumps were 42.4 gpm if measured witn the installed rotometer or 42.0 gpm if measured with a more accurate turbine flow meter.
(6)
July 29,1997: The SLC responsible system engineer wrote PlF 97-1225 questioning the operability of the "A" SLC Pump. Operations personnel requested an engineering operability determination.
(7)
July 30,1997: An engineering operability determination was submitted to operations that recommended SLC Pump "A" be considered operable because if a more accurate turbine flow meter, although not addressed in the SVI, would have been used for the test, it would have indicated that flow was greater than 42.4 gpm.
The licensee based this conclusion on test data which correlated insta!Iec'
rotometer and test turbine flow meter readings. T he operability determinstion stated that the SVI was required to be performed using the turbine flow m63r "as soon as reasonably achievable * The shift supervisor accepted the engineTing operability determination after discussing it with engineering personnel.
(8)
Augt.st 2,1997: SLC Pump "A" was tested under WO 97-2241 with a turbine flow meter and indicated flow was 45.0 gpm.
The inspectoa wcre concemed that the licensee had ider.tified that the SLC Pump "A" did not meet its TS required flow rate. but operations personnel did not decle.re the pump inoperable on July 29 when the shift upervisor was informed of the new flow test acceptance criterion. Had SLC Pump "A" been declared inopereble the plant would have been in TS LCO 3.1.7, Required Action A.1, whic61 required the plant to be shut down if the pump could not be restored to service within 7 days. The successful test of SLC Pump "A" was completed on what would have been the fourth dcy after entry into
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the TS LCO Required Action. The inspectors review of PAP-1105, *3urveillance Tes,t C5ntrol," revision 8 (July 18,1995) identified that while the procedure provided guidance on what to do if parameters are found outside acceptance criteria while performing the test, it did not include guidance on how to handle post test changes to acceptance. This is considered a Violation (50-440/9700942(DRP)) of 10 CFR 50, Appendix B, Criterion V, * Instructions, Procedures and Drawings," which required that activities
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affecting quality be prescribed by procedures appropriate to the circumstances, c.
Conclusions Engineering personnel's assessment of minimum flow raquirements for the SLC pumps tnd the system engineer's generation of a PIF questioning pump operability were a ppropriate; however, the direction to operstbn's personnel did not address the situation where acceptance criteria were char,ged after a test had been performed.
03.2 Preparations for Refuelina a.
Insoection Scoce (60705)
Using inspection Procedure 60705, the inspectors reviewed and observed licensee preparations for refueling, b.
Observations and Findinas Preparation of refueling equipment wa; planned and begun well in advance of planned use of the equipment. A detailed written schedule was periodically reviewed by
management to ensure that appropriate resources were applied to equipment preparation.
During observations of the receipt, inspection, and storage of new fuel, the inspectors observed that personnel were aware of their responsibilities and procedural requirements, procedures were property used, and records were correctly maintained. Proper reactivity controls were emphasized and maintained during fuel movements. Control of foreign material entry was appropriste and the licensee responded promptly and appropriately to a screw noted to be missing from a torque wrench and a snap ring noted to be missing from refueling equipment. The screw was found and the snap ring was not. Twenty new fuel rssemblies that had been stored before the search for the snap ring was completed, were reinspected. Problems encountered were promptly entered in the licensee's corrective action program.
c.
Conclusions Preparations for refueling were well controlled, a
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Operator Knowledge cred Performance 04.1 Power Operations a.
Inspection Scone (71707)
The inspectors conducted numerous observations of daily operations activities. Panel w?lkdowns were conducted. The inspectors questioned operators about plant and equipment status, and maintenance activities. The inspectors obsersad the July 20 power reduction and retum to full power.
b.
Observations and Findinas The inspectors observed appropriate operator attention to plant maintenance and plant alarms. Procedures and instructions were routinely and effectively used. Control of the July 20 power changes was effective with strong oversight of reactivity manipulations.
The operators were auentive to the risk impact of maintenance and other changes to plant equipment status. The inspoetors did not observe any deviations from the licensee's foimal verbal communications policy.
