IR 05000440/1999008

Insp Rept 50-440/99-08 on 990518-0708.No Violations Noted. Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML20210E086
Person / Time
Site:	Perry
Issue date:	07/22/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20210E071	List: IR 05000440/1999008 ML20210E066
References
50-440-99-08, NUDOCS 9907280119
Download: ML20210E086 (13)

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U. S. NUCLEAR REGULATORY COMMISSION l

REGION lil l

l Docket No: 50-440 License No: NPF-58

Report No: 50-440/99008(DRP)

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Licensee: FirstEnergy Nuclear Operating Company l P.O. Box 97 A200 Perry, OH 44081 l

l Facility: Perry Nuclear Power Plant l l Location: Perry, OH )

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Dates: May 18,1999 through July 8,1999 J

l Inspectors: C. Lipa, Senior Resident inspector J. Clark, Resident inspector S. DuPont, Project Engineer

Approved by: Thomas J. Kozak, Chief Reactor Projects Branch 4 Division of Reactor Projects l 1 l

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9907280119 990722 PDR ADOCK 05000440 0 PDR L

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EXECUTIVE SUMMARY i Perry Nuclek Power Plant l

NRC Inspection Report 50-440/99008(DRP)

This inspection report included resident inspectors' evaluations of aspects of licensee l operations, engineering, maintenance, and plant support activitie j Operations

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l e The inspectors concluded that the overall conduct of operations continued to be

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professional, with a continuing focus on safety. Operators demonstrated good attention to panels during hourly walkdowns and promptly identified two problems (Section 01.1).

e While the licensee aggressively pursued identifying and resolving higher than normal l

steam tunnel temperatures, this condition was distracting to plant operators (Section 01.1).

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e Inattention-to-detail by a non-licensed operator during restoration of a clearance resulted in an error. The operator unintentionally energized the motor control center for a normally de-energized motor-operated valve. This error did not result in a re-positioning of the valve and was considered to be of minor significance (Section 01.2).

Mainte aance e Maintenance and smveillance activities were properly controlled and performed per approved procedures. There was good coordination between the control room and other work groups for these activities. There was good preplanning for routine control rod exercise testing to address contingencies that could occur during the testing (Section M1.1).

• While the licensee generally scheduled surveillance tests to be performed by their due date, an inadequate review prior to changing the surveillance test schedule resulted in a high pressure core spray pump and valve surveillance test being scheduled past its due date and the allowed 25% extension specified in Technical Specifications (TS). The unit supervisor on shift identified the discrepancy on the last day before the TS interval was exceeded and the test was performed satisfactorily (Section M1.2).

Enaineerina e The inspectors concluded that engineering department personnel provided good support to plant operations by promptly dispositioning emergent equipment issues. Operability evaluations were generally well documented and engineering personnel demonstrated good understanding of plant systems (Section E1.1).

e The inspectors concluded that repeat problems with drifting setpoints on the Division 3 l diesel generator testable rupture disc were not adequately resolved to prevent

} recurrence (Section E1.2 ).

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Report Details Summary of Plant Status The plant was operated at approximately 100 percent power throughout the inspection period, l. Operations 01 Conduct of Operations 01.1 Review of Routine Plant Goeinions (71707) Inspection Scope The inspectors followed the guidance of Inspection Procedure (IP) 71707 and conducted frequent reviews of plant operations. This included observing routine control room activities, reviewing system tagouts, accompanying plant operators on rounds, attending shift tumovers and crew briefings, and performing panel walkdown Observations and Findinas The conduct of operations was professional. The inspectors observed appropriate use of procedures and consistent three-part communications. Shift tumovers and activity briefings were thorough and emphasized both personnel and plant safety. The inspectors verified that crew manning was consistent with Technical Specifications (TS).

