IR 05000334/1988016

Insp Repts 50-334/88-16 & 50-412/88-11 on 880401-30.No Violations Noted.Major Areas Inspected:Licensee Actions on Previous Insp Findings,Plant Operation,Physical Security, Radiological Controls,Plant Housekeeping & Fire Protection

ML20154J869
Person / Time
Site:	Beaver Valley
Issue date:	05/16/1988
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20154J855	List: IR 05000334/1988016 ML20154J852
References
50-334-88-16, 50-412-88-11, IEB-79-02, IEB-79-04, IEB-79-07, IEB-79-14, IEB-79-2, IEB-79-4, IEB-79-7, IEIN-79-06, IEIN-79-6, NUDOCS 8805270161
Download: ML20154J869 (14)

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m U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report Nos.: 50-334/88-16 License Nos.: DPR-66 50-412/88-11 NPF-73 l- Licen;ee: Duquesne Light Company One Oxford Center 301 Grant Street ,

Pittsburgh, PA 15279

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Facility Name: Beaver Valley Power Station, Units 1 and_2 Location: Shippingport, Pennsylvania Dates: April 1 - 30, 1988 Inspectors: J. E. Beall, Senior Resident Inspector S M. Pindale, R,esident Inspector Approved by: & '& 44 &

towell E. Tripp( Chief bh8

' ~ Ua t e Reactor Projects Section No. 3A g Inspection Summary: Combined Inspection Report Nos. C0-334/88-16 and 50-412/88-11 - April 1 - 30, 198 Areas Inspected: Routine inspections by the resident inspectors of licensee actions on previous inspection findings, plant operations, physical security, radiological controls, plant housekeeping and fire protection, maintenance, surveillance testing, calibration program and review of periodic and special report Results: No violations, unresolved ite.is or significant concerns were identi-fied by NRC. A licensee identified violation involving the failure to perform containment isolation valve closure surveillance testing for :.hree normally closed valves is discussed in Detail Followup and closure of an allega-tion regarding piping stress analyses is discussad in Detail Five NRC open items were closed during this inspection (Detail 3).

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8805270161 880517 PDR ADOCK 03000334

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a TABLE OF CONTENTS Page c Persons Contacted. . . . . . . . . . . . . . . . . . . . . . . . 1 S umma ry o f Fa c i l i ty Acti v i ti e s . . . . . . . . . . . . . . . . . . 1 Followup on Outstanding Items (92701). . . . . . . . . . . . . . 1 Plant Operations . . . . . . . . . . . . . . . . . . . . . . . . -3 4.1 General (71707, 71710). . . . . . . . . . . . . . . . . . . 3 4.2 .0perations.(71707) . . . . . . . . . . . . . . . . . . . . 4 4.3 Piant Security / Physical Protection (71881) . . . . . . . . 7 4.4 -Radiological Controls (71709) , . . . . . . . . . . . . . . 8 4.5 Plant Housekeeping and Fire Protection (71707) . . . . . . 8 Maintenance (62703). . . . . . . . . . . . . . . . . . . . . . .

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8 Surveillance (61726) . . . . . . . . . . . . . . . . . . . . . . 9 Calibration Program (71707) .................. 9 Overstressed Piping Allegation . ................ 10 Review of Portodic Reports (90713) . . . . . . . . . . . . . . .

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10. Exit Interview (30703) . . . . I'. . . . . . . . . . . . . . . . 12

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DETAILS L persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activitie . Summary of Facility-Activities At the beginning of the inspection period, both Unit 1 and Unit 2 were at 100% power. 0n April 4, .1988, Unit 2 tripped from full power due to low reactor coolant system flow following the de-energization of the "A" reactor coolant pump (see Section 4.2.1). Unit 2 was returned to power on April 5,198 Both Unit 1 and Unit 2 were at 100% power at the close of the inspection perio . Followup on Outstanding Items The NRC Outstanding Items (01) List was reviewed with cognizant licensee personnel. Items selected by the inspector were subsequently reviewed through . discussions with licensee personnel, documentation reviews and field inspection to determine whether licensee actions specified in the OIs had been satisfactorily completed. The overall status of previously identified inspection findings was reviewed, and planned / completed lic-ensee actions were discussed for the items reported below:

3.1 (Closed) IFI (50-334/84-25-02): Determine whether Technical Speci-fications need to be updated for the containment emergency air lock

, (EAL). The licensee previously determined that containment and outdoor temperature parameters were limiting conditions for nil ductility limits of the metal used in construction of the EAL. To address operability concerns for the EAL, the licensee administra-tively maintained the EAL out of service during cold weathe The

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licensee recently decided to insulate the outer EAL door which would eliminate both the nil ductility concerns and the need for revised Technical Specification requirements, provided that the insulation is administratively verified to be intact prior to or during cold weather. The insulation would be removed when the EAL is physically taken out of service (during outages), a process which necessitates *

the implementation of administrative controls to ensure that the insulation is properly replaced. The licensee expects to implement the EAL insulation effort during the Fall 1988 prior to extreme cold weather. The inspector will review the licensee's actions during a future inspectio This item is close .2 (Closed) IFI (50-334/85-24-02): Review licensee actions to improve feedwater regulating valve (FRV) reliabilit The licensee has experienced FRV control problems since initial plant startu Several modifications have previously been implemented, but they

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.have not been effective in eliminating the control problems. During the licensee's sixth refueling outage (December 1987 March 1988),

Design Change Package (OCP) No. 829, BVPS-1 Feedwater System Upgrade, was completed to implement the feedwater system task force recom-mendations to resolve the FRV control problems. The major change .

from the DCP was to reduce the diameter of the main feedwater pump  :

impeller to lower the pressure drop across the FRVs. Additionally, the FRV cage and plug (trim) assemblies were re-sized to match the new pump and system characteristics. After approximately two months of operation following ' implementation of the design change, no con- '

trol problems have been experienced with the FRV It should be i noted, however, that the majority of the FRV control problems have been experienced toward the end of the operating cycle. The in-spector will review the effectiveness of the licensee's modification through the routine inspection program a cing subsequat plant operation This item is close .3 (Closed) Violation (50-334/87-07-01): Failure to shut the "1C" gaseous waste system sample return valve, resulting in an unplanned gaseous waste releas The licensee responded to the violation by

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letter dated October 9, 198 The inspector verified that the ,

licensee's commitments have been implemented, including the issuance of special instructions to shif t personnel to require that senior control staff nyiew and verify specific checks and alignments prior to both gaseous and liquid discharges. This item is close ,

3.4 (Closed) Unresolved Item (50-334/87-07-05): Determine safety sig-nificance of non-conservative overpressure protection system (0PPS)

setpoints and investigate discrepancies between NRC safety evaluation report (SER) assumptions and Technical Specification requirements for ESF/ Reactor Protection System components. The licensee performed an evaluation to address the reactor coolant system overpressurization concerns of the May 27, 1987 event, when the licensee identified that the OPPS trip setpoints were actually at 364 psig, 14 psig higher than the Technical Specification required value of 350 psi The evaluation adequately demonstrated that there was no safety impact

due' to the even The OPPS setpoint specification appears to be unique in that a "nominal" setpoint value is specified in Technical Specification The NRC SER used 350 psig as the maximum value, including instrument error, while the licensee used a nominal value of 350 psig plus instrument error. Other ESF and Reactor Protection System trip / actuation setpoints are not susceptible to similar incon-sistencies as both the Trip Setpoints and associated Allowable Values i are specified in the Technical Specification No additional con-cerns were identified. This item is close l I