The operators identified that planned electrical work would have increased the probability that the reactor core isolation cooling (RCIC) system could be unavailable. The operators requested a review of the weekly risk evaluation, which confirmed that there was an increased risk. Maintenance planning personnel modified the work schedule to reduce the risk. The electrical work was completed without incident and RCIC remained
available. The operations superintendent initiated a PIF to enter the planning weakness into the corrective action system.
Conclusiom
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Plant operations were conducted in a safe and efficient manner with appropriate attention to overall plant risk and control of reactivity.
O4.2 Shift Tumover and Evolution Briefinas a.
Inspection Scoce (71707)
The inspectors observed many shift tuniover and plant evolution briefings, and
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associated work activities.
b.
Qbservations and Findinas The inspectors noted that there were thorough discussions of planned work, plant equipment problems, and available resources. The inspectors observed that written
" safety cultures" were posted in the tumover arua, and supervisors often asked individuals to explain how they planned to apply one of the safety cultures during anticipated shift activities. Observed evuution briefings included procedure reviews, expected equipment operation, and appropriate focus on the specific duties of participating individuals. Crew members and involved personnel from other organizations actively participated in the briefings. Conduct of the evolutions was consistent with the
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briefings. The inspectors observed that operators in the plant frequently questioned observed conditions during evolutions and control room operators promptly determined whether the observed conditions were appropriate, if they were not immediately able to respond to the operators in the plant.
c.
Qonclusions Tumover and evolution briefings were clear and effective. Crew members actively contributed to the successful completion of activities by displaying strong questioning attitudes during briefings and plant evolutions.
Miscellaneous Operations issues 08.1 ffdqged) Unresolved item (50 440/97007-03(DRP)) Reactor Feedwater Pumo Turbine
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101ongtion Scope (71500. 71707. and 92901)
The inspectors reviewed the circumstances surrounding a reactor feedwater pump turbine (RFPT) trip on June 1,1997. The review identified operational anc procedural deficiencies, b.
Observatigas and Findinos On June 1,1997, the " Auxiliary Condenser A Level High* annunciator came in three times. Using Alarm Response Instruction (ARI) H13-P870-8, " Auxiliary Condenser A Level High," the first two times the operators successfully retumed level to an acceptable point. On the third response, the operator, who was not involved in the previous alarms, was not successfulin lowering level and the RFPT tripped on low condenser va uum.
Based on review of the RFPT trip, the inspectors and the licensee independently identified that procedure ARI H13-P870 8 for manually controlling water level in the auxiliary condenser was deficient in a number of areas. (Note that an identical procedure existed for the "B" RFPT annunciator.)
(1)
The procedure referenced the wrong computer point to monitor while manually adjusting level. The procedure referenced computer point 1N12EA0015 when it should have referenced computer point 1N12EA015. This difference resulted in the wrong computer po;M being selected and caused operator confusion during efforts to reduce condense. Invel.
(2)
As vTitten, the procedure required, but did not explicitly state, that Steps 1 and 2 were to be performed concurrently. Step 2 of the procedure required the compu".er point to be monitored if level exceeded 12.75 inches. Given that the annunciator alarm point was set at 13.75 inches, Step 2 by default had to be performed.
(3)
Giep 2 also required the operators to trip the RFPT if water level, as monitored by computer point 1N12EA015, exceeded 100E A computer indication of 100 percent corresponded to 12.75 inches actual level, therefore, any time the
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alarm came in (set point 13.75 inches), the operator, by procedure, should have tripped the RFPT. This did not appear to be consistent with the intent of Step 1, which attempted to lower level to avoid a plant transient caused by an RFPT trip.
(4)
The procedure indicated that a 100 percent reading on the computer point corresponded to the condenser being approximately half full, but did not provide an equivalentlevelin inches.
In addition to the procedural issues, deficiencies in operator implementation of tile procedum also were identified.
(1)
The operators were r'ot knowledgeable of the set points and requirements of the procedure. For example, operators did not recognize that at the alarm condition tM procedure required Step 2 to be podsmed, on two occasions on June 1 the operators only performed Step i to lower level.