Operators demonstrated good attention to control room panels. Most operators marked a colored line on the control room chart recorders once per hour while walking down the panels to enhance their capability to detect problems with the chart recorders. The inspectors observed that panel walkdowns by operators were consistent from crew to crew and on an hourly frequency in accordance with plant management expectation In one instance, a licensed operator rvomptly identified a large step change in main generator volt-ampere reactive load on a chart recorder. This occurred as a result of a volt-ampere reactive load runback at the Eastlake plant. The operator took prompt action to restore the generator fidd voltage and ensure there was no damage to the main generator. Followup actions were taken to review other aspects of the event per Condition Report (CR) 99-1595. In another instance, a control room licensed operator promptly identified that a non-licensed operator in the plant inadvertently restored power to a residual heat removal valve that was to remain in a de-energized condition. See Section 01.2 for details of this operator erro Emergent equipment issues were promptly addressed and the conduct of operations was appropriately focused on safety. One example was the resolution of a steam leak in the steam tunnel. This was identified on June 28 by plant operators using installed cameras during routine rounds. The leak was subsequently determined to be coming from a flange on a feedwater flow venturi. The leak was monitored and determined to be steady over the next week and the repair was scheduled for a downpower on July 1 However, on July 8, an alarm was received for high temperatures in the steam tunnel, resulting in a % isolation signal for the main steam isolation valves. Based on indications that the steam leak was degrading, plant management decided to expedite the downpower and repair of the venturi flange, which was completed on July r

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g Conclusions

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The insp :: tors concluded that the overall conduct of operations continued to be professicial, with a continuing focus on safety. Operators demonstrated good attention to panels during hourly walkdowns and promptly identified two problems. Plant management proactively expedited repair of a steam leak in the steam tunnel when the

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leak appeared to be degrading. While the licensee aggressively pursued identifying and

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resolving higher than normal steam tunne! temperatures, this condition was distracting l to plant operator .2 Operator Error Durina Restoration of a Clearance l

l Insoection Scope The inspectors followed the guidance of IP 71707 and reviewed the circumstances l Involving a non-licensed operator who made an error while clearing a system tagout.

, This included a review of the tagout document, the applicable administrative procedures, l and a walkdown of the involved motor control center (MCC). Observations and Findinas On June 30,1999, a non-licensed operator was dispatched by the control room to clear

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a tagout and restore several components to their normal positions. Clearance No. 32707 provided instructions to de-energize and tag several MCCr as part of a work boundary on the residual heat removal system. One of the components, ras shutdown cooling isolation valve MCC EF1807-H that is normally maintained in a oe .aergized condition during power operation. The clearance correctly specified that the retum condition for this MCC was "OFF." The operator inadvertently placed the switch in the

"ON" position which was promptly identified by a licensed operator in the control room who identified that the valve closed position indication light became lit. The control room crew discussed the issue and directed the operator to retum the MCC to the off positio Energizing the MCC had no affect on the valve position; therefore, the significance of this error was minor. Conditiu Report 99-1722 was written to document the issu Technical Specification 6.4.1.a specifies, in part, that written procedures shall be implemented covering the applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33. Appendix A of RG 1.33 lists equipment control, such as '

tagging, as a specified activity. Section 6.15.2 of PAP-1401," Clearance /Tagout Program," Revision 9, a procedure used for equipment control, specifies the steps for removing tags as part of restoring a clearance. Step 3 specifies that the operator verify the component is positioned as required by the clearance. Clearance No. 32702 I

specified that for item 12, MCC EF1807-H, the retum condition was "OFF " When the operator placed the MCC in the "ON" position, this constituted a failure to follow a required procedure. This failure constitutes a violation of minor significance and is not subject to formal enforcement actio Conclusions inattention-to-detail by a non-licensed operator during restoration of a clearance i resulted in an error. The operator unintentionally energized the motor control center for I

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a normally de-energized motor-operated valve. This error did not result in a re-positioning of the valve and was considered to be of minor ' significanc O Operational Status of Facilities and Equipment O2.1 General Plant Tours and System Walkdowns (71707)

The inspectors followed the guidance of IP 71707 in walking down accessible portions of several systems and areas, including:

