IR 05000334/1989018

Insp Repts 50-334/89-18 & 50-412/89-18 on 890901-1013. Violations Noted.Major Areas Inspected:Licensee Actions on Previous Insp Findings,Plant Operations,Security, Radiological Controls,Plant Housekeeping & Fire Protection

ML19332C749
Person / Time
Site:	Beaver Valley
Issue date:	11/14/1989
From:	Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML19332C740	List: IR 05000334/1989018 ML19332C739 ML19332C746
References
50-334-89-18, 50-412-89-18, NUDOCS 8911280503
Download: ML19332C749 (16)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION I

' Report Nos.

50-334/89-18 50-412/89-18 e

License Nos.: DPR-66 NPF-73

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Licensee:

Duquesne Light Company r

One Oxford Center 301 Grant Street i

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Pittsburgh, PA 15279 Facility:

Beaver Valley Power Station, Units 1 and 2 Location:

Shippingport, Pennsylvania

Dates:

September 1 October 13, 1989 Inspectors:

J. E. Beall, Senior Resident Inspector P. R. Wilson, Resident Inspector

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Approved by:

/Y Z 00l/ /Y,risp?

Curtis J.'Cowg 11 Chief, Date'

s Reactor Projects ection No..4B c

Division of Reactor. Projects

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(Inspection Summary:. Combined Inspection ~ Report Nos. 50-334/89-18 and 50-412/89-18 for September 1 - October 13, 1989 Areas Inspected:

Routine inspections by the resident inspectors of licensee actions on previous inspection findings, plant operations, security, radio-logical controls, plant housekeeping and fire protection, surveillance testing, maintenance, control of overtime,. thimble tube **ning, auxiliary feed system check valve leakt.ge, Unit 1 Safeguards Build'r

',ilation and licensee event s

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reports.

I r Results: Overall, the facility was operated safely.

Licensee activities associated with additional Unit 1 inoperable fire dampers were reviewed; no-deficiencies were identified (Section 4.6).

One violation was identified regarding the failure to maintain required communications during a surveillance

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-test'(Section 5). Another_ violation was identified regarding excessive over-

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time',:in addition a weakness was noted in senior management oversight of con-trol of personnel overtime (Section 7).

Licensee activities associated with Unit.1 thimble tube thinning were reviewed; no deficiencies were identified i

(Section 8).

Licensee activities associated with the Unit 2 leaking auxiliary l-

.feedwater containment isolation check valves were identified (Section 9).

Three previous open NRC items were reviewed, one item was closed during this l

inspection.

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9911260303 991113 l.~

{DR ADOCK 05000334 PDC

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TABLE OF CONTENTS Page

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1.

Persons Contacted........................

1-

' 2.

Summary of Facility Activities..........'......

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Status of Previous Inspection Findings (71707, 92702,*

L and 91701)..............

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. 4 '.~ ~0perational Safety (IP 71707,.71710, and 40500)........

4.1 General..

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r 4.2 ESF Walkdown.....

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4.3 Operations........................

2-4.3.1 Unit 1 Feedwater Isolation During. Shutdown'

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4.3.2 -Unit 1 Reactor Trip.

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4.3.3 Unit 1 ESF Actuation - Ventilation Realignment.

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4.4: Plant Security / Physical Protection............

4;5 -Radiological Controls..................

4,6 Plant Housekeeping and Fire Protection..........

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Surveillance (61726).....................

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Maintenance (62703)......................

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Excessive Overtime, Unit 2 Refueling Outage (71707)......

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Unit 1 Thimble Tube Excessive Wear (37700, and 93702).....

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Leaking Check Valves in Unit 2 Auxiliary Feedwater

' System (37700, and 93702)..................

10. Unit 1. Safeguards Building Ventilation (37700)........

11..Inoffice Review of Licensee Event Reports (90712, and 40500).

12. Unresolved Items.......................

13. Meetings (30703).......................

• Indicates NRC inspection procedure number, i

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m DETAILS 1.

Persons Contacted

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During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspec-tion activities.