(2)
On a third use of the procedure, the operators faileo to identify that the computer point being monitored was train condenser level and not RFPT auxiliary condenser level. This led to confusion because the ccmputer point read
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3.7 inches while the control panel meter read more than 12.75 inches with a high level condition alarming. The error was caused by a procedural deficiency, previously noted, and by the operato. not adequately verifying the point being monitored (3)
The unit supervisor observed all three alarm responses without identifying the deficiencies. The shift supervisor directed the first two alarm responses without identifying the deficiencies.
The licensee's corrective actions appropriately addressed the specific procedure deficiencies and the licensed operator performance issues. However, the corrective actions did not address why the procedural errors were not identified during previous reviews, nor if other annunciator procedures may have similar problems. Pending additional information from the licensee on the corrective action weaknesses, this item is considered an Inspection Followup item (50-440/97009-03(DRP)).
Conclusion A deficient procedure and poor licensed operator p.~ormance resulted in an RFPT trip and a plant transient. Corrective actions were narrowly focused on the specific annunciator response procedure and did not consider whether the same types of deficiancies existed in other annunciator procedures.
II. Maintenance M1 Conduct of Maintenance The inspectors used inspection Procedures 61726 and 62707 to evaluate several work activities and surveillance tests. The inspectors observed emergent work as well as planned ms5tenance conducted dudng normal operations and divisional equipment outages.
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M1.1 On-line Maintenance Du-ina Divisional Eauipment Outaaes
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Inspection Scope (61726. 62707. and 92902)
The inspectors reviewed licensee preparation and plans for a Division 1 equipment outage, a RCIC equipment outage, and work on Division 1 and 2 control room ventilation equipment. The inspectors also observed related maintenarece, modification and testing activities.
b.
Observations and Findinas The activities observed were generally accomplished effectively with appropriate use of drawings and written instructione. Licensee personnel continued to maintain a low threshold in using the PIF process to identify issues and potential prob!ams. This included examples of personnelidentifying their own errors. The inspectors observed that oesign changes were used to replace emergency core cooling system (ECCS)
instrumentation inverters with more reliable solid state power supplies. The inspectors questioned the use of a channel check to verify operability of the new Division 2 power supply. Engineering, maintenance, arid operations personnel on day shift were not familiar with the justification for using the channel check. The picnt menager promptly identified two parallel paths to verify that the channel check was appropriate. The design engineer for the project, who was on the cvening shift, confirmed that the channal check was appropriate based on the earlier evaluation of qualification testing of new power supplies that had bean performed as part of design process.
The inspectors observed a modification of the leakage control sptem circuitry to prevent unnecessary RCIC initietions. The modification, installed during a RCIC outage, was technically sc<.nd. However, during post-maintenance testing of the RCIC turbine, the licensee encountered several unrelated emergent problems with turbine control which delayed restoration of the RCIC system. Licensee oorsonnel fixed the problems and initiated PIFs to enter the issues in the licensee's corrective action program for trending and further evaluation.
The inspectors observed various work activities conducted during a Division 1 equipment outage, including replacement and testing of the "A" Emergency Service Water (ESW)
Pump. TN ESW pump replacement, the most complex activity in the Division 1 outage, was well planned and executed, and remained on schedule until the licensee identified a failure of the pump motor lower bearing cooling water piping. The licensee initiated a PlF to evaluate the failure and attempt to determine if it wrs a prevjsting condition or occurred during the on-line work. The ESW pump was restored to service within the applicable TS LCO allowed outage time.
M1.2 On-line Maintenance for Emeroent Work and Work Not Reauirina a Divisional Outaae a.
Insoection Scope (61726. 62707. and 92902)
The inspectom observed emergent work and maintenance and testing activities that did not require a divisional equipment outage.
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b.
Observations and Findinos Although the licensee reduced its backlog of corrective and general maintenance, the emergent priority 2 and 3 work backlog usually remained above the licensee's unwritten goal of ten items. Operations personnel promptly identified high priority emergent work.
The Fix It Now (FIN) team and prompt maintenance pianning prevented the emergent work backlog from growing. Licensee management recognized that reducing the emergent work backlog would be an Indicator uf improved equipment reliability. The inspectors observed good coordination between engineering, operations, and maintenance la 'he operability evaluation of a failed safety-related control room ventilation vortex dampei and its eventual repair.