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3.5 (Closed) Unresolved Item (50-412/87-68-01): Address the potential design deficiency in the BV-1 Fast Transfer System for switching from on-site to off-site power and.vice versa. On November 17, 1987, BV-2 experienced a loss of off-site power following a turbine trip due to an inadvertent turbine thrust bearing signal. It was subsequently determined that three design deficiencies contributed to the sequence of breaker operations that resulted in the loss of off-site power event. The inspectors questioned whether similar design deficiencies may exist in BV- The licensee's followup study of the system design indicated that some of the BV-1 design features were similar to BV-2. A design change (DCP No. 867) was initiated in December 1987 to correct these apparent design deficiencies. The scope of the design change included: (a) the replacement of four turbine trip MG-6 relays (62ASTX 1&2,162ASTX 1&2) with high speed latching relays to maintain a turbine trip signal once it is executed; (b) the in-stallation of knife switches in the closing coil circuits for circuit breakers 41A, 410, 141A, 141C, 241B 2410, 3418 and 3410 located in the fast bus transfer breaker cabinet Installation of this design change was completed during the 1987 refueling outage and the modi-fied system was tested successfully on January 8, 1988, i

The inspector reviewed pertinent documents in DCP No. 867, including: Specification No. 8700-DES-0239 "Specification for installation of fast bus transfer breaker switches and turbine latching relays" (Revision 1), dated December 30, 198 Temporary Operating Procedure No. 1-88-02 "Fast bus transfer testing for DCP 867" (Revision 1), dated January 15, 198 The inspector also physically observed the installed conditions of the latching relays and the knife switches in the switchgear area and did not identify any deficiencie The licensee's corrective action is considered adequate and this item is close . Plant Operations

' General Inspection tours of the following accessible plant areas were con-ducted during both day and night shif ts with respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire protection, radiation control, physical security / plant protection and operational / maintenance administrative control .- _-- _ _ _ - _ - _ _ _ - _ _ _ _ _ - _ _ __ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

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-- Control Room -- Safeguard Areas

-- Auxiliary Building -- Service Building

-- Switchgear Area -- Diesel Generator Buildings

-- Access Control Points -- Containment Penetration Areas

-- Protected Area Fence Line -- Yard Area

-- Turbine Building -- Intake Structure 4. Component Labeling During a routine plant tour, the inspector noted that the label for a control transfer switch was missing from the emergency shutdown panel (SDP). The SDP is to be used if the control room becomes inaccessible (e.g., due to a control room fire). The label that was missing appeared to be for the control transfer to the SDP for the "2B" Control Rod Drive Mechanism Shroud Fan (IVS-F-28). The inspector also noted that about five other labels had be-come unglued from the SDP benchboard although they were still physically in plac The inspector brought this concern to the licensee's attention who committed to re-solve the discrepancies. Inspector followup on this issue will be included with the followup inspection associated with NRC Unresolved Item No. 50-334/88-11-01, Inadequate Plant Labelin . ESF System Walkdown The operability of selected Engineered Safety Features L (ESF) systems were verified by performing walkdowns of the accessible portions of the system The inspectors con-firmed that system cortponents were in the required align-ments, instrumentation was valved in with appropriate calibration dates, as-built prints reflected the as-

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installed systems and the overall conditions observed were i sati sfactor The systems inspected during this period include the Recirculation Spray, Emergency Diesel Generator j and Quench Spray system No concerns were identified.

l 4.2 Operations During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration and plant conditions. During plant tours, logs and records were reviewed to determine if entries were properly made, and that equipment status / deficiencies were identified and communi-cate These records included operating logs, turnover sheets, tagout and jumper logs, process computer printouts, unit off-normal and draf t incident report The inspector verified adherence to approved procedures for ongoing activities observed. Shift turnovers were witnessed and staffing requirements confirme In general,