• Control complex heating, ventilation, and air conditioning

• Radioactive waste treatment building

• Emergency closed cooling system a High pressure core spray system (HPCS)

o Reactor core isolation cooling system e Switchgear and station battery rooms Equipment operability and material condition were acceptable. Plant houselieeping was promptly restored to good condition following the refueling outage that ended on May 3,1999. Minor discrepancies were brought to the licensee's attention and were corrected. The inspectors identified no substantive concems as a result of these walkdown Miscellaneous Operations issues 08.1 (Closed) Inspection Followuo item 50-440/97009-03: Weak corrective actions associated with reactor feed pump turbine (RFPT) trip. On June 1,1997, RFPT "A" tripped on low vacuum due to a control room operator's failure to properly restore auxiliary (aux) condenser level sfter a high level alarm was received. Previous high level alarms were received, but operators restored level without affecting the RFP The inspectors were concemed that inadequate corrective actions were taken for problems associated with operators responding to Aux Condenser A High Level alarms, and that these actions were too narrowly focused on specific alarm response instruction (ARI) interpretation. Subsequently, the licensee initiated a potential issue form (PIF 97-0905) and conducted a category 2 investigation. The license concluded that several weaknesses existed. The licensee implemented actions to revise the ARl, provide operator training on proper command and control during these types of evolutions, and to review and correct similar instrument and ARI actions. The inspectors have not observed similar problems since the corrective actions for PlF 97-0905 were implemented. This item is close .2 7-016-00: Vibration-Induced Turbine Electro-Hydraulic Control System Fluid Leak Results in Reactor Protection System and Engineered Safety Feature Actuations. O'1 December 19,1997, a reactor scram signal was received due to a Turbine Control Valve Fast Closure signal in the reactor protection system. Subsequent licensee investigation found that the signal was produced due to a failure of an electro-hydraulic control (EHC) system tubing fittin The licensee initiated PlF 97-2466 to investigate this event. Engineering personnel determined that the tube fitting failure was, in part, due to vibration-induced problems after the replacement of several EHC welded flare fittings with compression fittings

, during RFO6. The engineers also determined that contributing factors to the problem l

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were EHC system pressure pulsations and inadequate tubing supports. The licensee implemented corrective actions, including replacement of the tube fittings with the original welded design, addition of tube supports, and the addition of accurnulators to dampen the system pressure pulsations during RFO7. The licensee subsequently observed reduced tubing vibrations in the area of the fittings, with no subsequent leaks or failures. Based on an onsite inspection, the inspectors concluded that the licensee took appropriate actions to investigate and correct the cause of the reactor scram. This item is close II. Maintenance M1 Conduct of Maintenance M1.1 Review of Routine Maintenance and Surveillance Activities Insoection Scooe (62707. 61726)

The inspectors observed or reviewed ali or portions of the following work activities:

e SVI-E22-1 i192, HPCS Logic System Functional Test e WO 99-1137, Reactor Protection System Logic, Division "D" e WO 97-0624, Diagnostic Testing of 1C11F002B e WO 97-3781, RHR [ residual heat removal] Valve Design Change Package implementation e SVI-C11-T1003, Control Rod Exercise for Control Rod 22-19 e PTI-E12-P0003, RHR Heat Exchanger "B" and "D" Performance Testing e TXI-310, Draining RHR Shutdown Cooling Suction Header Without introducing Air e SVI-M31-T2003A, Combustible Gas Mixing System A Operability Test Observations and Findinos Maintenance and surveillance test activities were well coordinated and were generally completed as scheduled. The more complicated activities, such as the HPCS logic functional test, were preceded by a detailed briefing for all involved individual Procedures were appropriate for the activities and the procedures were followe Surveillance test results either complied with TS requirements or were promptly addressed in the corrective action progra Operators had previously determined that control rod 22-19 had one channel of position indication that was not working at position 48. Because of this known condition, plant staff from engineering, maintenance, radiation protection, and operations worked together to develop a detailed contingency plan prior to the next scheduled control rod