During scheduled maintenance, technicians had difficulties obtaining a seal on safety-related control complex chiller electrical penetrations. The work, not completed by the end of the inspection period, took much longer than planned, although the TS LCO allowed outage tima had not been exceeded. Licensee personnelinitiated PlFs on the delays encountered to document them in the licensee's corrective action system.
The inspectors observed that excavations for nonsafety-related service water modifications during the refueling outage had been appropriately controlled to avoid damage to safety-releted underground structures.
The inspectors identified a violation related to standby liquid control pump testing (see SecHon O3.1).
M1.3 Maintenance of Control Complex Chill Water Valve a.
Inspection Scope (62707 end 92902)
On July 8,1997, the inspectors observed the replacement of the stem packing for safety-related Control Complex Chill Water (CCCW) Valve OP47-F085A and reviewed the associated work order (WO).
b.
Observajions and Findinas The inspectors noted that the binder containing WO Number 97-0873, which included the work instructions for the. valve packing replacement, was not opened during the work observation. The vah a packing was being replaced because of a packing leak that had been identified earlier by the inspectors. After the packing had been replaced, the inspectors reviewed the WO. Section 130 of the WO directed that the valve be repacked in accordance with General Maintenance Instruction (GMI) 0061, " Valve Packing Instructhn," Revision 2 (January 26,1996). GMI-0061 had numerous steps that were required to be checked or initiated as the steps were accomplished. None of the steps had been checked or initialed, and technical details of the work accomplished had not been recorded in specified locations in the instruction. A representative for the packing sendor had taken notes on a form that was not part of the WO. Some steps in the GMl had not been performed. The inspectors discussed the WO with maintenance supervisors. The supervisors stated that the GMl was not well suited for the type of packing used (TEFLON rings) and that the steps not performed were not necessary during replacen.ent of the TEFLON packing. No exp;anation was offered for not having
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wtitten, or modified, a procedure appropriate for TEFLON packing. The inspectors checked the valve near the end of the inspection period and noted that the packing was not leaking.
TS 5.4.1.a. required that written procedures shall be implemented covering the applicable procedures recommended in RG 1.33, Revision 2, Appendix A, February 1978. RG 1.33,
" Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," stated, in part, that maintenance that can affect the performance of safety-related equipment (Section 9.a) should be properly performed in accordance with written procedures appropriate to the circumstances. WO p7-0873 controlled maintenance that could have affected the performance of safety-related Valve OP47 F085A. The failure to perform maintenance on Valve OP47-F085A in accordance with WO No. 97-0873 is a Niolation (50-440/97009-04(DRP)) of TS 5.4.1.a.
M1.4 Inadeouale Post Maintenance Test Affects Emeroency Dies 01 Generator Ventilation a.
hipfction Sco9e (61726. 62707. and 92902)
The inspectors reviewed the licensie's initial corrective actions for a Division 3 emergency diesel generator (EDG) ventilation fan that maintenance and engineering personnel discovered was rotating backwards, b.
Qbservations and Findinos On July 17,1997, the FIN team, assisted by a responsible system engineer (RSE), was troubleshooting a reported problem with safety-related Division 3 ECK3 Room Supply Ventilation Fan 1M43C0002C. The RSE determined that the fan was rotating backwards, which prevented the fan from performing its safety function of cooling the EDG room.
The l'.censee determined, by records review, that the last work done on Fan 1M43C0002C was during cleaning of a Division 3 motor control center (MCC)in May 1997. The inspectors reviewed the lifted lead record for that work and noted that the power leads for the fan had been independently verified as correctly landed upon completion of MCC cleaning. However, the fan was rotating backwards because two o'
the leads had been reversed from the positions indicateci by the lifted lead record. The licensee had interviewed the maintenance workers who had initialed the lifted lead record and they had no explanation for the dif,'erence between the observed condition of the leads and the record. The licensee had not performed any post maintena.cc testing of
fan operation. Althougn a surveillance teet (SVI-E22-T1319) of the EDG had been performed after the MCC work, no problem had been reported with Fan 1M43C0002C.