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inspector comments or questions resulting from these reviews were resolved by licensee personnel. In addition, inspections were con-ducted during backshifts and weekends on the following dates and times: 4/5, 4:15 am - 7:00 am; 4/9, 8:30 am - 10:30 am; 4/16,10:00 am - 4:00 pm; 4/17, 9:00 am - 3:00 pm; 4/24, 10:00 am - 5:45 pm; 4/30, 2:00 pm - 9:00 pm. The inspectors verified that plant opera-tors were alert and displayed no signs of fatigue or inattention to dut . Reactor Trip Due to Low RCS Flow On April 4, 1988, Unit 2 tripped from 100% power due to low reactor coolant system (RCS) flow. The low flow condition occurred during the performance of Operations Surveillance Test (OST) No. 2.36.18 (4kV and 480 Volt Normal Bus Undervoltage Test), when the operability of the "2A" non-emergency 4KV bus undervoltage protection system was being verifie During the test, the undervoltage relays actuated, causing several motor loads to automatically isolate from the bus, including the "A" reactor coolant pump (RCp). Upon the loss of the RCP, an immediate reactor trip occurred as a result of the reduced RCS flo Emer-gency operating procedures were used by plant operators to stabilize the plant in Mode 3 (Hot Standby) following the reactor trip. The licensee made the required notifications per 10 CFR 50.72 reporting requiremert Following the ' reactor trip, the licensee initiated troubleshooting activities of related plant equipment, and identified that the cause of the r. vent was due to the failure of the undervoltage blocking relay. Upon placing the undervoltage test circuit in the "Test" position, the blocking relay is designed to pick up, thus preventing the simulated undervoltage signal from actuating the associated equipmen The relay failure was apparently caused by insufficient latching of one set of relay contact The licensee adjusted the blocking relay contacts and ir.spected additional similar relays for additional problem No aeficiencies were identified during the inspectio Additional licensee action included initiating a review to determine the reason for perform ng OST 2.36.18 on a monthly frequency. No Technical Specification requirements or NRC commitments to perform the OST were found and the OST is classified as a balance of plant surveillance ac-tivity. Therefore, the licensee elected to discontinue the performance of the OST on a monthly frequency and currently plans to perform it only when the plant is shutdow This action was taken to reduce the potential for unnecessary safety system challenges. The Technical Specification

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-6 undervoltage protection system utilizes a different type of relay and they are tested monthly per Technical .Specif t- !

cation surveillance requirements. No additional concerns were identifie . . Containment Isolation Valve Inoperability On April 5,1988, during a procedure review / revision, the licensee identified that Unit 1 containment isolation phase A (CIA) valves TV-1FP-105, TV-1FP-106, and TV-1FP-107, were not included in the 18 month Operations Surveillance Test (OST) No.1.1.4, Containment Isolation Trip Test, CIA Train B (Revision 62). Plant drawings were reviewed and the licensee confirmed that the three valves do receive a CIA Train B isolation signa Upon notification, plant operations personnel immediately declared the three valves inoperable due to the failure to meet the surveillance requirement of Technical Specification 3.6. The as-sociated Action Statement for Technical Specification 3.6.3.1 requires that inoperable containment isolation valves be restored to operable status within four hours or isolate the affected penetratio In accordance with Action Statement requirements, the licensee de-energized and closed the valves within four hours of identification of the problem. The valves are containment fire protection header isolation valves, and receive an automatic c1cse signal when a CIA occurs. The valves are normally main-tained closed during plant operatio Immediate licensee corrective action included initiating operating manual deficiency reports for the af fected pro-cedures to include the three CIA valves. Additionally, a review was initiated to confirm that all other CIA valves are listed in surveillance test procedures and have been

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fully teste No other deficiencies were identifie the licensee is developing a temporary

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Additionally, operating procedure that will verify that these valves will stroke closed upon receiving a Train B CIA signal.

i Licensee review into past performances of OST 1.1.4 in-

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dicate that the affected valves were never included in the l procedur It was determined that the CIA valves were

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installed as a part of a larger plant modification in 198 At that time, the station procedure update / revision process l following plant modification was as follows. After im-plementation of the design change and issuance of the Technical Specification Amendment (if applicsble), the various station groups wcJ1d receive a letter describing

the change made to the ; slant. The station groups were then j responsible to revita the appropriate procedure The I

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't licensee determined that the procedure change required by the plant modification in 1982 was omitted by the licensee at that time, therefore, the procedures were not revised to include the three CIA valves. The current procedure up-grade process includes the various station groups from the beginning of the project (Design Concent phase). The station groups are continually updued on modification development, personnel involvement begins at an earlier