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exercise in case the other channel of position indication also failed. In fact, the test was successful and there was no need to use the contingency plan, but this demonstrated good planning and teamwork on the licensee's par Conclusions Maintenance and surveillance activities were properly controlled and performed per approved procedures. There was good coordination between the control room and other work groups for these activities. There was good preplanning for routine control rod exercise testing to address contingencies that could occur during the testin M1.2 Quarterly Surveillance of HPCS Pumo Scheduled Past TS Interval Inspection Scooe (61726)

The inspectors followed the guidance of IP 61726 in reviewing a licensee-identified issue associated with a HPCS surveillance that was scheduled beyond the " late date" (the late date is calculated from the date of the last performance plus a 25% extension and is the last date that the test can be performed while still meeting the surveillance test interval required by TS). The inspectors also reviewed the scheduling of other TS required surveillance Observations and Findinos i On June 7,1999, the unit supervisor identif'ed that SVI-E22-T2001, " Quarterly HPCS Pump art Valve Opr ability." w5lch ted e lato date of June 7,1999, was scheduled for June 10,MW. Due to good ut'W9 m deini on the part of the unit supervisor, the surve#ance was peptly perferrr,ed to prevrent exceeding the surveillance test interval pbs 25% extension as reg ; ired by TS 2ndition Reports 99-1563 and 99-1587 were written to document the conditio The licensee's preliminary ' vestigation identified that the SVI was initially scheduled for June 6, which would have Aen within the allowed 25% extension, but more than one quarter of a year since the previous performance of the SVI on February 12,199 However, a change was made to the schedule late in the scheduling process to align the surveillance test with planned maintenance on the HPCS system. This change to the

, schedule was not reviewed to ensure that the TS interval plus 25% extension would not

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be exceede The inspectors reviewed the licensee's normal method for scheduling surveillance tests and determined that the tests were typically scheduled to be completed by the normal due date, without excessive use of the 25% extension allowed by T Conclusions While the licensee generally scheduled surveillance tests to be performed by their due date, an inadequate review prior to changing the surveillance test schedule resulted in a HPCS pump and valve surveillance test being scheduled past its due date and the allowed 25% extension specified in TS. The unit supervisor on shift identified the ,

discrepancy on the last day before the TS interval was exceeded and the test was performed satisfactoril !

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i 111. Enaineerina E1 Conduct of Engineering i

E Reviewof Routine Enaineerina Activities Ir:soection Scope (37551)

The inspectors evaluated the involvement of engineering personnelin the resolution of emergent material condition problems and other routine activities. The engineering personnel questioned by the inspectors demonstrated good understanding of their systems, provided thorough explanations for emergent problems which affected their !

systems, and had developed plans for resolution of the issues. In each case, system operability was properly evaluated and the operability evaluations were generally well-documented following identification of the problem. Systems were subsequently retumed to an operable condition either by repair or by calculation / engineering revie For example, actions were promptly taken to evaluate and resolve the failure of a filter test on the annulus exhaust gas treatment system (CR 99-1513), questioris on differential pressure test results for reactor core lolation cooling system and HPCS (CRs99-412 and 99-1567), a check valve failure on the combustible gas mixing compressor, a position indication failure for control rad 22-19 (CR 99-1434), and excessive drift of the Division 3 diesel generator (DG) testc' ole rupture disc setpoint (CR 99-1569). The inspectors concluded that engineering department personnel provided good support to plant operations by promptly dispositioning emergent equipment issues. Operability evaluations were generally well documented and engineering personnel demonstrated good understanding of plant system E1.2 Reoest Problems With Division 3 Diesel Generator Exhaust Testable Ruoture Disk

- Insoection Scope (37551)