During the test, both fans start and one is normally tumed off shortly after it starts. The j
problem with the fan was noted on July 11,1997, when a ventilation low flow alarm was received during the routine performance of SVI-E22-T1319. The inspectors reviewed Updated Safety Analysis Sections 7.3.1 and 9.4.5 and determined that only one of the two EDG room fans was required to be operable for the EDG to be operable. The licensee determined by records review that the other fan had remained operable.
At the end of the inspection period, the licensee was actively persuing root causes of the event and developing corrective actions. Pending the licensee's prompt assessment, this item is considared an Unresoived item (50-440/97009-05(DRP)).
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Mt.5 Reoair of Hydraulic Oil Leak
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a.
Insoection Scope (37551. 62707. 71750. 71707. and 92904)
The inspectors observed control room communicaticas among maintentace, operations, engineering, and health physics personnel after the operations foreman identified a turbine control valve hydraulic fluid leak.
D.
Qbservations and Findinos
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The inspectors observed that maintenance, engineering, and health physics personnel quickly developed a plan for repair of the hydraulic fluid leak. Communication between the different departments was clear and timely, and the operators were prompty updated as new information became available. The leak was repaired and a clamp was added to prevent later leakage. Maintenance personnel identified improvement items on a PlF.
M1.6 Conclusions on Conduct of Maintenance Generally work planning and conduct of maintenance and testing was appropriate. The overall maintenance backlog was reduced. However, control of emergent work was not always fully effective, there were delays in restoring safety-related equipment to service, and there were cases where plann;ng was not fully effective. The inspectors also identified a weakness in engineering communications with operations on post modification testing for ECCS power supply replacement. The inspectors identified a violation for maintenance technicians failing to use a WO during CCCW valve repacking and the licensee identified inadequate post maintenance testing.
'e8 Miscellaneous Maintenance issues (62707,61'26,90712,92700, and 92902)
M8.1 (Chsed) LER 50-440/95-005-00: " Inverter Failure Results in Reactor Scram." This event was discussed la inspection Report Nos. 50-440/95007 and C. The inspectors verified that the licensee had performed a design change to prevent e similar inverter failure from causing an unnecessary automatic reactor shutdown. The inspectors also verified that another design change replaced the inverter with a more reliable power
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M8.2 (Closed) LER 50-440/95-006-00: " Engineered Safety Feature (ESF) Actuation during Inverter Restoration." The inspectors ver.'ied that the licensee had performed a design change to replace the inverter with a more reliable power supply. This has reduced the number of power supply restorations. The inspectors also verified that the licensee had improvtid the applicable system instructions by including specific information on power supply restoration to minimize the probability of an ESF actuation during power supply restoration, t
68,3 (Closed) LER 50-440/95-008-00: " inverter Failure Results in Reactor Scram." This event was discussed in Inspection Report No. 50-440/95008. The inspectors verified that the licensee had performed a design change to prevent a similar inverter failure from causing an unnecessary automatic reactor shutdown. The inspectors also verified that another design change replaced the inverter with a more reli7ble power cupply.
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i M8.4 (Closed) LER 50-440/96-002-00: " inverter Failure Results in Partial High Pressure Core Spray System initiation." The laspectors verified that the licensee had performed a design change to replace the inverter with a more reliable power supply.
Ill. Ennineerina E2 Engineering Support of Facilities and Equipment E2.1 Transmission Yard Protective Relavs 3.
Inspection Scope (37551. 71707 and 92933)
The inspectors evaluated engineering resolution of a missing fuse for e switchyard backup protective relay circuit.
b.
ObservMions and Findinos On July 21,1997, an individualinspecting the boundary between Unit 1 and the abandoned Unit 2 noted that fuse R42-F0303 was not installed. He determined that the missing fuse disabled the Unit 2 overall differential relay (86U) that provided backup protection for the section of main switchyard bus between breakers S620 and S622 (S-10PY-BUC). Primary protecuve relaying was not affected. The individual promptly initiated PIF 9'i-1178 *o erter the condition in the licensee's corrective action system.
o The shift technical adv sor, aher reviewing the PIF, concluded that there was no potential operability concem and forwarded the PlF. On July 24, a design eng:neer evaluated the impact of the missing fuse and sent a memo to the operations superinter' dent which stated that the fuse had probably never been installed, and that, if the primarv protection failed, a fault on S-10-PY-BUS would be isolated by " clearing of the transmission fines."