. time, and the groups responsible for procedure changes have specific guidance and checklists to aid in determining whether station procedures need to be revise To provide assurance that additional problems had not previously occurred under the old plant modification pro-cedure system, the licensee instituted a review of randomly selected design change packages from between 1980 and 198 Of the approximately 127 DCPs performed, about one-third of them were reviewed. No similar problems were identifie Since the licensee identified this failure to meet Tech-nical Specification surveillance requirements and this situation meets the criteria to be considered a licensee identified violation, in accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR 2, Appendix C, no Notice of Violation will be issue .3 Plant Security / Phys' cal Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:

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Protected Area and Vital Area barriers were well maintained and not compromised;

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Isolation zones were clear;

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Personnel and vehicles entering and packages being delivered to the Protected Area were properly searched and access control was in accordance with approved licensee procedures;

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Persons granted access to te h site were badged to indicate whether they have unescorted access or escorted authorization;

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Security access controls to Vital Areas were being maintained and that persons in Vital Areas were properly authorize _

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Security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and

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Adequate illumination was maintaine No deficiencies were identifie .4 Radiological Controls Posting and control of radiation and high radiation areas were in-specte Radiation Work Permit compliance and use of personnel monitoring devices were checke Conditions of step-off pads, dis-posal of protective clothing, radiation control job coverage, area monitor operability and calibration (portable and permanent) and personnel _ frisking were observed on a sampling basi No concerns were identifie .5 Plant Housekeeping and Fire Protection Plant housekeeping conditions including general cleanliness condi-tions and control and storage of flammable material and other '

potential safety hazards were observed in various areas during plant tour Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also ob-served. The inspector conducted detailed walkdowns of the accessible areas of both Unit I and Unit . Unit 1 Areas During the previous inspection, the inspector expressed the concern that housekeeping at Unit 1 exhibited weaknes During the current inspection period, the inspector noted substantial improvements in housekeeping in both radio-logically controlled areas and other plant area Areas noted to be dirty were cleaned, and litter was remove Individual deficiencies were identified to the licensee for continued cleanu . Unit 2 Areas During the current inspection period, the inspector noted ,

that Unit 2 maintained a very good level of housekeepin '

Isolated deficiencies were identified to the licensee for resolutio T

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f Maintenance The _ inspector reviewed selected ma'ntenance activities to assure that:

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the activity did not ' violate Technical Specification Limiting Con-

. ditions ' for Operation and that redundant components were operable; i

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required approvals and releases had been obtained prior to commencing work;

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procedures used for the task were adequate and work was within the skills of the trade;

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activities were accomplished by qualified personnel;

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where necessar radiological and fire preventive controls were i adequate and implemented,  ;

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QC hold points were established, where required, and observed; *

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equipment was properly tested and returned to servic Maintenance activities reviewed included: ,

MWRs 880604, 880605, 880606: Rezero I/P Output Orifc for Atmospheric Steam Damp Valve ,

No deficiencies were identifiecC'

, Surveillance Testing The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, >

test instrumentation was properly calibrated and used, Technical Specifi-cations were satisfied, testing was performed by qualified personnel and test results satisfied acceptance criteria or were properly dispositione The following surveillance testing activities were reviewei:

BVT 1.3 - 8. Incore Moveable Detector Flux Mapping ,

OST 1. RCS Water Inventory Balance .

OST 1. Accident Monitoring Instrumentation Channel Checks OST 1.1 Safety Injection Pump Test

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OST 2. Centrifugal Charging Pump Test OST 2.1 Boron Injection Flow Path Valve Position Verification

OST 2.1 Containment Depressurization System Position Verification - Train A

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No deficiencies were identifie . Calibration Program

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The licensee's calibration program uses red foil-type stickers to identify those components required by TS to be calibrated within a specific perio Certain components which are used to measure the performance of other TS required equipment are also given red foil-type sticker In previous