. 2.

Summary of Facility Activities At the beginning of the inspection period, Unit I was at 80% power.

Unit I was shutdown on September 1 for the seventh refueling outage. Mode 5 was reached on September 4, and Mode 6 on September 13. The Unit I reactor was completely defueled on September 22, and remained defueled the remainder of the inspection period. Unit 2 operated at 100% power throughout the inspection period.

3.

Status of Previous Inspection Findings The NRC Outstanding Items 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 licersee actions were discussed for the. items reported below.

3.1 (0 pen) Unresolved Item (50-334/89-04-02):

Unit 1 Safeguards F3uilding Ventilation. This item involves questions raised by the inspector concerning the adequacy of the safety related ventilation system to remove the heat from the Unit 1 Safeguards Building during certain postulated accident scenarios.

This item is reviewed in Section 10.

3.2 (0 pen) Unresolved Item (50-334/87/11/01):

Inadequate program for the storage of transient equipment in safety related areas. This item concerned the identification of several instances where temporary equipment, located near safety related equipment, was found to be unrestrained and thus creating a concern during potential seismic events. The licensee upgraded Section 13 of the Maintenance Manual providing guidance on the proper temporary storage of transient equipment.

In addition, Site Administrative Procedure Chapter 58,

" Plant Inspection Program", was revised to include requirements to identify and resolve deficiencies involving unrestrained materials in safety related areas. The inspectors noted significant improve-ments during plant tours, however, unrestrained temporary equipment in safety related areas was still observed.

It was not clear whether all site personnel were aware of the requirements to properly restrain temporary equipment, l

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3.3 -(Closed) Damaged Emergency Diesel Generator Silencer Supports (50-412/88-19-01): This item involved damage to the Emergency Diesel Generator (EDG) silencer supports identified by the

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inspector which hed been caused by lateral thermal. growth. The support had been inadvertently insulated during construction allowing the support temperature to approach that of the i

silencer itself.

The support design allowed for growth in the length direction but not the lateral direction.. The insulation was removed, the damage was repaired (during the Unit 2 first

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L refueling outage) and no subsequent damage'has been observed.

The inspector had no further questions.

4.

Operational Safety

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4.1 General Inspection tours of the following accessible plant areas were conducted during both day and night shifts with respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire

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protection, radiation control, physical security / plant protection and operational / maintenance administrative controls.

-- 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

-- Reactor Containment

-- Spent Fuel

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Building-4.2 ESF Walkdown The operability of selected engineered safety features systems were-verified by performing detailed walkdowns of the accessible portions of the systems. The inspectors confirmed that system components were in the required alignments, instrumentation was valved-in with appropriate calibration dates, as-built prints reflected the as-installed systems.and the overall conditions observed were satis-factory. The systems inspected during this period included the Emergency Diesel Generator, Safety Injection, Auxiliary Feedwater and Recirculation Spray systems.

4.3 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

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and records were reviewed to determine if entries were properly made, and that equipment status / deficiencies were identified and communi-cated. These records included operating logs, turnover sheets, tagout and jumper ' logs, process computer printouts, unit off-normal

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and draft incident reports. The~ inspector verified adherence ~to approved procedures for ongoing activities. observed.

Shift turnovers were witnessed and staffing requirements confirmed.

Inspector comments or questions resulting from these' reviews were resolved by licensee personnel. Onsite Safety Review Committee meetings were

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attended to evaluate the licensee's self-assessment capability.

In addition, inspections were conducted during backshifts and weekends on 9/5, 9/6, 9/7, 9/21, 9/23, 9/24, 10/3, 10/5, and 10/7.

4.3.1 Unit 1 Feedwater Isolation During Shutdown On September 1, 1989, while conducting a plant shutdown in preparation for the Unit I seventh refueling outage, an in-advertent feedwater isolation occurred due to high water level in the 1A Steam Generator (SG). The reactor was subtritical-(Hot Standby, Mode 3) with rod insertion in progress and the

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main feedwater regulating valves were shut with feedwater controlled on the feedwater bypass valves. The 1A Main Feed-water Regulating Valve suddenly went opened.