The same memo stated that
"There is no need for an OPERABil lTY DETERMINATION. The transmission yard and all associated breakers are presently in-service with no adverse effect as a result of this finding. Additionally, considering both PNPP's and CEI's history of transmission yard bus failures, it is unlikely that a transmission yard bus fault will occur. Based on the above, the anticipated... response will require that ali necessary actions to be taken to place both the 87U and the 86-2 relays in servics."
The phrase," clearing of the transmlasion lines," meant that there would be a complete loss of offsite power (LOOP); the operators and operations management did not understand that.
USAR Section 8.2, "Offsite Power System," stated that "The switchyard design incorporates primary and backup relaying." The licensee concluded that backup relaying had never been functional for S-10-PY-BUS.
i The inspe : tors reviewed the engineering memo in the control room on July 25, and could not determine if the fuses had been installed. The inspectors asked three ser. lor reactor operators if the fuse had been installed; they were not sure, even aftor reading the memo.
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On July 28, a written plan was approved to verify that the appropriate Unit 2 relays were property set and to install the missing fuse. No schedule was included. On August i the inspectors determined that the FIN team had the WO for the plan. The inspectors questioned the FIN team supervisor. His planner had the WO for planning, but when the inspectors explained that the WO involved breaker protective relaying, the supervisor said that the WO was beyond FIN team scope and retrieved the WO.
On August 4, a compliance engineer informed the inspectors that an electrical fault on S-10-PY-BUS with a single failure in the primary protective relays could have caused a LOOP. The operations manager and superintendent informed the inspectors that they, too, had just teamed that a single failure could have caused a LOOP. The inspectors asked why the plant wa* not in TS Action Statemerit 3.8.1 C.1 (two required offsite circuits inoperable). The operations manager stated that there were no offsite circuits inopersbie because the circuits were performing their functions. The TS Bases and the USAR Sections that descri' ed the nonsafety-related pathway of offsite power from the o
offsita transmission network to the Class 1E ESF busses did not provide a definitive basis regarding the design of the protective relaying system.
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i On August 5,1997, the licensee determined that there were no fuses available for
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installatiori and opened breakers S620 and S622. Th4 eliminated S-10-PY-BUS as an initiator of a LOOP. The breakers could have been opened at any time. On August 7 the engineering director initiated PIF 97-1279 to initiate a corrective action evaluation of the communication deficimcy between operations and engineering personnel.
Clarification of tha TS Bases and the applicable USAR sections is necessary for the inspectors to complete their evaluation of this issue. This issue is considered an Unresolved item (50-440/97009-06 (DRP)) and will be evaluated in conjunction with Unresolved item 50-440/97007-04(DRP) conceming an original construction wiring error for protective circuits associated with the unit auxiliary transformer.
c.
Conclusions The inspectors concludh that poor communications between engineering and ope. ations caused a small but avoidable increase in the risk of a LOOP by delaying fuse installation or the opening of breakers S620 and S622 after discovery that a fuse was missing. The inspectors also concluded that persistent NRC intervention had been required to accelerate appropriate resolution of the issue. Operations personnel responded promptly and appropriately once they understood the significance of the missing fuse. Engineering personnel responded promptly and appropriately once they realized that operations had not understood the significance of the missing fuse. Licensee management responded promptly and appropriately upon teaming of the communications deficiency.
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E2.2 Excessive Cooldowns of the Reactor Pressure Vessel a.
Inspection Scope (37551. 61726. and 92903)
The inspectors reviewed a preliminary engineering evaluation of licensee-identified reactor transients that involved reactor pressure vessel (RPV) cooldowns in excess of the TS limit.
b.
Observations and Findinas On August 6,1997, engineers performing corrective actions for a January 7,1997, RPV cooldown identified RPV excessive cooldowns that had occurred in 1992 and 1993.