. inspections, the inspector noted that certain of these stickers had been r

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identified to the licensee as being beyond the required calibration due dat The inspector also identified instances where identical components had been assigned different kinds of calibration sticker In all but one case, the deficiencies were administrative in nature such ,

as wrong sticker (should not have been red), or wrong-calibration due date

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(wrong year). The one instrument found to be beyond its calibration due date was still within the "grace" period allowed by the Technical Speci-fications. The instrument was promptly recalibrated and the inspector confirmed that the device was in the licensee's tracking system. This item was the only deficiency among several hundred items reviewed and is considered an isolated cas No violations were identifie . Overstressed Piping Allegation (RI-88-A-0017)

In 1979, the NRC issued several IE Bulletins concerning generic problems

) in the seismic stress analyses of safety related pipin Certain non-conservative factors were discovered concerning information input for seismic analyses and these were addressed in IE Bulletin 79-02 (pipe supports) and 79-04 (valve weights). During the evaluation of certain i piping designs, significant discrepancies were identified at certain facilities between original piping analyses and the then (1979) acceptable computer analysis code. These discrepancies (see IE Information Notice t

79-06) led to the NRC issuance of IE Bulletin 79-07 which required all ,

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power reactor facilities to verify that the analysis codes used were

, properly benchmarked for accuracy. Four sites (including Beaver Valley I

Unit 1) were issued show cause orders and Beaver Valley Unit 1 underwent a i five-month outage to address this seismic stress issue.

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The confirmation of seismic analysis input information to actual, as-built (and possibly modified) system configuration was the subject of IE Bul-letin 79-14 which was issued to all power reactor facilities. This Bul-letin was a major contributor to another long (nearly 12 months) shutdown for Beaver Valley Unit 1. During the extended outage, the licensee em-ployed two contractors, Nuclear Services Corporation (NSC) and Schneider Consulting Engineers (SCE), to supplement the extensive analysis effort of Stone & Webster Engineering Corporation, the architect-enginee During the reanalysis effort, many examples of piping which could become overstressed under certain conditions were identified by the engineers conducting the reanalysi These deficiencies were forwarded to the licensee by the company making each identification. The licensee reviewed each deficiency and made a determination of reportability to the NRC as part of the corrective action. The inspector reviewed several examples of correspondence which- transmitted potentially reportable deficiencies from the identifying contractor to the license The licensee made many Licensee Event Reports (LERs) during the reanalyses effort, each of which reported the identification of a potentially overstressed condition in-volving safety related systems. In 1980 alone, approximately 25 LERs of this nature were submitted. Other similar LERs were submitted in 1979 and 1981. The inspector reviewed a sample of these LERs and no deficiencies were identified. The volume of such LERs provides good evidence that all deficiencies that met the licensee's criteria for reportability were reporte On March 23, 1988, the NRC requested the licensee to review one particular deficiency referred to in an unsigned, SCE internal memo dated December 24, 1980. The licensee's response, dated April 13, 1988, and the supporting documents were reviewed by the inspector. The inspector, fol-lowing the independent review, concluded that the deficiency involved was not reportable to the NRC because the piping involved was not safety re-

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lated nor would its failure have impacted safety related components. The

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inspector noted that the deficiency had been corrected as part of a plant l modification at that time.

I The inspector also reviewea the process which had been in place during the reanalysis effort to identify deficiencies, forward them to the licensee, review them for reportability, and correct them in the fiel Extensive documentation exists on these activities including system drawings, piping isometrics, meeting minutes, inter-company correspondence, design change files and NRC reports. The inspector reviewed a sample of each class of documentation including all available information on the deficiency in-volved in the allegatio No deficiencies were identified; this allegation is closed, l

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12 Review of Periodic Reports Upon receipt, periodic reports submitted _ pursuant ~ to Technical Specif t-cation 6.9 (Reporting Requirements) are reviewed. The review assessed whether the reported information was valid, included the NRC required data and whether results and supporting information were consistent with design predictions and performance specifications. The inspector also ascer-tained whether any reported information should be classified as an ab-normal occurrenc The following reports were reviewed:

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BV-1/BV-2 Monthly Operating Report for Plant Operations from March 1-31, 198 BV-1/BV-2 1987 Annual Radiological Environment Report No deficiencies were identifie . Exit Interview Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspection findings was further discussed with the licensee at the conclusion of the report period on May 12, 198 %

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