Control room operators immediately responded to the rapidly increasing 1A

~SG level by tripping the operating main feed pump, however, the 1A SG high level setpoint was reached and the feedwater system isolated as designed. The operators subsequently re-stored proper steam generator level and reset the feedwater isolation. The cause of the feedsater regulating valve popping ooen had not been determined at the end of the

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inspection period.

4.3.2 Unit 1 Reactor Trip

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On September 1,1989, approximately four minutes after the event described in Section 4.3.1 above, a Unit I reactor trip with inward control rod motion occurred due to high Source Range Nuclear Instrument (SRNI) flux.

Control room operators had not installed the SRNI power fuses on one of the two SRNIs during the shutdown because the SRNI detector Sas out of service due to an expired calibration. As neutron flux decreased during the shutdown, the Intermediate Range Nuclear Instrument permissive P-6 cleared and subsequently unblocked the high neutron flux trip signal from the SRNI with its fuses removed. The solid state protective system trip logic was thus satisfied (one out of two) and a reactor trip resulted.

The control room operators responded to the trip as required.

As a conservative measure, SRNI power fuses are removed during normal power power operation by procedure to prevent inadvertent energization and possible detector damage. The J

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unit shutdown procedure requires that the fuses be replaced before the detectors are required to be energized. Abnormal Operating Procedure (A0P) 1.2.1 " Nuclear Instrument Malfunc-tion", required that for a single SRNI channel malfunction

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that its associated block switch be placed in " bypass".

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this case, AOP 1.2.1 was not followed because the operators believed the AOP'was not applicable since the detector was

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fully functional and was only administrative 1y inoperable.

During the reactor shutdown, the' operators did not replace

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the fuses-in the inoperable SRNI because it was felt it would disrupt a surveillance procedure the operators mistakenly-believed was in progress.

i The inoperable SRNI was subsequently recalibrated and returned to service..The licensee intends to cover the event in i

operator retraining.

4.3.3 Unit 1 ESF Actuation - Ventilation Realignment On September 2, 1989, with Unit 1 in Hot Shutdown (Mode 4), an

"A" train Auxiliary Ouilding ventilation isolation and re-alignment of the Supplemental Leak Collection and Release (SLCR) system dampers to the main filter bank occurred. A surveillance test was in progress to determine the leakage past the Residual Heat Removal (RHR) system inlet motor operated isolation valves. The test boundary was initially pressurized via the Chemical and Volume Control System (CVCS),

then allowed to drain to the Reactor Plant Sample Panel after the test boundary was isolated from the CVCS-system.

Leakage past the RHR motor operated inlet valves was then to be measured, however, excessive leakage past the CVCS boundary valve resulted in e large volume of reactor coolant flowing into the Reactor Plant Sample panel. This in turn caused the

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"A" Auxiliary Building Ventilation Radiation Monitor to alarm and generate the ventilation realignment signal.

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The surveillance was immediately suspended and radiation technicians sampled the area environs and determined there were no radiological consequences of this event to the public or site personnel. The licensee intends to repair the leaking CVCS boundary valve during the current Unit I refueling outage and is planning to change the surveillance procedure to require that the SLCR main filter banks be placed in service prior to the performance of the test.

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14 f Planti security / Physical-Protectiont

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W4 is-c TImplementationiof the Physical Security. Plan was observed in various,

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i'l, iplant.TareasLwith, regard to-the_followingF

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Protected Area ~and: Vital Area barriers were !well ' maintained -

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LIsolction. zones were clear;

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is Personnel and vehicles entering and packages being delivered toi

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the' Protected Area were-properly searched and access control;

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was iniaccordance with-approved licensee procedures;>

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Persons granted access totthe site-were badgedito indicate'

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whether they have unescorted access or-escorted authorization;.