Since these cooldowns had not been identified at the time, the licensee had not analyzed them, as required by TS 3.4.11, before resuming plant operations. On August 7,1997, the licensee notified the NRC via the ENS that the TS requirement had not been met in 1992 arid 1993. In each c::se the analysis had not been done because the data recorded by the applicable surveillance instruction had been for areas of the RPV that did not experience the cooldowns. The licensee entered these events in its corrective action system and planned to submit an LER. Engineering personnel concluded that the identified cooldowns were bounded by the Jant,ary 7,1997, RPV cooldown, and that there were no opeiability concems for the RPV.
c.
Conclusions The inspectors concluded that the licensee's initia! evaluation of the previously unidentified RPV cooldowns was appropriate. The inspectors will complete their evaluation of the cooldowns during their review of the LER.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management near the conclusion cf the inspection on August 7,1997, The licensee acknowledged the findings presented. However, the licensee stated that they were not convinced that there was a violation associated with the unsatisfactory SLC test and failure to enter the LCO discussed ia Section O3.1. The inspecto:s asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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l PARTIAL LIST OF PERSONS CONTACTED
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Licensee J. P. Stetz, Senior Vice President, Nuclear L W. Myers, Vice President, Nuclear R. D. Brandt, General Manager Nuclear Power Plant Department W. R. Kanda, Director, Quality and Personnel Development Department N. L Bonner, Director, Nuclear Maintenance Department J. J. Powers, Director, Nucler't Engineering Department T. S. Rausch, Director, Nu, lear Services Department J. Messina, Operations Manager
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I ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-440/97009-01 VIO Failure to submit LER for HPCS Suction ESF Actuation 50-440/97009-02 VIO SLC Pump indicated Flow Low 50-440/97009-03 IFl Weak RFPT Trip Corrective Actions 50-440/97009-04 VIO CCCW Valve Packing WO Violation 50-440/97009-05 URI EDG Fan Inoperable
'50-440/97009-06 URI Poor Response to Missing Fuse Closed 50-440/97007-03 URI React ? Feedwater Pump Turbine Tiip 50-440/95005-00 LER Inverter Failure Roscits in Reactor Scram 50-440/95006-00 LER ESF Actuation During inverter Restoration 50-440/95008-00 LER Inverter Failure Results in Reactor Scram 50-440/96002-00 LER inverter Failure Results !n Partial HPCS Actuation Discussed None INSPECTION PROCEDURES USED 37001:
10 CFR 50.59 Safety Evaluation Program 37551:
Engineering 60705:
Preparation for Refueling 61726:
Surveillance Cbservations 62707:
Maintenance Observations 71500:
Balance of Plant inspection 71707:
Flant Operations 71750:
Plant Support Activities 90712:
Inof'ica Review of Written Reports of Nonroutine Events at Power Reactor Facilities 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Fccilities 92901:
Followup - Operations 92902:
Followup - Maintenance 92903:
Followup - Engineering 92904:
Followup - Plant Support 93702:
Prompt Onsite Response to Events at Operating Power Reactors
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l-LIST OF ACRONYMS ANDINITIALISMS
' ARI Alarm Response Instruction ASME American Society of Mechanical Engineers CCCW Control Complex Chill Water
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CFR Code of Federal Regu!ations CST
' Condensate Storage Tank DCC Design Change Control DES Design Engineering Section ECCS Emergency Core Cooling System EDG Emergency Diesel Generator ENS Emergency Notification System EPA Electrical Protective Assembly ESF Engineered Safety Feature ESW Emergency Service Water FIN Flx It Now GMI General Maintenance instruction HPCS High Pressure Core Spray id
Inspection Report
LCO
Limiting Condition for Operation
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LER
Licensee Event Report
Motor Control Center
NRC
Nuclear Regulatory Commission
Pls,t Administrative Procedure
Pubic Document Room
PlF
Potentialissue Form
Perry NcrJear Power Plant
Reactor Cors isoidion Conling
Reactor Feedwater Pump Turbine
RFO6
Refueling Outage 6
Regulatory Guide
Reactor Protection Systent
RSE
P:sponsible System Enginser
SVI
Surveillance instruction
TS
Technical Specification
TXI
Temporary Instruct 6n
Updated Sasety Analysis Report
Violation
Work Order
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