The inspectors reviewed a licensee-identified test failure when the Division 3 DG testable rupture disc failed to lift within the required setpoints. The actual force required to lift the disc exceeded the value that engineering had determined was required to ensure operability of the DMsion 3 DG. The inspectors reviewed the test results, the history of past problems with the disc, and previous corrective actions that had been taken. The inspectors also reviewed the applicable sections of the Perry Updated Safety Analysis Report and walked down the rupture disc portion of the syste Observations and Findings On June 8,1999, during a test of the Division 3 DG testable rupture disc on the exhaust piping, the lift force was found to exceed the allowable limit of 466 lbs. The Division 3 ,

DG supplies emergency power to the HPCS system. The function of the rupture disc is i described in the licensee's operability evaluation (CR 99-1569) and is summarized as follows: The purpose of the rupture disc is to provide an attemate exhaust relief path in the event that the nonsafety-related, non-missile protected, exhaust silencer or piping should become partially or fully blocked. Should the nonsafety-related exhaust path become blocked, the disc must open to assure that an adequate path exists for the diesel engine exhaust flow. When the lift force exceeds the allowable limit (466 lbs), the

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DG is considered inoperable because high exhaust back pressure may prevent the DG from supplying all of the safety-related equipment load Plant engineering personnel recently modified the latch assembly of the rupture disc for all 3 Divisional DGs due to a history of excessive drift of the actual force required to lift the disc (PlFs 98-2481, 97-0538, 97-0325, 96-1048, and 96-2796). The disc latch assembly was redesigned in an attempt to prevent the excessive drift problem. The modification improved the drift problem on the Division 1 and 2 DGs, since there was !

not excessive drift between the modification date and a subsequent test date, approximately four to six months later. For the Division 3 disc, however, the setpoint drifted excessively between the modification date in December 1998 (approximately 350 lbs) and the test date on June 8,1999 (650 lbs). After cleaning and exercising the disc on June 8, the lift force appeared to be repeatable within limits (approximately 350 lbs). However, on June 9, the disc was retested and again exceeded the allowable limit (480 lbs). The interim disposition of this issue was to leave the disc in the open position pending further engineering review. This plan was documented on CR 99-1569 as part of the operability evaluation for the Division 3 D This failure to effectively resolve the setpoint drifting problem for the Division 3 rupture disc was of concem due to the high safety significance of the HPCS syste Criterion XVI of 10 CFR 50, Appendix B, requires that for significant conditions adverse to quality, measures shall be taken to ensure that the cause of the condition is determined and corrective action taken to preclude repetition. At the exit meeting on June 8,1999, the licensee indicated that a review was underway to determine if the DG was actually inoperable at the high as-found setpoint. Pending a review of the licensee's evaluation, this is considered an unresolved item (URl 50-440/99008-01(DRP)). Conclusions I The inspectors concluded that repeat problems with drifting setpoints on the Division 3 diesel generator testable rupture disc were not adequatel/ resolved to prevent recurrenc E7 Quality Assurance in Engineering ,

E7.1 Licensee Self-Assessment Activities (37551. 71707)

During the inspection period, the inspectcts reviewed multiple licensee self-assessment i activities, including: )

e Daily Manager Meeting to discuss new CRs e Quality Assurance Audit Exit on Design Control (PA 99-11)

e Company Nuclear Review Board (off-site review committee) Meeting, May 26 and 27,1999 New CRs were discussed each day to brief the management team on the issue, the category of investigation, and the owner. In most cases, there was good discussion of significance of the issue, the extent of condition, or other pertinent aspects. The

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inspectors determined that there was good management involvement in the corrective action proces The Design Control audit identified attention-to-detail issues during the course of engineering work at the Perry plant. Other areas reviewed included safety evaluations, operability evaluations, and modifications. Condition Reports were written for the Quality Assurance findirigs during the audit. The inspectors considered the audit to be thorough and self-critica l During the Company Nuclear Review Board meeting, members discussed recent NRC  !