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' Security access controls to Vital 1 Areas were being maintained

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My Land that persons in-' Vital _ Areas were properly authorized, m,,

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Security posts were adequately staffed and equipped, security'

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personnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and

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-, : Adequate illumination was maintained, y

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iNo-deficiencies were~ identified, s-4.5 (R_adiol'ogical Controls Posting and control of radiation =and high radiation areas were-inspected., Radiation Work 1 Permit compliance and use'of personnel

monitoring! devices were checked. ' Conditions. of step-of f pads, edisposal of prote:.tive clothing, radiation'controldob coverage, area imonitor operability and calibration (portable and permanent) and

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personnel frisking were observed on 'a sampling basis, j

During a= tour'of the Unit'2 Safeguards Building,_a Radiologically

. l Controlled Area (RCA)~,.the inspecter identified some: discarded candy

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wrappers indicati.ng a potential ingestion of food.in the RCA, a violation of licensee work rules.' A similar concern had been identified in a previous inspection (IR 50-334/89-03; 50-412/89-03).

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Further licensee attention is required to prevent further recurrence.

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4.6 Plant Housekeeping and Fire Protection

Plant housekeeping conditions, including general cleanliness i

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L potential safety hazards, were observed in various areas during plant

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tours. Maintenance of fire barriers, fire barrier penetrations, and

verification of posted fire watches in these areas were also observed.

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Thelinspector co' ducted detailed walkdowns of the accessible areas.of'

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.No significant deficiencies were identified.-

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OnLSeptember}, 2989,iUnderwriters Laboratories (UL),. notified thei

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,l licensee?that1the six-horizontal:prototypeLfire dampersTdiscussed in W-Inspection! Report 50-334/89.13;150-412/89-14',0 failed the fire

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endurance and the hose. stream tests'(the test required by::UL;Stahdard:

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Based on_ this",Lthe licensee declared 16: horizontalf fire

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1 dampers 11noperable. -The areas affected by:theli_noperable dampers <

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includeithe CableLTray? Mezzanine,cthe DF: Emergency Switch Gear Room,c

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W f areas; could impact:theTredundant emergency; diesel generator controli l'

land power distribution system.

These horizontal-dampersLwerellocated,

m in the;same areas as the 26 vertical fire dampers that had been;

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..previo'usly declared inoperable.on' August 15, 1989, and=thus were

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The licensee: currently' plans to renlace.all the dampers:(b_oth?

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vertical andihorizontal) in-affected areas with~ combustible loading,

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exceeding'one hour. - The licensee is evaluating. other alternatives.

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for af fected areas with-less than one ho'ur. combustible -loading.

TheLinspector periodically' verified that fire watches were performing required duties.

The inspector will continue to monitor-

-licensee performance in the area of fire protection.

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35; Surveillance Testing

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-Thelinspectors witnessed / reviewed selected surveillance tests to-determine-

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lwhether properlyiapproved procedures were in use, details =were adequate.

1 test instrumentation was. properly calibrated and:used, Technical, Specifi-:

cations were. satisfied,. testing'was performed by qualified personnel and W

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testJresultsisatisfied acceptance criteria or were4 properly:dispositioned.

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)Th6?followingisurveillance testing activities were reviewed:

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--EOST'2.24.-2 MotorJDriven Auxiliary Feed Pump. Test

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'-- :0ST 1.39 ID. Veekly: Station Battery Check, Battery. No. 4

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'- LOST 2.24.4 Steam Turbine ~ Driven Auxiliary Feed Pump Test During the performance of OST 1.39.ID,.the following discrepancies were

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'The OST required that the charging current of the battery be deter-

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mined by connecting.a digital voltmeter across the terminals of an installed amp meter.and measuring the DC millivoltage.

Then the j

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current'was to be calculated by applying the millivolt reading to an

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--equation given in the procedure.

The operator performing the OST

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used the milliamp function on the digital voltmeter vice the DC volt

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function to obtain the required.r?ading. After being prompted by the

. inspector, the operator used the proper digital volt meter function and obtained the correct measurement.

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The OST required that if the battery was not on an equalizing charge or had not been on an equalizing charge within the past 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, that the specific gravity of the battery acid be. determined using a

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hydrometer. At the end of the OST, the operator realized that the battery had not been on an equalizing charge for the past 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and'had to go back and perform the test steps to obtain the specific gravity.

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The first step in the test required the operator to obtain all the equipment required to perform the test. The test had to be suspended

. temporarily while the operator went to the control-voom to obtain the digital voltmeter.

.q While the surveillance was eventually performed satisfactorily, it i

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appeared the-operator was not well prepared to perform the

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. surveillance.

During the performance of OST 2.24.4, the following discrepancy was iden-

tified:

Unit 2 Technical Specification 4.7.1.2 and OST 2.24.4 requires that constant communications be established and maintained between the

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control room and the auxiliary feed pump room while the normal pump i

discharge valve is closed during-the surveillance test.

However,

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contrary to the above, constant communication was not being main-l tained while the normal discharge valve of the Steam Driven Auxiliary Feedpump was closed. This is a violation (50-412/89-18-01).

Constant communications had been established using the "Gaitronics" five channel phone pager system with operator keeping the. handset to his ear at the start of the surveillance. During the test, the-local ~

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communicator (constant) left his post to assist an operator inspect-l ing seal leakage and temperature for acceptable performance. The local communicator obtained permission from the control room communi-cator prior to leaving his. post. The noise levels in the auxiliary

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l feed pump room from the running steam driven auxiliary feedpump was s,uch that the local communicator could not have heard the page from the control room communicator if there had been a need to open the

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pumps discharge valve.

t On two previous occasions the inspector identified communication weak-nesses during the auxiliary feed pump testing. Curing surveillance test-ing of a Unit 2 auxiliary feedpump, direct communications were not main-tained during the majority of the test with the local communicator relying on a page from the control room (see Inspection Report 50-334/88-25;

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50-412/88-14). On another' occasion, the inspector attributed an inadver -

tent. start of a Unit-1 auxiliary feed pump due to lack of constant com-munications while testing another Unit I auxiliary feedpump (see IR 50-334/88-28; 50-412/88-22).

As indicated above, further attention is required to ensure that constant communications are properly maintained during auxiliary feedpump testing.

6.

Maintenance The inspector reviewed selected maintenance activities to assure that:

the activity did not violate Technical Specification Limiting

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Conditions for Operation and that redundant components were operable; required approvals and releases had been obtained prior to

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commencing work; procedures used for the task were adequate and work was within

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the skills of the trade; activities were accomplished by qualified personnel;

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where necessary, radiological and fire preventive controls were

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adequate and implemented; QC hold points were established where required, and observed;

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equipment was properly tested and returned to service.

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Maintenance activities reviewed included:

MWR 883339 unpack, measure and repack valves in accordance

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with Design Change Package 822 MSP 36.35-M No. 2 Emergency Diesel Generator Thermostatic

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Valve Replacement MSP 36.34-M No. 2 Emergency Diesel Generator Lube Oil

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Circulating Pump Replacement MSP 36.36-M No. 2 Emergency Diesel Generator Filter and

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Strainer Maintenance No deficiencies were identified.

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E7, Excessive Overtime During Unit 2 Refueling Outage The control of overtime (OT) was one of the regulatory issues contained in-NUREG-0737, "Clarif.ication of TMI Action Plan Requirements", issued in tjovember,1930(ItemI.A.1.3).

Further regulatory review led to modifi-cation of the requirements as described in Generic letters 82-12 and 83-14. The numerical limits on OT hours were captured in Section 6.2.2 (f), the Unit 2 Technical Specifications as follows:

Administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform safety-related functions; senior reactor operators, reactor operators, radiation control technicians, auxiliary operators, meter and control repairman, and all personnel actually performing work on safety related equipment.

The objective shall be to have operating personnel work a normal 8-hour day, 40-hour week while the plant is operating.

However, in-the event that unforeseen problems require substantial amounts of over-time to be used, or during extended periods of shutdown for refuel-ing, major maintenance or major plant modifications, on a temporary basis, the following_ guidelines shall be followed:

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An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight, excluding shift turnover time, b.