Inspectior. Reports, a proposed TS change to a 24 month refuel cycle, cycle 7 fuel leak l cause and corrective actions, and refueling outage 7 results. The committee reviewed I activities in the engineering, operations, and maintenance areas. There was good discussion of licensee-identified problem areas and planned corrective actions. The inspectors concluded that the self-assessment activities observed were effective at identifying and resoMng problem E8 Miscellaneous Engineering issues (92903)

E Year 2000 Comoliance Review The staff conducted an abbreviated review of Y2K activities and documentation using Temporary instruction 2515/141, " Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants." The review addressed aspects of Y2K management planning, documentation, implementation planning, initial assessment, detailed assessment, remediation activities, Y2K testing and validation, notification activities, and contingency planning. The reviewers used NEl/NUSMG 97-07," Nuclear Utility Year 2000 Readiness Contingency Planning," as the basis for this revie Conclusions regarding the Y2K readiness of this facility are not included in this summary. The results of this review will be combined with reviews of Y2K programs at other plants in a summary report to be issued by July 31,199 E8.2 (Closed) Insoection Followuo item 50-440/97016-04: Suppression Pool Level Concems. On October 16,1997, the licensee noted larga oscillations in suppression pool (SP) level while running the HPCS pump. Operations personnel initiated PlF 97-2168 to evaluate this problem. The licensee determined this was actually a problem with air entrapment in SP level transmitter sensing lines, and that actual level was not fluctuating as was indicated. The licensee's investigation included observing SP level locally, with portable cameras, around the instrument sensing lines during HPCS run The problem was noted to be most prevalent when HPCS was running in the SP to SP test mode. The licensee initiated several corrective actions for this probiem. New fill and vent procedures for the transmitters were implemented, as well as a change to HPCS test procedures to limit HPCS flow when in the SP to SP mode. The inspectors observed minimal oscillations in SP level, due to HPCS testing, after the corrective actions associated with PlF 97-2168 were implemented. The inspectors concluded that the licensee took adequate steps to analyze and correct the apparent problem. This ;

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V. Manaaement Meetinas

- X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 8,1999. The licensee acknowiedged the findings presented.

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The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED Licensee H. Bergendahl, Director, Nuclear Services Department B. Boles, Manager, Plant Engineering

' N. Bonner, Director, Nuclear Maintenance Department R. Collings, Manager, Quality Assurance H. Hegrat, Manager, Regulatory Affairs T. Henderson, Supervisor, Compliance W. Kanda, General Manager, Nuclear Power Plant Department F. Keamey, Superintendent, Plant Operations J. Kloosterman, Supervisor, Corrective Actions Program B. Luthanen, Compliance Engineer J. Powers, Manger, Design Engineering T. Rausch, Operations Manager S. Sanford, Senior Compliance Engineer R. Schrauder, Director, Nuclear Engineering Department J. Sears, Manager, Radiation Protection J. Sipp, Manager, Radwaste, Environmental, and Chemistry J. Wood, Vice President, Nuclear INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support IP 9270 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities I IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering

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ITEMS OPENED, CLOSED, AND DISCUSSED l Opened  !

50-440/99008-01 URI ' . Repeat failure of DG rupture disc to open within allowable values l Closed *

50-440/97009-03 IFl Weak corrective actions associated with RFPT 50-440/97-016-00 LER Vibration induced EHC system leak results in reactor scram 50-440/97016-04' IFl Suppression pool level instrumentation concems Discussed None

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LIST OF ACRONYMS USED ARI Alarm Response Instruction CFR Code of Federal Regulations CR Condition Report DG Diesel Generators EHC Electro-Hydraulic Control HPCS High Pressure Core Spray IFl Inspection Followup item IP Inspection Procedure MCC Motor Control Center NRC Nuclear Regulatory Commission PlF Potential issue Form RCIC Reactor Core Isolation Cooling RG Regulatory Guide RFPT Reactor feed pump turbine RHR Residual Heat Removal SP Suppression Pool SVI Surveillance Instruction TS Technical Specification i URI Unresolved item Y2K Year 2000 I

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