An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period, all excluding shift turnover time,

-A break of at least eig't hours should be allowed between work c.

n periods, including shift turnover time.

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Except during extended shutdown periods, the use of overtime should be considered on an individual. basis and not'for the entire staf f on a shif t.

Any deviation from the above guidelines shall be authorized by the plant Manager or predesignated alternate, or higher levels of manage-ment.

Authorized deviations to the working hour guidelines shall be documented and available for NRC review.

Contrary to the above, three instances were identified in which licensed operators exceeded the Technical Specification. limits during the Unit 2 first refueling outage.

This is a violation (50-412/89-18-02).

The Technical Specifications dif fer slightly from the Generic Letters in two places. Generic Letter 82-12 states:

" Recognizing that very unusual circumstances may arise requiring deviation from the above guidelines, such deviation shall be authorized by the plant manager or his deputy, or

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i-higher' levels of management" (emphasis added), Generic Letter 83-14 states that the OT limits applying to " key maintenance personnel" are defined as:

"those personnel who are responsible for the correct performance of maintenance, repair, modification or calibration of safety-related structures, systems or components, and who are personnel performing or immediately supervising the performance of such activities" (emphasis added).

The clear regulatory position is that personnel should normally work an 8-hour day, 40-hour week, that OT should be controlled within prescribed limits, and that senior management should authorize exceptions only for very unusual circumstances.

The licensee implements the OT requirements in Nuclear Grcup Directive 19, "Use of Overtime" (NGD-19), which extends-the limits to all personnel in the onsite Nuclear Group. Numerous instances were_ identified in which individuals not covered by the Techni-cal Specifications _ violated the limits of NGD-19 during the Unit 2 refuel-ing outage.

In many other cases, OT beyond the Technical Specification limits was authorized.by managers as allowed by NGD-19, but not consistent with the " deputy plant manager" guidance of Generic Letter 83-14.

As documented in a previous Inspection Report (50-334/89-04; 50-412/89-04),

the Plant' Manager was not aware that OT was being authorized in excess of the Technical Specification limits.

This lack of knowledge and the wide-spread use of OT above NGD-19 limits is indicative of a loss of oversight

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by senior management.

In the area of maintenance during the outage, the site maintenance director authorized consecutive 12-hour days for seven day periods to support outage work.

In some cases, as many as four consecutive week; of seven 12-hour days were authorized for the same individual. The use of OT beyond the Technical Specification limits was widespread, pervasive, and did not meet the "very unusual circumstances" test of Generic Letter 82-12 nor did it meet the " unforeseen problems" criteria of the Technical Specifications.

Supervisors of work on safety related equipment are identified in Generic Letter 83-14 as being under the OT limits, but the Technical Specifica-tions do not contain those limits.

The supervisors are instead covered by NGD-19 administrative limits. The use of large amounts of OT by super-visors was also widespread with some individuals working six or more weeks of seven 12-hour days. At least one supervisor worked nine consecutive weeks of seven 12-hour days.

The effect of first line supervisor fatigue was clearly demonstrated because it was the latter supervisor's wrong decisions which contributed to two different plant events (a reactor trip in Mode 3 and a safety injection while shut down). These events show the importance of including supervisors under the OT limits and effect of the loss of management

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oversight.

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?RCS. ; Lapsesiin" attention :to detail were contributors to.those errors.

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both 'as aLworker and as a - supervi.sor. The' widespread use=of'OT.may-

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refueling; outage.

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8. - ~-Unit'1-Thimbl'e Tube Excessive Wear

20n' October 10,c1989, the 1icensee notified the NRC:that based on the=

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-results;of eddy current testing,_ eight Unit 1 incore neutron monitoring:

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. system thimble: tubos had wall thickness wear indications greater' than;50?J.

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1The licensee was monitoring thimble tube integrity -in response to NRC C i

' Bulletin.No. 88-09 which-described concerns dealing with thimble tube

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thinning-in Westingho.use reactors.

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- The:incore neutron ' monitoring Lsystem thimble tubes extend from a : 10 path.

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itransferJdevice, through the seal table, through the bottom;of the reactor

vessel,and into selected fuel assemblies.

The thimble tubes are sealed at:

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the reactor end, but are open at the~ 10 path transfer device to allow the'

insertionJof an incore neutron _ detector during flux-mapping evolutions.

18y dssign,_ each thimble tube, over most-of-its length, serves as a. portion-

'lof-the reactor coolant system (RCS) pressure boundary. Thus, wear of the-

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jthimble tubesiresults in degradation of the.RCS pressure: boundary and can also createra potentially nonisolable leak of reactor coolant.

' The = licensee's: acceptance criteria for -thimble tube. wear is that any. tube exhibiting greater than 50?; material? wear loss, the tube will be removed

@N-fromis~ervice..'This was based on an American' Society of Mechanical

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Engineers 1(ASME) code, and a' finite elementi structural analysis _ which:

? concluded a thimble;t_ubeJcould ' experience 60?J material _ wear loss and still-JassureLoperation with-an external pressure of 2250-psig. EA_10*J~ allowance (wastused < to account-for inspection methodology and wear scar geometry

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Euncertainties.

In1 addition, all tubes which. exhibit indications greater

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60%.through wall indication during the next~ fuel = cycle.

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Based.on the above acceptance criteria, the licensee ' intended to cap the

eight thimble tubes which exhibited greater greater than_50?J material

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? wear. 'One tube had been previously capped during the sixth refueling-

R outage.

In addition, nine other thimble tubes will be axially reposi-

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tioned'since:it-was predicted that these tubes would have wall loss

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indications greater than 60?; during the next 18 month core cycle.

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The remaining 32 thimble' tubes, out of a total population of 50, had either no wear indications or projected material wear loss that would exceed the 60% limit during the next fuel cycle.

Unit 1 Technical Specification 3.3.3.2 requires that at least 75% of the thimble tubes be operable and at a minimum there must be two thimble tubes operable per core quadrant. With the 41_ tubes still operable, these requirements are met.

The inspectors did not identify any deficiencies with the licensee actions and will continue to follow licensee activities concerning thimble tube wear.

9.

Leaking Check Valves in Unit 2 Auxiliary Feedwater System Leaking check valves in the Unit 2 Auxiliary Feedwater (AFW) System caused elevated piping temperatures in the Safeguards Building. The high tempera-tures were detected on September 20 and ranged from 250 F to 328 F.

The initial report was from an alert security guard who noticed a strange odor (possibly from the-baking paint on the AFW lines) during a tour and who reported this to the control room.

Responding to the guard's notifica-tion, operators noted the very hot AFW lines (with discolored paint).

Two check valves in the line to the B Steam Generator (SG) apparently failed to reseat following a surveillance test the previous day.

Diffe-rential pressure between the B and C main feedwater lines created a flow path back through the leaking check valves in the B AFW header and into the header to the C SG.

The discharge check valves at the AFW pumps did not leak so the pumps remained at ambient temperature and were therefore not exposed to potential steam binding. Operator shift tours included checking the pump casings for elevated temperature but not the delivery headers downstream.

Operators closed a valve to stop the back flow and later flushed the piping by running one AFW pump. The flushing was done efter temperatures dropped below 200 F due to concern over possible water hammer at the higher temperatures.

Piping temperatures remained at ambient after the pump was secured indicating that the AFW check valves had reseated.

The Unit 2 Safeguards Building contains much of the ECCS equipment

. including the containment quench spray pumps, low head safety injection pumps, and containment recirculation spray pumps.

It also contains the AFW pumps, the hydrogen recombiners and the chemical injection pumps.

These componer.ts have environmental qualification (EQ) limits associated with the 120 F and 90% humidity building design basis environment.

The possibility of a high energy line break (HELB) was reviewed during the licensing process and also during on site inspections (see Inspection Reports 50-412/86-31 and 87-02).

The Safeguards Building and the equip-

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ofJan_ unanticipated HELB mechanism has potentially:significant s'afety.

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The inspector conducted an' independent review of. the events, system design.

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and corrective actions.

The' piping involved is rated for full' secondary-1 pressure,so no over pressure conditions wereJinvolved.

Tho' temperature rise'was caused by the' flow from one main feedwater header to another-

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through= the AFW lines induced by the small differential pressure between -

the headersc A leak to atmosphere or a full.HELB would have created much larger. differential pressures and would-have tended to reseat the leaking -

check valves.10nce fully seated, the check valves would stop or greatly

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11mit' additional-release of' feedwater to the Safeguards Building. These check valves (nine total)-are Containment. Isolation Valves and were tested satisfactorily within the.24 month Technical Specification interval.

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licensee reviewed the components exposed to the elevated temperatures and concluded that no damage should have occurred. -The inspector. discussed

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the evaluation with the engineers involved and had.no questions.

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linspector will continue to monitor licensee corrective actions.

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'10. Unit'l Safeg'uards Building Ventilation In a previous: inspection = report, questions were' raised concerning the

' adequacy of-the ventilation of the Unit 1 Safeguards Building (Unresolved Item 50-334/89-04-02). Cooling for the safety related-equipment-is

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provided'by-the Supplementary Leak Collection and Release (SLCR) system.

When room temperatures reach a. predetermined setpoint, dampers open to-

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pull outside air in-and exhaust the circulated air to the outside.

One such room includes-the three-AFW pumps (two electric and one steam driven)

and both quench spray pumps..The-inspector reviewed the design and

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environmental qualification (EQ) calculations and noted that only half the component's heat. loads were assumed'to be running. The EQ maximum-temperature was 120 F but the damper opening setpoint was 130 F.

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these-concerns were brought to-the licensee's attention in' February, 1989,-

.the: licensee conducted an evaluation of the TLCR system adequacy.

Initial calculations. assumed 85 F initial room conditions. The inspector noted that.this-assumption 'requ' ired the nonsafety air conditioner to be working.

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. temperature rise (in February) and high humidity that caused the inspector

to review the SLCR and EQ calculations. The inspector requested the 1.icensee to review the accident calculations without the non-safety, non-

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administrative 1y controlled air conditioning system available.

I The requested calculations assumed a 90 F outside air temperature and

s indicated a. stable room temperature of about 114 F.

Without the cooler

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. room surfaces for passive heat sinks, the analysis showed a post accident l

temperature peak of about 140 F with temperature EQ limits exceeded for

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between two.and three hours.

The licensee calculations treated the steam i

drive AFW pump as an insulated pipe; this assumed zero steam leakage from

packing and drains.

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t After the re-analysis, the licensee committed to change the SLCR setpoint to 110 F, below the 120 F EQ temperature limit. The priority for main-(

tenance or repair of the Safeguards Building air conditioner will also be reviewed. -This item remains unresolved pending completion of the SLCR setpoint change, review of the priority and controls involving the Safe-guards Building air conditioner, and review of the steam driven AFW tests (for heat release).

11.

Inoffice Review of Licensee Event Reports (LERs)

The inspector reviewed LERs submitted to the NRC Region I Office to verify that the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective action. -The inspector

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. determined whether further information was required from the licensee, whether generic implications were indicated and whether the event warranted onsite followup.

The following LERs were reviewed:

Unit 1:

LER 89-008-00 Reactor Trip and Feedwater Isolation During Shutdown LER 89-009-00 Engineered Safety Features Actuation-Ventilation Realignment LER 89-010-00 Unqualified Fire Dampers Unit 2:

LER 89-024-00 Steam Generator Blowdown Containment Isolation Valves Closure - ESF Actuation LER 89-025-00 Auxiliary Feedwater Intra-System Recirculation-Unanalyzed Condition.

The above LERS were reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022. Generally, the LERs were found to be of high quality with good documentation of event analyses, root cause determinations and corrective actions.

12. Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations. No new unresolved items were identified in this inspection report.

13. Meetings Periodic meetings were held with senior facility management 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 October 25, 1989.

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